{"document":{"slug":"filing-er26-3552-miso-zgia-attachment-1","title":"Tab A - Marked Tariff Sheets.pdf","issued":"2026-08-18","accession":"20260818-5152","docket":"ER26-3552-000","group":"MISO filings","filer":"Midcontinent Independent System Operator, Inc.","kind":"attachment","file":"sources/originals/20260818-5152_02.pdf","url":"https://elibrary.ferc.gov/eLibrary/filelist?accession_Number=20260818-5152","parent":"filing-er26-3552-miso-zgia","sha256":"a3edcadd726fb6efea53b5f67704a6e7a0955fba7d4bbea6bd791fbd1e33f6c9","pages":772,"tokens":211131,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":5,"text":"Tab A – Marked Tariff Sheets"},{"page":2,"startToken":5,"endToken":286,"text":"MISO\n1.F\nFERC Electric Tariff\nDefinitions - F\nMODULES\n65.0.0, 66.0.0\nEffective On: October 18, 2026\nFacility:  An electric generating unit or an electric generating station composed of one or more \ncontiguous electric generating units aggregated at a single geographical site. \nFacilities Study:  An engineering study conducted by the Transmission Provider or ITC in \ncollaboration with the affected Transmission Owner(s) and ITC Participant(s) to \ndetermine the required modifications to the Transmission System, including the cost and \nscheduled completion date for such modifications, that will be required to provide the \nrequested Transmission Service.  The Transmission Provider shall have the final \ndetermination and ultimate responsibility for any such studies.  Facilities Studies for any \ntransmission facilities not under the operational control of the Transmission Provider \nshall be performed by the Transmission Owner, or ITC, or any entity it designates to \nperform the studies.  \nFast Ramping Resource:  A Generation Resource that:  (1) meets the qualification criteria of \nhaving a: (i) ramp rate greater than eighty (80) MW per minute; (ii) Fast Ramping \nResource Performance Score that meets or exceeds the Fast Ramping Resource \nPerformance Threshold when responding to regulation signals in Fast Ramping Resource \nPerformance Tests; and (iii) duration greater than 20 minutes or more for Use Limited \nResources; and (2) as such, will receive a fast changing regulation signal for a market \ninterval for which it has been offered.\nFast Ramping Resource Historical Performance Score:  A performance score calculated on a \nRegulation Qualified Resource as the ratio of its Fast Ramping Resource Passed Intervals \nto its Fast Ramping Resource Valid Intervals in the Dispatch Intervals in all previous \nHours when it was offered as a Fast Ramping Resource."},{"page":3,"startToken":286,"endToken":580,"text":"MISO\n1.F\nFERC Electric Tariff\nDefinitions - F\nMODULES\n65.0.0, 66.0.0\nEffective On: October 18, 2026\nFast Ramping Resource Passed Interval:  An AGC signal interval, within a Fast Ramping \nResource Performance Test, that is considered passed by a Resource offered as a Fast \nRamping Resource for a particular Hour, during Regulating Reserve Deployment for the \nAGC signal interval if the MW response of the Resource for the Setpoint Instruction, \nadjusted for the communication delay, is within the tolerance range (i.e., +/- 0.25 MW if \nthe delta change is 0.8 MW or less, and +/- 30 percent if the delta change is greater than \n0.8 MW).\nFast Ramping Resource Performance Score:  A score calculated during a Fast Ramping \nResource Performance Test.\nFast Ramping Resource Performance Test:  A test performed in real time to evaluate the \ncapability of a Regulation Qualified Resource that is offered as a Fast Ramping Resource \nto perform reliably as a Fast Ramping Resource while deploying Regulating Reserve.  \nThe test will be performed on such a Regulation Qualified Resource that is receiving \neither fast or regular regulation signals.  At the start of each hourly interval, the Resource \nwill be assigned an initial score that is the higher of the Fast Ramping Resource \nHistorical Performance Score or the Fast Ramping Resource Performance Threshold.  \nWithin each hourly interval, at the end of each Dispatch Interval, a new adjustment to the \ninitial score will be calculated as the ratio of Fast Ramping Resource Passed Intervals to \nFast Ramping Resource Valid Intervals in the current and all previous Dispatch Intervals \nin the particular hourly interval. \nFast Ramping Resource Performance Threshold:  A minimum Fast Ramping Resource \nPerformance Score of seventy percent (70%) that a Resource is required to meet to be"},{"page":4,"startToken":580,"endToken":873,"text":"MISO\n1.F\nFERC Electric Tariff\nDefinitions - F\nMODULES\n65.0.0, 66.0.0\nEffective On: October 18, 2026\nqualified as a Fast Ramping Resource.\nFast Ramping Resource Valid Interval:  An AGC signal interval is considered valid for a \nResource undergoing a Fast Ramping Resource Performance Test, during its Regulating \nReserve Deployment for an AGC signal interval, during which a new Setpoint Instruction \nis calculated that changes by a threshold MW of at least 0.1 MW from the previous \nSetpoint Instruction.\nFast Start Resource: An online Generation Resource that is started, synchronized and injects \nEnergy, or a Demand Response Resource that reduces its Energy consumption, within \nsixty (60) minutes of being notified and that has a minimum run time of one hour or less \nand that will participate in setting price as described in the process in Schedule 29A of \nthis Tariff.  A Fast Start Resource does not include fuel-limited resources such as pumped \nstorage, Electric Storage Resources, run-of-river hydro, and wind resources.  Offline \nGeneration Resources will not participate in setting price as described in the process in \nSchedule 29A of this Tariff. \nFast Start Resource All-In Energy Offer:  The sum of an online Fast Start Resource’s Energy \nOffer, its amortized No Load Offer and, during its Minimum Run Time, its amortized \nStart up Offer; provided, that, in the case of a Demand Response Resource – Type I, it \nshall be the sum of the Energy Offer, its amortized Hourly Curtailment Offer and its \namortized Shut-Down Offer over its minimum interruption duration.\nFast Start Resource All-In Reference Level:  The sum of an online Fast Start Resource’s \nEnergy Reference Level, its amortized No Load Reference Level and, during its \nMinimum Run Time, its amortized Start up Reference Level; provided, that, in the case"},{"page":5,"startToken":873,"endToken":1162,"text":"MISO\n1.F\nFERC Electric Tariff\nDefinitions - F\nMODULES\n65.0.0, 66.0.0\nEffective On: October 18, 2026\nof a Demand Response Resource – Type I, it shall be the sum of the Energy Reference \nLevel, its amortized Hourly Curtailment Offer Reference Level and its amortized Shut-\nDown Offer Reference Level over its minimum interruption duration.\nFeasibility Upgrade Process:  The procedure that enables additional ARRs to be allocated based \nupon Network Upgrades as part of the MTEP process.\nFederal Energy Regulatory Commission (FERC) Uniform System of Accounts:  The \nCommission’s Uniform System of Accounts in the Code of Federal Regulations, Title 18, \nConservation of Power and Water Resources, Parts 1-399, pursuant to which electric \npublic utilities, licensees and other companies within FERC jurisdiction are required to \nmaintain their books and records.\nFederal Power Marketing Agency:  Any agency or instrumentality of the United States (other \nthan the Tennessee Valley Authority), which sells electric Energy.\nFERC Market Rules:  The market behavior rules and the prohibition against electricity Energy \nmarket manipulation codified by the Commission in its Rules and Regulations at 18 CFR \n§ 1c.2 and 35.37, respectively; and any related proscriptions or any successor rules that \nthe Commission from time to time may issue, approve or otherwise establish.\nFile Transfer Protocol (FTP):  The standardized File Transfer Protocol for data transfer.\nFinal Planning Reserve Margin Requirement (Final PRMR):  For LSEs not selecting the \nReliability Based Demand Curve Opt Out, the PRMR established as a result of the PRA \nclearing using RBDCs.  For LSEs selecting the RBDC Opt Out, Final PRMR is based on \nthe sum of the applicable PRM plus the applicable RBDC Opt Out Adder.  LSEs under \nstate jurisdiction where the state has overridden the PRM established by the Transmission"},{"page":6,"startToken":1162,"endToken":1426,"text":"MISO\n1.F\nFERC Electric Tariff\nDefinitions - F\nMODULES\n65.0.0, 66.0.0\nEffective On: October 18, 2026\nProvider will have a Final PRMR based on the planning reserve margin established by \nthe state.\nFinancial Schedule:  A financial arrangement between two Market Participants designating a \nSource Point, Sink Point and Delivery Point establishing the obligations of the buyer and \nseller for the payment of Cost of Congestion and Cost of Losses.  The Transmission \nProvider is not the Energy Market Counterparty to the sale of Energy under a Financial \nSchedule transaction and collects and disburses the Transmission Usage Charge as agent \nfor the parties to the Financial Schedule.\nFinancial Security:  A Cash Deposit or Irrevocable Letter of Credit in an amount and form \ndetermined by and acceptable to Transmission Provider, provided by an Applicant and/or \nTariff Customer to Transmission Provider as security.  \nFinancial Transmission Right (FTR):  A financial instrument that entitles the holder to receive \ncompensation for or requires the holder to pay certain congestion related transmission \ncharges that arise when the Transmission System is congested and differences in \nMarginal Congestion Components of Day-Ahead Ex Post LMPs result.\nFirm Flow:  The estimated impacts of firm transactions under network and point-to-point \nTransmission Service on a particular Coordinated Flowgate.\nFirm Point-To-Point Transmission Service:  Transmission Service under this Tariff that is \nreserved and/or scheduled between specified Points of Receipt and Points of Delivery \npursuant to Module B of this Tariff. \nFirm Service Level:  The MW portion of the total demand of a Demand Resource that is not \nsubject to curtailment as a Demand Resource."},{"page":7,"startToken":1426,"endToken":1712,"text":"MISO\n1.F\nFERC Electric Tariff\nDefinitions - F\nMODULES\n65.0.0, 66.0.0\nEffective On: October 18, 2026\nFirst Planning Area:  The Transmission System of the Transmission Provider Region as it \nexisted immediately before the effective date of the Second Planning Area.  The First \nPlanning Area may be modified from time to time by:  (1) the addition of any \ntransmission facilities in the Midwest portion of the United States (i.e., Illinois, Indiana, \nIowa, Kentucky, Michigan, Minnesota, Missouri, Montana, North Dakota, Ohio, South \nDakota, and Wisconsin) where transmission facilities not under the functional control of \nthe Transmission Provider are subsequently conveyed to the functional control of the \nTransmission Provider to be used to provide Transmission Service under Module B of the \nTariff; or (2) the withdrawal from the Transmission Provider Region of a Member \nlocated in the First Planning Area.\nFixed Carrying Charge:  An annual charge calculated by taking the cost of service carrying \ncharge elements expressed as a percent multiplied by the Transmission Owner or ITC’s \nrate base.  The carrying charge elements include: operations and maintenance, \ndepreciation expense, other taxes, return, and income taxes. \nFixed Demand Bid:  A request to purchase a specified MWh quantity of Energy, at specified \nlocations in the Transmission Provider Region, during specific Hours of the next \nOperating Day submitted to the Day-Ahead Energy and Operating Reserve Market.  \nDemand Bids may only be submitted by a Market Participant that is itself a Load Serving \nEntity (LSE) or is purchasing Energy to serve an LSE.\nFixed Interchange Schedule:  An Interchange Schedule consisting of a fixed, non-Dispatchable \namount, used in the Energy and Operating Reserve Markets.\nFixed Resource Adequacy Plan (FRAP):  A plan submitted by an LSE through the MECT to"},{"page":8,"startToken":1712,"endToken":2003,"text":"MISO\n1.F\nFERC Electric Tariff\nDefinitions - F\nMODULES\n65.0.0, 66.0.0\nEffective On: October 18, 2026\nthe Transmission Provider that is approved by the Transmission Provider which \ndemonstrates that the LSE has sufficient ZRCs to meet all or part of its Initial PRMR for \none or more LRZs in a Season.\nFlowgate:  A representative modeling of a facility or group of facilities that may act as a \nconstraint to power transfer on the Bulk Electric System.\nFlowgate Rating:  The Total Transfer Capability of a Flowgate.\nForced Outage or Generator Forced Outage:  An immediate reduction in output, Capacity or \nremoval from service, in whole or in part, of a Generation Resource by reason of an \nEmergency or threatened Emergency, unanticipated failure, inability to return on \nschedule from a Planned Transmission Outage, or other cause beyond the control of the \nowner or operator of the facility, as specified in the relevant portions of the BPM for \nOutage Operations.  A reduction in output or removal from service of a Generation \nResource in response to changes in Energy Market conditions does not constitute a \nGenerator Forced Outage.\nForecast LSE Requirement:  The forecasted Demand including the effect of all losses for an \nLSE at a CPNode for a Month less the Full Responsibility Purchases plus the Full \nResponsibility Sales and minus the Demand Resources that were registered to net for a \ngiven Month all at the same CPNode.\nForecast Maximum Limit:  For a Dispatchable Intermittent Resource, The the maximum MW \nlevel at which a Dispatchable Intermittentthe Resource is forecasted to operate.  In \naddition, for a ZG Resource participating as a DIR, the maximum MW level at which a \nResource may operate shall be less than the Demand of the Resource’s ZG Associated"},{"page":9,"startToken":2003,"endToken":2264,"text":"MISO\n1.F\nFERC Electric Tariff\nDefinitions - F\nMODULES\n65.0.0, 66.0.0\nEffective On: October 18, 2026\nLoads.  \nForeign Guarantor:  A Guarantor that is organized under the laws of a jurisdiction outside of \nthe United States or Canada.\nForeign Guaranty:  A Corporate Guaranty accepted from a Guarantor that is organized under \nthe laws of a jurisdiction outside of the United States or Canada.\nForward Reliability Assessment Commitment (FRAC):  A RAC process conducted up to seven \n(7) days prior to, and before the closing of, the Day-Ahead Energy and Operating \nReserve Market.\nFTR and ARR Transactions Cleared But Not Yet Settled:  This service category is a component \nof the FTR Potential Exposure.  The FTR and ARR Transactions Cleared But Not Yet \nSettled are calculated on a monthly basis.  If the net monthly value is positive, it is \nincluded in the FTR Potential Exposure calculation.  If the net monthly value is negative, \nthe value is not included in the FTR Potential Exposure calculation. \nFTR Auction:  An auction conducted periodically through which the Transmission Provider, \nsubject to the Simultaneous Feasibility Test:  (i) awards FTRs of various durations and \n(ii) facilitates the selling of existing FTRs between Market Participants.\nFTR Auction Credit Allocation:  \nThe amount of the Applicant’s and/or Tariff Customer’s \nTotal Credit Limit allocated to FTR Auctions.\nFTR Auction Credit Exposure:  Exposure to non-payment associated with the amount of the \nApplicant’s and/or Tariff Customer’s FTR Bids and Offers submitted in the auction. \nFTR Auction Participant:  A Market Participant that participates in an FTR Auction \nadministered by the Transmission Provider."},{"page":10,"startToken":2264,"endToken":2539,"text":"MISO\n1.F\nFERC Electric Tariff\nDefinitions - F\nMODULES\n65.0.0, 66.0.0\nEffective On: October 18, 2026\nFTR Auction Settled Transactions Exposure:  The potential exposure to non-payment \nassociated with FTR Auction transactions that have been cleared and settled.\nFTR Bid:  A bid to purchase an FTR through an FTR Auction.\nFTR Bidder:  A Market Participant submitting an FTR Bid.\nFTR Delivery Point:  The transaction Delivery Point specified in a receipt point to delivery point \nFTR.\nFTR Holder:  A Market Participant that owns one (1) or more FTRs.\nFTR MCP:  The price at which a set of Comparable FTRs are sold through an FTR Auction.\nFTR Obligation:  A receipt point to delivery point FTR that imposes a financial obligation on \nthe FTR Holder if congestion exists in the direction from the FTR Delivery Point to the \nFTR Receipt Point. \nFTR Offer:  An offer to sell an FTR through an FTR Auction.\nFTR Offeror:  A Market Participant submitting an FTR Offer.\nFTR Option:  A receipt point to delivery point FTR that imposes no financial obligations on the \nFTR Holder under any conditions.\nFTR Period:  The period(s) of time on a given Day during which an FTR is in effect (On Peak, \nOff Peak, or full Day time period(s)).\nFTR Potential Exposure:  The sum of exposure values as defined in Section V.B of Attachment \nL to this Tariff.  Included are all FTR related charge types.\nFTR Potential Exposure Violation:  A condition that exists whenever a Tariff Customer’s FTR \nPotential Exposure plus the larger of the FTR Auction Credit Allocation or FTR Auction \nCredit Exposure exceeds its Financial Security less its alternative capitalization"},{"page":11,"startToken":2539,"endToken":2834,"text":"MISO\n1.F\nFERC Electric Tariff\nDefinitions - F\nMODULES\n65.0.0, 66.0.0\nEffective On: October 18, 2026\nrequirement as further defined in Section V.C of Attachment L to this Tariff.\nFTR Quantity:  The quantity in MW specified in an FTR.\nFTR Receipt Point:  The transaction receipt point specified in an FTR.\nFTR Transactions Cleared But Not Yet Settled:  The value of the FTRs based on the clearing \nprice(s) established as a result of an FTR Auction which has been cleared, but has not yet \nbeen settled.\nFuel Cost Uncertainty Adder:  An amount determined by the Independent Market Monitor, not \nto exceed $100 per MWh, that is included in the Reference Level determination to \naccount for fuel cost uncertainty when the resulting Reference Level exceeds $1,000 per \nMWh.\nFull Responsibility Purchases:  The total of all purchases coincident with the expected Demand \nof the LSE under which the seller is contractually obligated to deliver Energy plus \nreserves to the purchaser, expressed in MWs for the hour. Reserve provision by the seller \nas a percent must meet or exceed the PRM obligation for the purchasing LSE.  Up Ramp \nCapability and Down Ramp Capability by the seller as a percent must meet or exceed the \nPRM obligation for the purchasing LSE.  Short-Term Reserve provision by the seller as a \npercent must meet or exceed the PRM obligation for the purchasing LSE.  Each \npurchaser and seller must agree on which of their transactions are to be reported under \nthis heading.\nFull Responsibility Sales:  The total of all sales coincident with the expected Demand of the \nLSE under which the seller is contractually obligated to deliver Energy plus reserves to \nthe purchaser, expressed in MWs for the hour. Reserve provision by the seller as a"},{"page":12,"startToken":2834,"endToken":2925,"text":"MISO\n1.F\nFERC Electric Tariff\nDefinitions - F\nMODULES\n65.0.0, 66.0.0\nEffective On: October 18, 2026\npercent must meet or exceed the PRM obligation for the purchasing LSE.  Up Ramp \nCapability and Down Ramp Capability by the seller as a percent must meet or exceed the \nPRM obligation for the purchasing LSE.  Short-Term Reserve provision by the seller as a \npercent must meet or exceed the PRM obligation for the purchasing LSE.  Each \npurchaser and seller must agree on which of their transactions are to be reported."},{"page":13,"startToken":2925,"endToken":3204,"text":"MISO \n1.H\nFERC Electric Tariff \nDefinitions - H\nMODULES \n62.0.0, 63.0.0\nEffective On: October 18, 2026\nHeadroom:  For all Resources committed by the Transmission Provider in any real-time RAC \nprocesses or the LAC process conducted for the Operating Day, the difference between \n(i) the real-time Economic Maximum Dispatch and (ii) the sum of the Real-Time (a) \nDispatch Target for Energy, (b) Dispatch Target for Regulating Reserve, (c) Dispatch \nTarget for Spinning Reserve, (d) Dispatch Target for Supplemental Reserve, and (e) \nDispatch Target for Short-Term Reserve. \nHigh Utilization Factor Unit (HUFU) Reserved Source Point (RSP):  An RSP that does not \nqualify for inclusion in the BRSS per section 43.2.4.a.i.(b) but has a RSP Utilization \nFactor of seventy percent (70%) or greater. \nHistoric Unit Consideration: A right to receive excess Planning Resource Auction revenue \nbased on qualification described in Section 69A.7.7(a). \nHour:  A sixty (60) minute clock hour interval commencing the first second of each clock hour. \nHot-to-Cold Time:  The number of hours that must elapse between the time a Generation \nResource, Demand Response Resource – Type II, or Electric Storage Resource is \ndesynchronized and the time at which a cold Start-Up Offer would apply.   \nHot-to-Intermediate Time:  The number of hours that must elapse between the time a \nGeneration Resource, Demand Response Resource – Type II, or Electric Storage \nResource is desynchronized and the time at which an intermediate Start-Up Offer would \napply.  \nHourly Bi-Directional Ramp Rate:  The MW/minute rate at which a Generation Resource, an \nExternal Asynchronous Resource, or Demand Response Resource - Type II can respond \nto either increasing or decreasing Setpoint Instructions that may be submitted to override"},{"page":14,"startToken":3204,"endToken":3489,"text":"MISO \n1.H\nFERC Electric Tariff \nDefinitions - H\nMODULES \n62.0.0, 63.0.0\nEffective On: October 18, 2026\nthe default value submitted during the asset registration process. \nHourly Charge Ramp Rate:  The MW/minute response rate for an Electric Storage Resource \nmoving from zero output to its Hourly Economic Minimum Charge Limit and/or from the \nHourly Economic Minimum Charge Limit to zero output that is utilized in the clearing of \nthe Day-Ahead Energy and Operating Reserve Market and all Reliability Assessment \nCommitment processes, and in responding to either increasing or decreasing Setpoint \nInstructions between zero and the Hourly Economic Minimum Charge Limit that may be \nsubmitted to override the default value submitted during the asset registration process. \nHourly Curtailment Offer:  The compensation request, in dollars per Hour, in a Demand \nResponse Resource-Type I Offer by a Market Participant representing the fees required \nfor operating a Demand Response Resource Type I in an interrupted state. \nHourly Discharge Ramp Rate:  The MW/minute response rate for an Electric Storage Resource \nmoving from zero output to its Hourly Economic Maximum Discharge Limit and/or from \nthe Hourly Economic Maximum Discharge Limit to zero output that is utilized in the \nclearing of the Day-Ahead Energy and Operating Reserve Market and all Reliability \nAssessment Commitment processes, and in responding to either increasing or decreasing \nSetpoint Instructions between zero and the Hourly Economic Maximum Discharge Limit \nthat may be submitted to override the default value submitted during the asset registration \nprocess. \nHourly Economic Maximum Limit:  The maximum MW level at which a Generation Resource, \nDemand Response Resource Type II, or External Asynchronous Resource may operate \nunder normal system conditions that may be submitted to override the default value"},{"page":15,"startToken":3489,"endToken":3769,"text":"MISO \n1.H\nFERC Electric Tariff \nDefinitions - H\nMODULES \n62.0.0, 63.0.0\nEffective On: October 18, 2026\nsubmitted during the asset registration process.  In addition, for a ZG Resource \nparticipating as a Generation Resource, the maximum MW level at which the Resource \nmay operate under normal system conditions shall be less than the Demand of the \nResource’s ZG Associated Loads. \nHourly Economic Maximum Charge Limit: The maximum withdrawal MW level at which an \nElectric Storage Resource may operate under normal system conditions that may be \nsubmitted to override the default value submitted during the asset registration process. \nHourly Economic Maximum Discharge Limit: The maximum injection MW level at which an \nElectric Storage Resource may operate under normal system conditions that may be \nsubmitted to override the default value submitted during the asset registration process.  In \naddition, for a ZG Resource participating as an Electric Storage Resource, the maximum \nMW level at which the Resource may operate under normal system conditions shall be \nless than the Demand of the Resource’s ZG Associated Loads. \nHourly Economic Minimum Limit:  The minimum MW level at which a Generation Resource, \nDemand Response Resource Type II, or External Asynchronous Resource may operate \nunder normal system conditions that may be submitted to override the default value \nsubmitted during the asset registration process.   \nHourly Economic Minimum Charge Limit: The minimum withdrawal MW level at which an \nElectric Storage Resource may operate under normal system conditions that may be \nsubmitted to override the default value submitted during the asset registration process. \nHourly Economic Minimum Discharge Limit: The minimum injection MW level at which an \nElectric Storage Resource may operate under normal system conditions that may be"},{"page":16,"startToken":3769,"endToken":4055,"text":"MISO \n1.H\nFERC Electric Tariff \nDefinitions - H\nMODULES \n62.0.0, 63.0.0\nEffective On: October 18, 2026\nsubmitted to override the default value submitted during the asset registration process. \nHourly Electric Storage Resource Efficiency Factor: An operating characteristic of an Electric \nStorage Resource that is the amount of increase in Energy Storage Level for each 1 MWh \nof Charge Energy withdrawn by that Resource and may be submitted to override the \ndefault value submitted during the asset registration process. \nHourly Emergency Maximum Limit:  The maximum MW level at which a Generation \nResource, an External Asynchronous Resource, or Demand Response Resource Type II \nmay operate under Emergency conditions that may be submitted to override the default \nvalue submitted during the asset registration process.  In addition, for a ZG Resource \nparticipating as a Generation Resource, the maximum MW level at which a Resource \nmay operate under Emergency conditions shall be less than the Demand of the \nResource’s ZG Associated Loads. \nHourly Emergency Maximum Charge Limit: The maximum withdrawal MW level at which an \nElectric Storage Resource may operate under Emergency system conditions that may be \nsubmitted to override the default value submitted during the asset registration process. \nHourly Emergency Maximum Discharge Limit: The maximum injection MW level at which an \nElectric Storage Resource may operate under Emergency system conditions that may be \nsubmitted to override the default value submitted during the asset registration process.  In \naddition, for a ZG Resource participating as an Electric Storage Resource, the maximum \nMW level at which the Resource may operate under Emergency system conditions shall \nbe less than the Demand of the Resource’s ZG Associated Loads. \nHourly Emergency Minimum Limit:  The minimum MW level at which a Generation Resource,"},{"page":17,"startToken":4055,"endToken":4323,"text":"MISO \n1.H\nFERC Electric Tariff \nDefinitions - H\nMODULES \n62.0.0, 63.0.0\nEffective On: October 18, 2026\nan External Asynchronous Resource, or Demand Response Resource Type II may operate \nunder Emergency conditions that may be submitted to override the default value \nsubmitted during the asset registration process. \nHourly Emergency Minimum Charge Limit: The minimum withdrawal MW level at which an \nElectric Storage Resource may operate under Emergency system conditions that may be \nsubmitted to override the default value submitted during the asset registration process. \nHourly Emergency Minimum Discharge Limit: The minimum injection MW level at which an \nElectric Storage Resource may operate under Emergency system conditions that may be \nsubmitted to override the default value submitted during the asset registration process. \nHourly Ex Post MCP:  The average Regulating Reserve MCP, Regulating Mileage MCP, \nSpinning Reserve MCP, Supplemental Reserve MCP, Up Ramp Capability MCP, Down \nRamp Capability MCP, and Short-Term Reserve MCP applicable to a specific Resource \nderived through time and quantity weighting of the applicable Ex Post MCPs over the \nHour, and used for purposes of Settlement of Operating Reserves, Regulating Mileage, \nUp Ramp Capability, Down Ramp Capability, and Short-Term Reserve in the Real-Time \nEnergy and Operating Reserve Market. \nHourly Fast Ramping Resource:  An hourly Offer parameter flag (“Yes/No”) representing \nwhether a Resource is offered into the Real-Time Energy and Operating Reserve Market \nas a Fast Ramping Resource. \nHourly Integrated Forecast Maximum Limit:  The hourly integration of the Forecast Maximum \nLimits of a Dispatchable Intermittent Resource as used by the SCED algorithm in the \nReal-Time Energy and Operating Reserve Market for a given Hour."},{"page":18,"startToken":4323,"endToken":4620,"text":"MISO \n1.H\nFERC Electric Tariff \nDefinitions - H\nMODULES \n62.0.0, 63.0.0\nEffective On: October 18, 2026\nHourly Maximum Energy Storage Level:  The maximum amount of Energy that may be stored \nby an Electric Storage Resource on a sustained basis, expressed in MWh, that may be \nsubmitted to override the default value submitted during the asset registration process.  \nThis is equivalent to the hourly maximum State of Charge. \nHourly Minimum Energy Storage Level: The minimum amount of Energy that may be stored \nby an Electric Storage Resource on a sustained basis, expressed in MWh, that may be \nsubmitted to override the default value submitted during the asset registration process.  \nThis is equivalent to the hourly minimum State of Charge. \nHourly Neutral Zone Lower Limit:  A MWh lower limit representing a percentage of the \nCapacity of a Fast Ramping Resource up to which it is being offered, which will be used \nin the Automatic Generation Control fast ramping regulation signal logic. \nHourly Neutral Zone Upper Limit:  A MWh upper limit representing a percentage of the \nCapacity of a Fast Ramping Resource up to which it is being offered, which will be used \nin the Automatic Generation Control fast ramping regulation signal logic. \nHourly Ramp Rate:  The MW/minute response rate for a Generation Resource, External \nAsynchronous Resource, or Demand Response Resource Type-II that is utilized in the \nclearing of the Day-Ahead Energy and Operating Reserve Market and all Reliability \nAssessment Commitment processes that may be submitted to override the default value \nsubmitted during the asset registration process. \nHourly Real-Time Ex Post LMP:  The LMP derived through mathematical integration of the \nDispatch Interval Real-Time Ex Post LMPs over the Hour, and used for purposes of \nSettlement of Energy transactions in the Real-Time Energy and Operating Reserve"},{"page":19,"startToken":4620,"endToken":4887,"text":"MISO \n1.H\nFERC Electric Tariff \nDefinitions - H\nMODULES \n62.0.0, 63.0.0\nEffective On: October 18, 2026\nMarket. \nHourly Real-Time Ex Post MCP:  The average MCPs for Regulating Reserve, Spinning \nReserve, Supplemental Reserve, Up Ramp Capability, Down Ramp Capability, and \nShort-Term Reserve applicable to a specific Resource derived through time and quantity \nweighting of the applicable Real-Time Ex Post MCPs over the Hour, and used for \npurposes of Settlement of Operating Reserves, Up Ramp Capability, Down Ramp \nCapability, and Short-Term Reserve in the Real-Time Energy and Operating Reserve \nMarket. \nHourly Regulation Maximum Charge Limit: The maximum withdrawal MW level at which an \nElectric Storage Resource can respond to automatic control signals, that may be \nsubmitted to override the default value submitted during the asset registration process. \nHourly Regulation Maximum Discharge Limit: The maximum injection MW level at which an \nElectric Storage Resource can respond to automatic control signals, that may be \nsubmitted to override the default value submitted during the asset registration process.  In \naddition, for a ZG Resource participating as an Electric Storage Resource, the maximum \nMW level at which the Resource can respond to automatic control signals shall be less \nthan the Demand of the Resource’s ZG Associated Loads. \nHourly Regulation Maximum Limit:  The maximum MW output at which a Generation \nResource, Demand Response Resource – Type II, or External Asynchronous Resource \ncan respond to automatic control signals that may be submitted to override the default \nvalue submitted during the asset registration process.  In addition, for a ZG Resource \nparticipating as a Generation Resource, the maximum MW level at which a Resource can"},{"page":20,"startToken":4887,"endToken":5154,"text":"MISO \n1.H\nFERC Electric Tariff \nDefinitions - H\nMODULES \n62.0.0, 63.0.0\nEffective On: October 18, 2026\nrespond to automatic control signals shall be less than the Demand of the Resource’s ZG \nAssociated Loads. \nHourly Regulation Minimum Charge Limit: The minimum withdrawal MW level at which an \nElectric Storage Resource can respond to automatic control signals, that may be \nsubmitted to override the default value submitted during the asset registration process. \nHourly Regulation Minimum Discharge Limit: The minimum injection MW level at which an \nElectric Storage Resource can respond to automatic control signals, that may be \nsubmitted to override the default value submitted during the asset registration process. \nHourly Regulation Minimum Limit:  The minimum MW output at which a Generation \nResource, Demand Response Resource–Type II, or External Asynchronous Resource can \nrespond to automatic control signals that may be submitted to override the default value \nsubmitted during the asset registration process. \nHourly Single-Directional-Down Ramp Rate:  The MW/minute rate at which a Generation \nResource, an External Asynchronous Resource, or Demand Response Resource-Type II \ncan respond to the Setpoint Instructions in the downward direction only that may be \nsubmitted to override the default value submitted during the asset registration process. \nHourly Single-Directional-Up Ramp Rate:  The MW/minute rate at which a Generation \nResource, an External Asynchronous Resource, or Demand Response Resource-Type II \ncan respond to the Setpoint Instructions in the upward direction only that may be \nsubmitted to override the default value submitted during the asset registration process. \nHourly Transmission Congestion Charges Collection:  The aggregate amount of Transmission \nUsage Charge collected in a given Hour."},{"page":21,"startToken":5154,"endToken":5426,"text":"MISO \n1.H\nFERC Electric Tariff \nDefinitions - H\nMODULES \n62.0.0, 63.0.0\nEffective On: October 18, 2026\nHub:  A Commercial Pricing Node developed for financial and trading purposes.  \nHUFU ARR:  An ARR allocated during the LTTR Restoration and Termination Stage of an \nAnnual ARR Allocation from a HUFU ARR Entitlement. \nHUFU ARR Entitlement:  An ARR Entitlement defined from a HUFU RSP to the applicable \nARR Zone.  The MW amount of a HUFU ARR Entitlement is calculated, and \ncorresponds to, the RSP MW at a fifty percent (50%) implied capacity factor.  A HUFU \nARR Entitlement is calculated as follows: \nHUFU MW Level = (total net generation MWh in the test period) / (50% x Total Hours \nin the test period). \nHub LMP:  The weighted-averaged LMP for an invariant set of Elemental Pricing Nodes that \ncomprise the Hub.  The weights are static over time, except for those of Elemental \nPricing Nodes constituting ARR Zones administered as Hub Commercial Pricing Nodes.  \nThe weights, or weighting factors, for determining ARR Zone LMPs are updated daily \nbased on State Estimator information. \nHigh-Voltage Direct Current Facilities:  The high voltage direct current transmission facilities, \nincluding associated alternating current facilities, if any, that are subject to Section 27A \nof this Tariff and that are specifically identified in:  (i) any Agency Agreement pertaining \nto such facilities between the Transmission Provider and the Transmission Owner that \nowns or operates such facilities, or (ii) in any other contractual arrangement that permits \nthe Transmission Provider to provide HVDC Service over such facilities, as set forth in \nSection 27A of this Tariff. \nHigh-Voltage Direct Current Facility Upgrades:  All or portion of the modifications or"},{"page":22,"startToken":5426,"endToken":5569,"text":"MISO \n1.H\nFERC Electric Tariff \nDefinitions - H\nMODULES \n62.0.0, 63.0.0\nEffective On: October 18, 2026\nadditions to any HVDC Facilities for the general benefit of all Users of such HVDC \nFacilities. \nHigh-Voltage Direct Current Service:  Firm and Non-Firm Point-to-Point Transmission Service \nprovided by the Transmission Provider on HVDC Facilities pursuant to Section 27A of \nthis Tariff.  \nHigh-Voltage Direct Current Service Agreement:  Any executed or unexecuted agreement for \nHVDC Service, as reflected in Attachment A-3, A-4, and B-1 of this Tariff. \nHigh-Voltage Direct Current Service Charge(s):  The charge(s) for HVDC Service, as stated in \nthe relevant HVDC Service Agreement. \nHybrid Resource:  A Generator that combines more than one type of Electric Facility for the \nproduction and/or storage for later injection of electricity that participates as a single \nGeneration Resource in the Energy and Operating Reserve Market."},{"page":23,"startToken":5569,"endToken":5858,"text":"MISO\n1.P\nFERC Electric Tariff\nDefinitions - P\nMODULES\n69.0.0, 70.0.0\nEffective On: October 18, 2026\nPartial-Year FTR Allocation:  The procedure used by the Transmission Provider to allocate \nFTRs to Market Participants in the new ARR Zones added as a result of Transmission \nProvider Region expansion that becomes effective after the start of the Annual ARR \nAllocation period.  The Partial-Year FTR Allocation will cover the partial year period \nwhen the new ARR Zone(s) become effective to the start of the next Annual ARR \nAllocation.  For the partial year period, the Market Participants in the new ARR Zone(s) \nmay request an allocation of FTRs, which will be in lieu of an allocation of ARRs. \nParty(ies):  The Transmission Provider, ITC where appropriate, Market Participants, \nTransmission Customers, or any combination of the above. \nPast Due Amount:  Any amount invoiced by the Transmission Provider that is not paid when \ndue.\nPeak Reserved Source Set:  Set of Resources including those constituting the Baseload Reserved \nSource Point that have met the Resource Qualification Requirements for inclusion as a \nReserved Source Point for a given ARR Zone. \nPeak Usage:  A Market Participant’s Total Forecasted Peak Load in a given ARR Zone for the \nupcoming Annual ARR Allocation period calculated using the immediate prior three year \nactual peak Loads.  The Total Forecast Peak Load is the sum of the forecast Network \nIntegration Transmission Service peak Load for the upcoming allocation period plus peak \nLoad served by Option A – Grandfathered Agreements plus peak Load served by Option \nB – Grandfathered Agreements.\nPenalty Level:  A component of a mitigation measure described in Module D that represents the \namount of Energy purchased by a Market Participant that is an LSE or represents an LSE"},{"page":24,"startToken":5858,"endToken":6109,"text":"MISO\n1.P\nFERC Electric Tariff\nDefinitions - P\nMODULES\n69.0.0, 70.0.0\nEffective On: October 18, 2026\nin the Real Time Energy Market in excess of the Allowance Level the entity is subject to. \nPhysical Withholding Threshold Quantity:  Threshold employed by the IMM to identify \nphysical withholding by a supplier of Planning Resources for the Planning Resource \nAuction, expressed in MW.\nPlan:  The Transmission Provider’s Market Monitoring Plan set forth in Module D of this Tariff.\nPlanned Transmission Outage:  Any transmission outage scheduled for the performance of \nmaintenance or repairs or the implementation of a system enhancement which is planned \nin advance for pre-determined duration and which meets the notification requirements for \nsuch outages as specified by the Transmission Provider.  \nPlanning Advisory Committee:  A committee of stakeholders established under the ISO \nAgreement for the purpose of providing input to the planning staff on the development of \nthe MTEP.  \nPlanning Area(s):  A collective or alternative reference to the First Planning Area and/or the \nSecond Planning Area.\nPlanning Coordinator:  The entity responsible for the longer term reliability of its planning \ncoordinator area.\nPlanning Reserve Margin (PRM):  The percentage above forecasted Coincident Peak Demand \nof Planning Resources for the Transmission Provider Region in order to meet the LOLE.  \nThis percentage will include a quantity sufficient to cover transmission losses.\nPlanning Reserve Margin Requirement (PRMR):  The amount of ZRCs required of each LSE \nwith Coincident Peak Demand in an LRZ to meet the LSE’s Resource Adequacy \nRequirements in each Season."},{"page":25,"startToken":6109,"endToken":6394,"text":"MISO\n1.P\nFERC Electric Tariff\nDefinitions - P\nMODULES\n69.0.0, 70.0.0\nEffective On: October 18, 2026\nPlanning Resource:  A Capacity Resource or Load Modifying Resource that can be used to \nsatisfy PRMR.\nPlanning Resource Auction (PRA):  Auctions conducted by the Transmission Provider to \ndetermine the ACP and the cleared ZRC Offers for each LRZ and ERZ for each Season \nin the applicable Planning Year.\nPlanning Year:  The period of time from June 1st of one year to May 31st of the following year \nthat is used for developing Resource Plans.  The first Planning Year shall commence on \nJune 1, 2009.\nPMAX:  The maximum Generator real power output reported in MWs on a seasonal basis.\nPMIN:  The minimum Generator real power output reported in MWs on a seasonal basis.\nPoint(s) of Delivery:  Point(s) on the Transmission System where Capacity and Energy \ntransmitted by the Transmission Provider will be made available to the Receiving Party \nunder Module B and Module C of this Tariff.  The Point(s) of Delivery shall be specified \nin the Service Agreement for Long Term Firm Point To Point Transmission Service or \nthe HVDC Service Agreement.\nPoint(s) of Receipt:  Point(s) of interconnection on the Transmission System where Capacity and \nEnergy will be made available to the Transmission Provider by the Delivering Party \nunder Module B and Module C of this Tariff.  The Point(s) of Receipt shall be specified \nin the Service Agreement for Long Term Firm Point To Point Transmission Service or \nthe HVDC Service Agreement.\nPoint(s) of Withdrawal:  The point(s) where a non-transmission facility that is used to withdraw \nEnergy from the Transmission System to serve Load connects to the Transmission"},{"page":26,"startToken":6394,"endToken":6638,"text":"MISO\n1.P\nFERC Electric Tariff\nDefinitions - P\nMODULES\n69.0.0, 70.0.0\nEffective On: October 18, 2026\nSystem.\nPoint-To-Point Transmission Service:  The reservation of Capacity and of Energy on either a \nfirm or non firm basis from the Point(s) of Receipt to the Point(s) of Delivery under \nModule B of this Tariff. \nPortfolio:  For Multi-Value Project purposes, means two or more Multi-Value Projects proposed \nto be located in one or more Transmission Pricing Zones that, when evaluated together, \nare expected to result in system-wide benefits across the MISO footprint or benefits \nacross the subregion. For purposes of the Portfolio, subregion refers to either the MISO \nMidwest MVP Cost Allocation Subregion or MISO South MVP Cost Allocation \nSubregion.\nPost Reserve Deployment Constraints:  The post zonal Operating Reserve and Short-Term \nReserve deployment flows on the transmission constraints and Sub-Regional Power \nBalance Constraints, used to determine the Co-optimized Zonal Regulating Reserve \nRequirement, Co-optimized Zonal Contingency Reserve Requirement, Co-optimized \nZonal Spinning Reserve Requirement, and Co-optimized Zonal Short-Term Reserve \nRequirement, for each Reserve Zone.\nPost Reserve Deployment Constraints Demand Curve:  Demand curves used to price Post \nReserve Deployment Constraints.\nPower Purchaser:  The entity that is purchasing the Capacity and reserved Energy to be \ntransmitted under this Tariff. \nPPA Schedule: Schedule associated with a PPA that is executed after April 3, 2014.\nPre-Confirmed Application:  An Application that commits the Eligible Customer to execute a \nService Agreement upon receipt of notification that the Transmission Provider can"},{"page":27,"startToken":6638,"endToken":6895,"text":"MISO\n1.P\nFERC Electric Tariff\nDefinitions - P\nMODULES\n69.0.0, 70.0.0\nEffective On: October 18, 2026\nprovide the requested Transmission Service.\nPrice Sensitive Demand Bids:  Demand Bids in which the Market Participant specifies a \nmaximum price (dollars per MWh) at which the Market Participant desires to purchase \nthe designated MWh of Energy.\nPrice Taker:  A Market Participant with an Energy and/or Operating Reserve Offer not capable \nof setting LMPs or MCPs. \nProduction Costs:  The Energy output cost of a Generation Resource or a Demand Response \nResource-Type II based upon Start Up, No Load and Energy Offer cost components set \nforth in an Offer or the Energy reduction cost of a Demand Response Resource-Type I \nbased upon Shut Down Offer, Hourly Curtailment Offer and Energy Offer cost \ncomponents set forth in an Offer.\nProject Cost:  All costs for Network Upgrades, as determined by the Transmission Provider to be \na single transmission expansion project, including those costs associated with seeking and \nobtaining all necessary approvals for the design, engineering, construction, and testing of \nthe Network Upgrades.  These Network Upgrades will include costs classified by the \nTransmission Owners and Independent Transmission Companies as transmission plant \nusing the Uniform System of Accounts 350 through 359 or equivalent set of accounts for \nany Coordinating Owner. \nProject Financial Security:  The Cash Deposit or Irrevocable Letter of Credit described in \nAppendix 1 to Attachment FF of the Tariff that a Selected Developer is required to \nprovide.\nProposal: A proposal to construct, implement, own, operate, maintain, repair, and restore all"},{"page":28,"startToken":6895,"endToken":7196,"text":"MISO\n1.P\nFERC Electric Tariff\nDefinitions - P\nMODULES\n69.0.0, 70.0.0\nEffective On: October 18, 2026\nCompetitive Transmission Facilities associated with a Competitive Transmission Project, \nin response to a Request for Proposal. Proposals may be submitted in one of two different \nforms: (i) a Single-Developer Proposal; or (ii) a Joint-Developer Proposal. The term \n“Proposal” shall include “Single-Developer Proposal” and “Joint-Developer Proposal”. \nProposal Cure Period: A period of time, as set forth within Attachment FF, Section VIII.D.10, \nallowed for an RFP Respondent to correct deficiencies identified by the Transmission \nProvider in its previously submitted Proposal. The Proposal Cure Period commences \nupon notification by the Transmission Provider to an RFP Respondent of deficiencies in \nits Proposal. \nProposal Participant(s): Any entity or entities involved in a Proposal, excluding the RFP \nRespondent(s), that will co-own the Competitive Transmission Project and rely on the \nRFP Respondent(s) to be the Selected Developer(s) responsible for constructing and \nimplementing the Competitive Transmission Facilities associated with the Competitive \nTransmission Project. Proposal Participants may be identified in a Proposal as \nresponsible for one or more aspects of operations, maintenance, repair, or restoration, on \nterms comparable to those that would apply if the RFP Respondent(s) intended to rely on \na third-party contractor. \nProposal Submission Deadline: The date and time Proposals must be submitted to the \nTransmission Provider by in order to be considered and evaluated by the Transmission \nProvider. The Submission Deadline shall be no later than 5:00 PM EPT on the date specified \nin the RFP, which shall not exceed one hundred and sixty-five (165) Calendar Days from the \ndate the RFP was issued by the Transmission Provider, unless such date falls on a Saturday, \nSunday, or MISO observed holiday in which case the Proposal Submission Deadline shall be"},{"page":29,"startToken":7196,"endToken":7491,"text":"MISO\n1.P\nFERC Electric Tariff\nDefinitions - P\nMODULES\n69.0.0, 70.0.0\nEffective On: October 18, 2026\nthe next Business Day that is not a MISO observed holiday.\nProposed Generator Planned Outage:  The planned removal from service, in whole or in part, \nof a Generation Resource for inspection, maintenance or repair for which the Generation \nOwner has sought or will seek approval from the Transmission Provider for such planned \nremoval in accordance with the Business Practices Manuals.\nProtected Information:  Privileged and non public information to be maintained by the \nTransmission Provider.\nProxy Offers: The Offers created for resources that are deployed during Emergency operating \nprocedures by the Transmission Provider as specified in Schedule 29A.\nPseudo-tie:  A telemetered reading or value that is updated in real time and used as a tie line \nflow in the Area Control Error equation but for which no physical tie or energy metering \nactually exists.  The integrated value is used as a metered MWh value for interchange \naccounting purposes.  Pseudo tied status of Resources and Loads may only be changed \nduring Network Model updates and the timing of such updates shall be as defined in the \nBusiness Practices Manuals. \nPseudo-tie Agreement:  The Agreement between MISO and a Market Participant included as \nAttachment FFF-1 or Attachment FFF-2 to this Tariff, as applicable, outlining the terms \nand conditions of the real-time transfer of control of a generating unit or load to (or from) \nthe MISO Balancing Authority Area from (or to) a specified external Balancing \nAuthority Area.\nPublic Power:  For credit scoring purposes, an Applicant or Market Participant that is a not for \nprofit municipality, cooperative, Joint Action Agency, or agent representing one or more \nPublic Power entities and whose credit quality is directly derived from the credit quality"},{"page":30,"startToken":7491,"endToken":7701,"text":"MISO\n1.P\nFERC Electric Tariff\nDefinitions - P\nMODULES\n69.0.0, 70.0.0\nEffective On: October 18, 2026\nof the Public Power entities represented through the agency relationship.\nPublic Power Composite Score:  For credit scoring purposes, the weighted average value of the \nPublic Power Qualitative Score and the Public Power Quantitative Score.  The relative \nweights are sixty percent (60%) and forty percent (40%). \nPublic Power Qualitative Score:  A component of a Public Power Composite Score which has, \nfor credit scoring purposes, a value ranging from 1 to 6.99, with 1 being the best and 6.99 \nbeing the worst.  The value is based on a review by the Transmission Provider of \nqualitative factors relative to an Applicant’s business, including but not limited to: i) \nregulatory; ii) legal; iii) demographic; and iv) energy supply/price factors as provided in \nAttachment L to this Tariff.\nPublic Power Quantitative Score:  A component of a Public Power Composite Score which has, \nfor credit scoring purposes, a value ranging from 1 to 6.99, with 1 being the best and 6.99 \nbeing the worst.  The value is based on a review by the Transmission Provider of various \nfinancial metrics as detailed in the Transmission Provider’s credit scoring model in \nAttachment L."},{"page":31,"startToken":7701,"endToken":7985,"text":"MISO\n1.Z\nFERC Electric Tariff\nDefinitions - Z\nMODULES\n42.0.0, 43.0.0\nEffective On: October 18, 2026\nZero Injection Generation (ZG) Associated Load:  A source of electrical load that has a Point of \nWithdrawal that is at the same substation as the Point of Interconnection to the \nTransmission System (i.e. same voltage level at the interconnecting substation) as the \nGenerating Facility with ZG Interconnection Service that will serve it.\nZero Injection Generation (ZG) Interconnection Service:  A limited form of Interconnection \nService that allows an Interconnection Customer to connect its Generating Facility to the \nTransmission System or Distribution System, as applicable, for the limited purpose of \ndelivering energy to ZG Associated Load.  ZG Interconnection Service does not grant \nany right to inject energy onto the Transmission System except as may be authorized by \nSection 3.11 of the Generator Interconnection Procedures.  ZG Interconnection Service \ndoes not convey Transmission Service.  ZG Interconnection Service also does not \nprovide a right to serve, or a right to Transmission Service to serve, a ZG Associated \nLoad or retail customer except as allowed by applicable state law.\nZero Injection Generation (ZG) Resource:  A generating resource with an Attachment X \ndefined ZG Interconnection Agreement.  A ZG Resource may participate as a Generation \nResource, Dispatchable Intermittent Resource, Electric Storage Resource, or Behind the \nMeter Generation resource.\nZonal Deliverability Charge (ZDC):  A positive charge per ZRC associated with ZRCs in a \nFRAP that may be assessed to an LSE based upon the congestion contribution to the \nconstraints between LRZs or ERZs of any ZRCs that are located outside of the LRZ \nwhere the LSE has Load.\nZDC Hedge:  The mechanism that permits an LSE to avoid Zonal Deliverability Charge"},{"page":32,"startToken":7985,"endToken":8241,"text":"MISO\n1.Z\nFERC Electric Tariff\nDefinitions - Z\nMODULES\n42.0.0, 43.0.0\nEffective On: October 18, 2026\nassessments through the investment in new or upgraded Transmission System facilities \nwhich are a result of approved firm transmission service requests where the LSE’s \nPlanning Resource and the LSE’s Demand are in separate LRZs or the Planning Resource \nis located in an ERZ.\nZonal Export Ability:  The ability of an LRZ to export capacity to areas outside of that LRZ.  \nEqual to an LRZ’s base interchange plus the LRZ’s incremental ability to export \ngeneration.\nZonal Import Ability:  The ability of an LRZ to import capacity from areas outside of that LRZ. \nEqual to an LRZ’s base interchange plus the LRZ’s incremental ability to import \ngeneration.\nZonal Operating Reserve:  Operating Reserve that is available on a Reserve Zone basis.\nZonal Regulating Reserve:  Regulating Reserve that is available on a Reserve Zone basis.\nZonal Resource Credit (ZRC):  A MW unit of a Planning Resource that has been converted \nfrom a MW of Seasonal Accredited Capacity to a credit in the MECT, which is eligible to \nbe offered by a Market Participant into the PRA, to be sold bilaterally, eligible to be used \nfor replacement capacity, and/or to be submitted through a Fixed Resource Adequacy \nPlan.\nZonal Uplift Report:  A monthly report of Day-Ahead Revenue Sufficiency Guarantee Credits, \nReal-Time Revenue Sufficiency Guarantee Credits, Day-Ahead Margin Assurance \nPayments, and Real-Time Offer Revenue Sufficiency Guarantee Payments, paid in \ndollars, and categorized by Local Resource Zone, Interface, day, and uplift category."},{"page":33,"startToken":8241,"endToken":8430,"text":"MISO\n1.Z\nFERC Electric Tariff\nDefinitions - Z\nMODULES\n42.0.0, 43.0.0\nEffective On: October 18, 2026\nZRC Near-Shortage Conditions:  Any Season in a Planning Resource Auction in which there is \nsufficient volume of ZRC Offers in the LRZ to meet LCR, but the Season’s ACP is \ngreater than the daily CONE value (i.e. 1/365 times CONE).\nZRC Offer:  An offer into the PRA of ZRCs by a Market Participant.\nZRC Offer Revenue Sufficiency Charge:  A charge that is assessed to an LSE that has cleared \nunder ZRC Shortage Conditions and/or ZRC Near-Shortage Conditions for one or more \nSeason’s in the Planning Resource Auction.\nZRC Offer Revenue Sufficiency Credit:  A Resource credit guaranteed by the Transmission \nProvider ensuring the minimum recovery of a Planning Resource’s Allowable ZRC Costs \nthat have been cleared for one or more Seasons in the Planning Resource Auction.\nZRC Shortage Conditions:  Any Season in a Planning Resource Auction in which there is an \ninsufficient volume of ZRC Offers in the LRZ to cover LCR.\nZone:  A set of Buses in a geographic area as determined by the Transmission Provider."},{"page":34,"startToken":8430,"endToken":8682,"text":"MISO\n38.2.2\nFERC Electric Tariff\nMarket Participant Application and Qualifications\nMODULES\n42.0.0, 43.0.0\nEffective On: October 18, 2026\nTo qualify as a Market Participant, a Market Participant Applicant shall fulfill the following \nrequirements.\na.\nSubmit a duly executed Market Participant Application to the Transmission Provider, in\nsuch form as shall be established by the Transmission Provider.\ni.\nA Market Participant Applicant shall not qualify as a Market Participant until the\nTransmission Provider has duly executed a Market Participant Agreement that has\npreviously been duly executed by the Market Participant Applicant.\nii.\nNotwithstanding any information provided to the Transmission Provider prior to\nthe submission of the Market Participant Application, the Market Participant\nApplicant must provide all information required in the Market Participant\nApplication.\nb.\nDemonstrate to the Transmission Provider that it or its Designated Agent complies with\nall applicable metering, telemetry, data storage and transmission, and other reliability,\noperation, planning and accounting standards and requirements for operating in the\nTransmission Provider Region as set forth in this Tariff.\ni.\nA Market Participant Applicant that intends to assign to a Scheduling Agent, an\nMDMA, or other Market Participant certain Markets Activities shall demonstrate\nto the Transmission Provider’s satisfaction that it has assigned these\nresponsibilities to a qualified Designated Agent by forwarding to the\nTransmission Provider a certificate that represents the underlying relationship\nbetween the Market Participant and the Designated Agent.  In the event an entity\nother than the Local Balancing Authority is designated as an MDMA, the Local"},{"page":35,"startToken":8682,"endToken":8947,"text":"MISO\n38.2.2\nFERC Electric Tariff\nMarket Participant Application and Qualifications\nMODULES\n42.0.0, 43.0.0\nEffective On: October 18, 2026\nBalancing Authority must still receive the metered data.  If a Market Participant \ndesignates another entity as a Scheduling Agent or MDMA, the Market \nParticipant remains financially responsible for all Market Activities represented \nby the Scheduling Agent or MDMA.\nii.\nA Market Participant Applicant that, as a Market Participant, intends to make\npurchases and sales of Energy, Operating Reserves, Up Ramp Capability, Down\nRamp Capability, and/or Short-Term Reserve or Other Ancillary Services, or\nFTRs on behalf of other entities shall so inform the Transmission Provider.  The\nMarket Participant shall remain financially responsible and liable for all Market\nActivities in the Energy and Operating Reserve Markets in which it engages\nregardless of on whose behalf it has arranged to make purchases and sales.  The\nMarket Participant’s purchases and sales for other entities may, however, impact\nits own creditworthiness assessment.\nc.\nInform the Transmission Provider of its intent to submit Self-Schedules, Bilateral\nTransactions, Bids, Offers, including Virtual Bids and Offers, or hold FTRs.\ni.\nMarket Participant Applicants that are party to Grandfathered Agreement(s) and\nintend to terminate such agreements and provide or receive Transmission Service\nunder this Tariff shall so inform the Transmission Provider pursuant to procedures\nestablished by the Transmission Provider.  Such Market Participants that intend to\nmaintain service under such agreements should inform the Transmission Provider\nin accordance with the process set forth by the Transmission Provider of its\nselection of the optional treatment of transactions pursuant to such agreements"},{"page":36,"startToken":8947,"endToken":9212,"text":"MISO\n38.2.2\nFERC Electric Tariff\nMarket Participant Application and Qualifications\nMODULES\n42.0.0, 43.0.0\nEffective On: October 18, 2026\nunder the Energy and Operating Reserve Markets as described in Section 38.8.3.  \nIn addition, the Market Participant Applicant shall provide the information listed \nin Section 38.2.3.a.  \nd.\nA Market Participant Applicant seeking to submit Demand Bids into the Day-Ahead\nEnergy and Operating Reserve Market shall demonstrate to the Transmission Provider\nthat the end-users to be served by Energy purchased in the Energy and Operating Reserve\nMarkets are located within the Transmission Provider Region or will be brought within\nthe Transmission Provider Region prior to any purchases from the Energy and Operating\nReserve Markets.\ne.\nA Market Participant Applicant seeking to submit Generation Offers or Electric Storage\nResource Offers, including Self-Schedules, to sell in the Energy and Operating Reserve\nMarkets shall demonstrate to the Transmission Provider that such Market Participant\nApplicant:  (i) has exclusive rights through ownership, operational control, or other\ncontractual arrangements to the output of Resources capable of responding to the\nDispatch Target and, if applicable, Setpoint Instructions; (ii) meets any applicable\nrequirements pursuant to RAR; and (iii) complies with all metering, telemetry, data\nstorage and communication protocols, and other reliability, operation, planning and\naccounting standards and requirements for operating in the Transmission Provider Region\nnecessary to allow the Transmission Provider to validate the ability of the Generation\nResource or Electric Storage Resource to respond to the Dispatch Targets, and, if\napplicable, Setpoint Instructions.\nCriteria for generating facility, including a storage facility, with ZG Interconnection"},{"page":37,"startToken":9212,"endToken":9494,"text":"MISO\n38.2.2\nFERC Electric Tariff\nMarket Participant Application and Qualifications\nMODULES\n42.0.0, 43.0.0\nEffective On: October 18, 2026\nService. A ZG Resource that is greater than 5 MW in size must register, prior to its \nCommercial Operation Date, as a Generation Resource, Energy Storage Resource, or \nDispatchable Intermittent Resource based on its applicable operating characteristics.\nA Market Participant Applicant seeking to submit ZRC Offers, including Self Schedules \nor FRAPs, for LMRs to sell capacity in the PRA shall demonstrate to the Transmission \nProvider that such Market Participant Applicant:  (i) has exclusive rights through \nownership, operational control, or other contractual arrangements to the output of LMRs \ncapable of responding to Scheduling Instructions; (ii) meets any applicable requirements \npursuant to RAR; and (iii) complies with all metering, data storage, accounting and \ncommunication protocol requirements applicable to LMRs under the Tariff, Business \nPractices Manuals, or necessary to allow the Transmission Provider to validate the ability \nof the LMR to respond to the Scheduling Instructions.\nf.\nA Market Participant Applicant seeking to engage in Market Activities shall demonstrate\nto the Transmission Provider that it meets all of the requirements established by the\nTransmission Provider and included in this Tariff for each activity as to which Market\nParticipant seeks to participate, including, without limitation, executing a credit\nagreement in a form acceptable to the Transmission Provider, providing any Financial\nSecurity required by the Transmission Provider and otherwise complying with the Credit\nPolicy.\ng.\nA Market Participant Applicant seeking to submit Demand Response Resource–Type I\nOffers or Demand Response Resource–Type II Offers in the Energy and Operating\nReserve Markets shall:  (i) demonstrate to the Transmission Provider that it has exclusive"},{"page":38,"startToken":9494,"endToken":9784,"text":"MISO\n38.2.2\nFERC Electric Tariff\nMarket Participant Application and Qualifications\nMODULES\n42.0.0, 43.0.0\nEffective On: October 18, 2026\nrights through ownership, operational control, or other contractual rights to the output of \nsuch Resources, (ii) that such Resources are capable of responding to the Dispatch Target \nfor Energy and Operating Reserve and Setpoint Instructions if a Demand Response \nResource–Type II or that such Resources are capable of responding to commitment \ninstructions to supply Energy or responding to deployment instructions associated with \nDispatch Targets for Contingency Reserve in the case of a Demand Response Resource–\nType I; (iii) designate those Resources as either a Demand Response Resource–Type I or \nDemand Response Resource–Type II with the Transmission Provider; (iv) demonstrate to \nthe Transmission Provider that it complies with all metering, telemetry, data storage, and \ncommunication protocols, and other reliability, operation, planning, and accounting \nstandards and requirements for operating in the Transmission Provider Region necessary \nto allow the Transmission Provider to validate the ability of the Resource to respond as \ndescribed under (ii) above; and (v) verify to the Transmission Provider during the asset \nregistration process that it has received any required approvals from all applicable state \nregulatory agencies to enable such Resources to participate in the Energy and Operating \nReserve Markets.\nh.\nTransmission Provider Evaluation of Application.  Upon submission of a complete \nMarket Participant Application, and such other information as shall be requested by the \nTransmission Provider, and a signed written representation that the Market Participant \nApplicant will be able to execute the Market Participant Agreement as provided in \nAttachment W of this Tariff upon approval of the Application, the Transmission Provider \nshall investigate and evaluate whether the Market Participant Applicant meets the criteria"},{"page":39,"startToken":9784,"endToken":9902,"text":"MISO\n38.2.2\nFERC Electric Tariff\nMarket Participant Application and Qualifications\nMODULES\n42.0.0, 43.0.0\nEffective On: October 18, 2026\nspecified in Section 38.2.2.  As soon as practicable, but in any event not later than sixty \n(60) Days after submission of the requested information, the Transmission Provider shall \nnotify the Market Participant Applicant of its determination, along with a written \nsummary of the basis for the determination.  The Transmission Provider shall grant the \nsought for status upon a reasonable showing by the Market Participant Applicant that it \nmeets the criteria specified in Section 38.2.2, subject to its execution of the applicable \nMarket Participant Agreement and upon approval of the Application."},{"page":40,"startToken":9902,"endToken":10172,"text":"MISO\n68A.8\nFERC Electric Tariff\nCalculation of Transmission Losses\nMODULES\n37.0.0, 38.0.0\nEffective On: October 18, 2026\nCalculation of Transmission Losses\na.\nThe Transmission Provider shall calculate the LBA transmission loss percentages for \neach Season using the process described as follows:\n1.\nThe Transmission Provider's State Estimator calculates transmission losses (MW) \nas part of the solution output process every five (5) minutes.\n2.\nThe transmission losses (MW) are computed on all transmission lines and \ntransformers by summing up real power at both ends for each transmission \nelement (retaining the convention for flow direction) or as the difference in real \npower (without the sign convention for flow direction) for each State Estimator \nsolution.\n3.\nThe individual transmission losses (MW) for each element are summed to a total \ntransmission values for each Local Balancing Authorities (LBA) level.\n4.\nThese LBA transmission loss values are then integrated across each hour to \ncalculate an hourly transmission loss value (MW) for each LBA.\n5.\nThe total transmission loss value (MW) for each LBA will be the hourly \nintegrated transmission losses value (MW) for the hour of the Coincident Peak \nDemand from the calendar year two years prior to the upcoming Planning Year.\n6.\nFor the purposes of the Transmission Provider Region, the LBA transmission loss \npercentages are calculated as the total LBA transmission losses divided by the \ntotal LBA peak data at that MISO peak hour for each Season.  For purposes of a \nLocal Resource Zone, the LBA transmission loss percentages are calculated as the \ntotal LBA transmission losses divided by the total LBA peak data at the LRZ peak"},{"page":41,"startToken":10172,"endToken":10301,"text":"MISO\n68A.8\nFERC Electric Tariff\nCalculation of Transmission Losses\nMODULES\n37.0.0, 38.0.0\nEffective On: October 18, 2026\nhour for each Season.\nb.\nThe Local Balancing Authority (LBA) transmission loss percentage shall apply to the \nLSE's applicable LBA Coincident Peak Demand and Local Resource Zone Peak Demand \nforecast to determine the LSE transmission losses.  Behind-the-Meter-Generation Resources that \nare interconnected to the Transmission System and are not a ZG Resource shall be treated like \nother Resources with respect to transmission losses.  Behind-the-Meter-Generation Resources \nthat are not interconnected to the Transmission System, ZG Resources and Demand Resources \nshall be adjusted to account for serving load without incurring transmission losses by grossing up \nthe MW quantity of such resources by (1.0 + the appropriate LBA transmission loss percentage)."},{"page":42,"startToken":10301,"endToken":10618,"text":"MISO\n69A.1.1\nFERC Electric Tariff\nForecasted Demand Identification\nMODULES\n39.0.0, 40.0.0\nEffective On: October 18, 2026\nForecasted Demand Identification\na.\nThe Demand forecasts required in Section 69A.1 shall include: (1) the Coincident Peak \nDemand within each LBA Area in the Transmission Provider Region for the upcoming Planning \nYear; (2) the monthly non-coincident peak Demand and net Energy for Load within each LBA \nArea, for the upcoming Planning Year and the following Planning Year; (3) the non-coincident \npeak Demand and net Energy for Load within each LBA Area, for each Season, for the eight \nPlanning Years subsequent to the two for which monthly values are provided in (2); and (4) the \navailable Local Resource Zone Peak Demand within each LBA Area in the Local Resource Zone \nfor the upcoming Planning Year.  All of these forecasts shall be submitted by November 1st prior \nto each Planning Year and shall be consistent with Good Utility Practice.  Forecast providers \nshall use the MECT or other means described in the BPM for Resource Adequacy to submit the \nrequisite information.  Details regarding the items required in the Demand forecasts submittal are \nin the BPM for Resource Adequacy.  \nb.\nThe supplied Coincident Peak Demand and Local Resource Zone Peak Demand forecasts \nshall include the Demand expected for the forecast time period (e.g. the Coincident Peak \nDemand hour) augmented to include the normal Demand from forecasted demand resources, \nwhether registered or not registered with the Transmission Provider, including Demand from any \nretail demand side management programs.  The Coincident Peak Demand forecast shall identify, \nin MW, the expected contribution of each ZG Associated Load and identify its associated ZG \nResource.  A ZG Resource is ineligible for Seasonal Accredited Capacity unless its ZG \nAssociated Load is explicitly identified in the Coincident Peak Demand forecast.  Such forecasts \nmay include Demand reductions achieved by energy efficiency programs that will be fully"},{"page":43,"startToken":10618,"endToken":10927,"text":"MISO\n69A.1.1\nFERC Electric Tariff\nForecasted Demand Identification\nMODULES\n39.0.0, 40.0.0\nEffective On: October 18, 2026\nimplemented prior to the start of the Planning Year.  Energy efficiency programs are installed \nmeasures on retail customer facilities that achieve a permanent reduction in electric Energy \nusage while maintaining a comparable quality of service and must comply with the guidelines set \nforth in the BPM for Resource Adequacy.  Energy efficiency program effects included in the \nload forecast must follow state and RERRA regulations and measurement and verification \nrequirements, as applicable.  All submissions for such forecast values shall include distribution \nlosses, but not transmission losses.  The Transmission Provider will be responsible for the \ncalculation of the applicable transmission losses for the forecasts provided and for annually \npublishing such values for each LBA on its website by October 1, as specified in Section 68A.8 \nand the BPM for Resource Adequacy. \nc.\nIn order to assist with the development of the Coincident Peak Demand and Local \nResource Zone Peak Demand forecasts, the Transmission Provider will make available the \nhistorical monthly peak hours for each of the four months June through September, since 2005, \nor as available, for the Transmission Provider Region and for each Local Resource Zone.  On or \nbefore March 1st of each year, the Transmission Provider will review a sampling of submitted \nDemand forecast methodologies and inputs to ensure accuracy and consistency, in accordance \nwith the BPM for Resource Adequacy.  If the Transmission Provider determines that the \nDemand forecast methodologies are inaccurate or inconsistent, the Transmission Provider shall \nwork with the applicable LSEs to reconcile such issues.  If reconciliation is not achieved, or if \nLocal Resource Zone Peak Demand forecasts are not available, then the Transmission Provider \nwill provide the required forecast values.\nd.\nAll Coincident Peak Demand and Local Resource Zone Peak Demand forecasts shall"},{"page":44,"startToken":10927,"endToken":11131,"text":"MISO\n69A.1.1\nFERC Electric Tariff\nForecasted Demand Identification\nMODULES\n39.0.0, 40.0.0\nEffective On: October 18, 2026\nreflect a 50% probability that the Demand will not exceed the forecasted Demand for the \nrelevant period.\ne.\nConsistent with Section 69A.1.2.1, the EDC must provide both the Transmission \nProvider and the respective LSEs with each retail customer’s peak load contribution (“PLC”) in \neach Season, including transmission losses and PRM as determined by the Transmission \nProvider, in the EDC’s service territory by December 15th.  At least five (5) Business Days \nbefore January 15, LSEs must notify the EDC and the Transmission Provider if they disagree \nwith the EDC calculated PLC value.\nf.\nIf an LSE knows it will gain a wholesale customer by the beginning of any Season in the \nnext Planning Year, then that LSE may provide the Transmission Provider with the Coincident \nPeak Demand and the Local Resource Zone Peak Demand forecast for such acquired load by \nNovember 1.  In all other cases, the existing Market Participant serving such wholesale customer \nshall provide the Transmission Provider by November 1st with the Market Participant’s forecast \nof the wholesale customer’s Coincident Peak Demand and Local Resource Zone Peak Demand."},{"page":45,"startToken":11131,"endToken":11377,"text":"MISO\n69A.3.1.g\nFERC Electric Tariff\nDetermination of Deliverability\nMODULES\n42.0.0, 44.0.0\nEffective On: October 18, 2026\nA.\nDetermination of Deliverability of Generation Resources, Electric Storage \nResources, and External Resources:\nThe Transmission Provider shall be responsible for determining whether Generation Resources, \nElectric Storage Resources, and External Resources eligible to be Capacity Resources are \ndeliverable to Load.  The deliverable amount of such Generation Resources, Electric Storage \nResources, and External Resources will be any combination of the following: \ni. \nThe amount of Network Resource Interconnection Service under Attachment X;\nii. \nThe amount of Energy Resource Interconnection Service under Attachment X that \nis coupled with firm Transmission Service;\niii. \nThe amount of firm Transmission Service associated with a Grandfathered \nAgreement that can only be used to satisfy PRMR within the LRZ of the Load \nunder the Grandfathered Agreement; \niv. \nThe amount of aggregate deliverability that a Generation Resource or External \nResource was granted through the market transition deliverability test by the \nTransmission Provider and could qualify for Network Resource Interconnection \nService; or \nv. \nThe amount of non-aggregate deliverability that a Generation Resource or \nExternal Resource was granted by the transmission provider and confirmed by a \nNetwork Customer as a designated Network Resource under the OASIS \nreservation process in place prior to either the initial effective date of the Energy \nMarket in 2005 or that corresponding Transmission Owner’s integration date, will \nbe accepted by the Transmission Provider as deliverable to the Network Loads of"},{"page":46,"startToken":11377,"endToken":11599,"text":"MISO\n69A.3.1.g\nFERC Electric Tariff\nDetermination of Deliverability\nMODULES\n42.0.0, 44.0.0\nEffective On: October 18, 2026\nthe Network Customer for that term of the confirmed designation, as such term \nmay be extended.; or,\nvi.\nThe amount of ZG Interconnection Service under Attachment X only for a ZG \nResource. \nB.\nDetermination of Deliverability of Intermittent Generation, Dispatchable \nIntermittent Resources, and Electric Storage Resources:\nThe Transmission Provider shall be responsible for determining whether Intermittent Generation, \nDispatchable Intermittent Resources, and Electric Storage Resources eligible to be Capacity \nResources are deliverable to Load.  The deliverable amount of such Intermittent Generation, \nDispatchable Intermittent Resources, and Electric Storage Resources will be any combination of \nthe following: \ni.\nThe amount of Network Resource Interconnection Service under Attachment X;\nii.\nThe amount of Energy Resource Interconnection Service under Attachment X that \nis coupled with firm Transmission Service;\niii.\nThe amount of firm Transmission Service associated with a Grandfathered \nAgreement that can only be used to satisfy PRMR within the LRZ of the Load \nunder the Grandfathered Agreement; \niv.\nThe amount of aggregate deliverability that the Intermittent Generation or \nDispatchable Intermittent Resource was granted through the market transition \ndeliverability test by the Transmission Provider and could qualify for Network \nResource Interconnection Service; or, \nv.\nThe amount of non-aggregate deliverability that a Intermittent Generation or"},{"page":47,"startToken":11599,"endToken":11779,"text":"MISO\n69A.3.1.g\nFERC Electric Tariff\nDetermination of Deliverability\nMODULES\n42.0.0, 44.0.0\nEffective On: October 18, 2026\nDispatchable Intermittent Resource was granted by the transmission provider and \nconfirmed by a Network Customer as a designated Network Resource under the \nOASIS reservation process in place prior to either the initial effective date of the \nEnergy Market in 2005 or that corresponding Transmission Owner’s integration \ndate, will be accepted by the Transmission Provider as deliverable to the Network \nLoads of the Network Customer for that term of the confirmed designation, as \nsuch term may be extended.; or,\nvi.\nThe amount of ZG Interconnection Service under Attachment X only for a ZG \nResource.\nC.\nDetermination of Deliverability of Resources with Provisional Generator \nInterconnection Agreements:\nThe Transmission Provider shall be responsible for determining whether Resources with \nProvisional Generator Interconnection Agreements are deliverable to Load.  The deliverable \namount of such Resources will be the amount of interconnection service established through the \nannual ERIS evaluation in accordance with the BPM for Generator Interconnection that is \ncoupled with firm Transmission Service."},{"page":48,"startToken":11779,"endToken":12015,"text":"MISO\n69A.3.1.h\nFERC Electric Tariff\nReplacement of Planning Resources\nMODULES\n43.0.0, 44.0.0\nEffective On: October 18, 2026\nReplacement of Planning Resources \nA.\nReplacement of Planning Resources\nA Planning Resource may replace Cleared ZRCs with Uncleared ZRCs pursuant to the \nfollowing circumstances:\ni.\nRetirement and Suspension\n1.\nA Planning Resource for which a Market Participant requests a change in \nstatus in accordance with the System Support Resource (SSR) provisions \ndescribed in Section 38.2.7 will no longer qualify as a Planning Resource \neffective as of the actual date that the status of the Planning Resource changes \nto Retire pursuant to Section 38.2.7.  \n2.\nA Generation Resource that has the status of Suspend pursuant to Section \n38.2.7 will continue to qualify as a Planning Resource in accordance with the \nBPM for Resource Adequacy.  \n3.\nIf a Planning Resource for which a Market Participant converts Seasonal \nAccredited Capacity into ZRCs is Retired or Suspended prior to the end of the \nSeason during the Planning Year in which the ZRCs cleared, such Market \nParticipant must replace the Cleared ZRCs with Uncleared ZRCs.  If a Market \nParticipant does not replace such ZRCs associated with a Retired or \nSuspended Planning Resource, a Capacity Replacement Non-Compliance \nCharge will be assessed as determined below in this Section.\nii.\nICAP Deferral\n1.\nA Planning Resource for which a Market Participant submits an ICAP"},{"page":49,"startToken":12015,"endToken":12278,"text":"MISO\n69A.3.1.h\nFERC Electric Tariff\nReplacement of Planning Resources\nMODULES\n43.0.0, 44.0.0\nEffective On: October 18, 2026\nDeferral Notice will be subject to ICAP Deferral Requirements and Charges \npursuant to Section 69A.7.9.    \n2.\nIf a Market Participant’s Planning Resource fails to satisfy the ICAP deferral \nrequirements set forth in Section 69A.7.9 and the Market Participant does not \nreplace Cleared ZRCs with Uncleared ZRCs, an ICAP Deferral Non-\nCompliance Charge will be assessed pursuant to Section 69A.7.9.  \niii.\nOutage\n1.\nIf a Planning Resource, including a ZG Resource of any type, for which a \nMarket Participant converts Seasonal Accredited Capacity into ZRCs is \nunable to meet the applicable performance requirements for the Cleared ZRCs \nas described in Section 69A.5 for greater than thirty-one (31) Days in total due \nto full or partial Generator Planned Outage during the Season of the Planning \nYear in which the ZRCs cleared, or for Planning Resources that are subject to \nDiversity Contracts for greater than one (1) Month during any Season of the \nPlanning Year in which the ZRCs cleared, such Market Participant must \nreplace the Cleared ZRCs with Uncleared ZRCs to transfer the performance \nrequirements applicable to the Planning Resource.  If a Market Participant \ndoes not replace such ZRCs associated with a Planning Resource, a Capacity \nReplacement Non-Compliance Charge will be assessed as determined below \nin this Section.  \n2.\nAny combination of Cleared ZRCs that are on full or partial Generator \nPlanned Outage for greater than thirty-one (31) Days in total during a Season,"},{"page":50,"startToken":12278,"endToken":12541,"text":"MISO\n69A.3.1.h\nFERC Electric Tariff\nReplacement of Planning Resources\nMODULES\n43.0.0, 44.0.0\nEffective On: October 18, 2026\nor for any other reason including full or partial Generation Outages that were \nnot planned but were known or could have been reasonably anticipated at the \ntime of the PRA, as set forth in the Market Monitoring and Mitigation \nBusiness Practices Manual, or unavailable because subject to a Diversity \nContract that is not available for greater than one (1) Month during a Season, \nwill be assessed a Capacity Replacement Non-Compliance Charge.  \n3.\nIf a Planning Resource for which a Market Participant converts Seasonal \nAccredited Capacity into ZRCs is unable to meet the applicable performance \nrequirements for the Cleared ZRCs as described in Sections 69A.3.3.1 and \n69A.5 due to a Catastrophic Generator Outage any time during the Season(s) \nof the Planning Year in which the ZRCs cleared such Market Participant may \nreplace the Cleared ZRCs with Uncleared ZRCs to transfer the performance \nrequirements applicable to the Planning Resource. \niv.\nLoad Modifying Resources\n1.\nA Behind the Meter Generator for which a Market Participant converts \nSeasonal Accredited Capacity into ZRCs that is unable to meet the applicable \nperformance requirements for the Cleared ZRCs as described in Section \n69A.3.3.1 due to either an outage submitted in accordance with the BPM for \nResource Adequacy or due to regulatory restrictions resulting in the \nunavailability of the BTMG may replace the Cleared ZRCs with Uncleared \nZRCs. \n2.\nA Demand Resource for which a Market Participant converts Seasonal"},{"page":51,"startToken":12541,"endToken":12806,"text":"MISO\n69A.3.1.h\nFERC Electric Tariff\nReplacement of Planning Resources\nMODULES\n43.0.0, 44.0.0\nEffective On: October 18, 2026\nAccredited Capacity into ZRCs is unable to meet applicable performance \nrequirements for the Cleared ZRCs as described in Section 69A.3.3.1 due to a \nchange in ownership of the end use facility or through state or RERRA action \nwhich results in the termination of contracts with the Demand Resource may \nreplace the Cleared ZRCs with Uncleared ZRCs. \n3.\nA Market Participant representing an LMR may through consultation with the \nIMM as set forth in Section 64.3.e of Module D replace the Cleared ZRCs \nwith Uncleared ZRCs. The performance obligation of the Uncleared ZRCs \ntake the place of the applicable performance obligation of the Cleared ZRCs \nthat were replaced.\nv.\nGeneral Provisions\n1.\nA Planning Resource may not transfer its performance requirements by \nreplacing the Cleared ZRCs with Uncleared ZRCs for any reason other than \nthose reasons discussed immediately above.  \n2.\nA Planning Resource for which a Market Participant converts Seasonal \nAccredited Capacity into ZRCs that are used to replace Cleared ZRCs must \nmeet the applicable performance requirements as described in sections \n69A.3.3.1 and 69A.5 for the balance of the Season of the Planning Year, \nsubject to the same replacement requirements set forth above.  \n3.\nCleared ZRCs can be replaced with Uncleared ZRCs that are not from the \nsame LRZ or ERZ by examining post-replacement clearing as if it were the \nPRA clearing results, so that such replacement: (1) does not violate any CIL"},{"page":52,"startToken":12806,"endToken":13079,"text":"MISO\n69A.3.1.h\nFERC Electric Tariff\nReplacement of Planning Resources\nMODULES\n43.0.0, 44.0.0\nEffective On: October 18, 2026\nused in the PRA; (2) does not violate any CEL used in the PRA; (3) does not \nreduce the remaining total ZRCs for any LRZ of Cleared ZRCs below the \nLCR for that LRZ; and (4) does not exceed any flow ranges established under \napplicable seams agreements, coordination agreements, or transmission \nservice agreements.  \n4.\nZRC replacements from LRZs or ERZs other than that of the Cleared ZRCs \nwill be processed in accordance with the following parameters:\ni.\nZRC replacement shall be processed on a first come, first served basis.\nii.\nThe amount of Cleared ZRCs in each LRZ or ERZs at the time of a ZRC \nreplacement shall be based upon the current amounts of Cleared ZRCs, \nincluding any previous replacement transactions.   \n5.\nZRC replacement shall have no impact on settlements from the PRA, FRAPs, \nand RBDC Opt Out, including any assessed Capacity Replacement Non-\nCompliance Charges.\nB.\nCapacity Replacement Non-Compliance Charge and Distribution\ni.\nCapacity Replacement Non-Compliance Charges will be calculated as follows:  \nthe number of days for which the Market Participant had a replacement \nrequirement but failed to replace per section 69A.3.1.h.a above multiplied by the \namount of ZRCs that failed to be replaced multiplied by the sum of the ACP for \nthe applicable Season and the daily CONE value (1/365 times CONE). The ACP \nand the CONE values will be based on the LRZ where the Planning Resource \ncleared those ZRCs. If the Planning Resource is represented in an ERZ connected"},{"page":53,"startToken":13079,"endToken":13219,"text":"MISO\n69A.3.1.h\nFERC Electric Tariff\nReplacement of Planning Resources\nMODULES\n43.0.0, 44.0.0\nEffective On: October 18, 2026\nto a single SRRZ, the applicable CONE value will be the greatest CONE value of \nall LRZs in the respective SRRZ. For External Resources represented in ERZs \nthat are connected to multiple SRRZs or that are not connected to any SRRZs, the \napplicable CONE value will be the greatest CONE value of all LRZs in those \nconnected SRRZs.\nii.\nDistribution of Capacity Replacement Non-Compliance Charges:  Capacity \nReplacement Non-Compliance Charge revenues received by the Transmission \nProvider will be distributed to Market Participants representing LSEs that have \nmet their Final PRMR during the applicable Season of the Planning Year on a pro \nrata basis, based upon their respective LSEs’ share of Final PRMR for the \nTransmission Provider Region."},{"page":54,"startToken":13219,"endToken":13490,"text":"MISO\n69A.3.3\nFERC Electric Tariff\nLoad Modifying Resources\nMODULES\n35.0.0, 37.0.0\nEffective On: October 18, 2026\nLoad Modifying Resources \nLoad Modifying Resources can be offered as ZRCs in the PRA or can be used in FRAPs \npursuant to Section 69A.9 or used in an RBDC Opt Out pursuant to Section 69A.9.1.  As \ndescribed below, a Demand Resource or a BTMG is eligible to qualify as a Load Modifying \nResource if it meets the following requirements.  A ZG Resource may qualify as a BTMG if not \nregistered as a Generation Resource or DIR.  All LMRs that are cleared in the PRA or were \nsubmitted in a FRAP for a Season or submitted in an RBDC Opt Out must be available for use in \nthe event of an Emergency as declared by the Transmission Provider, pursuant to the Emergency \noperating procedures of the Transmission Provider, unless replaced with other ZRCs pursuant to \nSection 69A.3.1.h.  ZRCs from Demand Resources will be grossed-up by the amount of avoided \ntransmission losses in accordance with Section 68A.8.b and also by the applicable PRM in \naccordance with Section 68A.2.  ZRCs from BTMGs will be grossed-up by the amount of \navoided transmission losses in accordance with Section 68A.8.b.  In accordance with the BPM \nfor Resource Adequacy, the Transmission Provider will qualify an LMR for the applicable \nSeason in the upcoming Planning Year.  The amount of ZRCs from Demand Resources and \nBTMG has to be consistent with the expected reduction in demand at the time of the \nTransmission Provider’s expected Coincident Peak Demand."},{"page":55,"startToken":13490,"endToken":13761,"text":"MISO\n69A.3.6\nFERC Electric Tariff\nBehind the Meter Generation Eligibility\nMODULES\n45.0.0, 49.0.0\nEffective On: October 18, 2026\nBehind the Meter Generation Eligibility \n1.\nIn accordance with the BPM for Resource Adequacy, the Transmission Provider will \nqualify a BTMG for the applicable Season in the upcoming Planning Year.  A Market \nParticipant that possesses ownership or equivalent contractual rights in a BTMG can \nrequest accreditation for such BTMG.  The Market Participant registering the BTMG \nmust include the contracts with each end-use customer indicating rights behind the \nBTMG to generate behind-the-meter generation.  Notwithstanding, a copy of a contract \nwith an end-use customer will not be required if the Market Participant is, or has non-\ncontractual legal rights to control, the end use customer.  In addition, the a Market \nParticipant registering a BTMG or ZG Resource participating as a BTMG must meet the \nfollowing requirements: \na.\nregistering such resource(s) with the Transmission Provider as documented in the \nBPM for Resource Adequacy.\nb.\ndemonstrating GVTC capability for applicable Season in each Planning Year on \nan annual basis as established in the BPM for Resource Adequacy, and by \nsubmitting the GVTC results to the Transmission Provider no later than \nSeptember 30 prior to such Planning Year for existing accredited BTMG unless \nthe Transmission Provider has granted an extension pursuant to Section \n69A.3.6.1.k.  All new BTMGs or an existing accredited BTMG that has an \nincreased installed capacity shall submit their GVTC to the Transmission Provider \nprior to qualification, but no later than March 1 prior to the PRA as established in \nthe BPM for Resource Adequacy."},{"page":56,"startToken":13761,"endToken":14046,"text":"MISO\n69A.3.6\nFERC Electric Tariff\nBehind the Meter Generation Eligibility\nMODULES\n45.0.0, 49.0.0\nEffective On: October 18, 2026\nc.\nsubmitting generator availability data (including, but not limited to, NERC GADS \ninformation) into a database provided by the Transmission Provider and as \nestablished in the BPM for Resource Adequacy.  A Market Participant is not \nrequired to report generator availability data based on GVTC for a BTMG less \nthan 10 MW if the Market Participant has never provided such data for such \nBTMG.  A Market Participant that begins reporting generator availability data \nbased upon GVTC for a BTMG that is less than 10 MW must continue to report \nsuch data.  \nd.\nhaving a notification time requirement less than or equal to 6 hours to receive \ncredit as a Planning Resource. \ne.\ndemonstrating that the BTMG is able to sustain energy production at the \naccredited MW level for at least four (4) continuous Hours;  \nf.\ndemonstrating that the BTMG is capable of being deployed at the accredited MW \nlevel for: (i) at least the first five (5) times requested in the Summer Season; and \n(ii) at least the first five (5) times requested in the Winter Season; (iii) at least the \nfirst three (3) times requested in the Spring Season; and (iv) at least the first three \n(3) times requested in the Fall Season, based on their physical capability when \ncalled upon by the Transmission Provider during an Emergency during any \napplicable Season in a Planning Year for which the BTMG receives credit as a \nPlanning Resource.  Limitations due to applicable regulatory restrictions that are \nmore restrictive than the physical limitations of the BTMG will supersede the \nphysical availability of the BTMG."},{"page":57,"startToken":14046,"endToken":14312,"text":"MISO\n69A.3.6\nFERC Electric Tariff\nBehind the Meter Generation Eligibility\nMODULES\n45.0.0, 49.0.0\nEffective On: October 18, 2026\ng.\nThere shall be no penalties assessed to a Market Participant representing the entity \nthat has offered ZRCs from the LMR if the BTMG Resource is unavailable for \ninterruption as a result of maintenance requirements in accordance with Good \nUtility Practice, or for reasons of Force Majeure, or in the event the specified \nBTMG reduction had already been accomplished for other reasons (e.g., \neconomic considerations, operating the BTMG Resource at or above the credited \nlevel of BTMG Resource, or local reliability concerns in accordance with \ninstructions from the Local Balancing Authority). \nh.\nA BTMG Resource for which operation is not an obligation during Emergency \nevents declared by the Transmission Provider pursuant to the Transmission \nProvider emergency operating procedures, will not qualify as an LMR.  \ni.\nA Market Participant shall be prohibited from registering a BTMG Resource for \nwhich credit is already being taken by a Market Participant.\nj.\nMarket Participants providing physical, regulatory, or contractual limitations of \nthe notice time and availability of BTMG must provide appropriate \ndocumentation to the Transmission Provider in accordance with the BPM for \nResource Adequacy. \nk.\nA Market Participant for a BTMG required to submit GVTC results must use \nReasonable Efforts to submit GVTC by September 30 prior to the upcoming \nPlanning Year.  If circumstances prevent the Market Participant from submitting \nthe GVTC results for the BTMG by September 30, the Market Participant must \nnotify the Transmission Provider no later than five (5) Business Days after"},{"page":58,"startToken":14312,"endToken":14505,"text":"MISO\n69A.3.6\nFERC Electric Tariff\nBehind the Meter Generation Eligibility\nMODULES\n45.0.0, 49.0.0\nEffective On: October 18, 2026\nSeptember 30 and request an extension.  The extension request must include a \nreasonable explanation and justification for missing the deadline and an expected \ncompletion date prior to the upcoming Planning Year.  The Transmission Provider \nwill review each extension request on a case by case basis to determine whether \nor not to approve or deny the request to extent the GVTC deadline.  Denial of an \nextension will not preclude the Market Participant for the BTMG from utilizing \nthe ICAP Deferral process as described in Section 69A.7.9.\n2.\nInstalled Capacity (ICAP) Deferral\nIf a Market Participant for a BTMG has not completed GVTC testing by the deadlines \nprovided in 69A.3.6.1.b, is not expected to demonstrate deliverability, or is otherwise not \nexpected to demonstrate commercial operation prior to March 1, ZRCs from such \ncapacity may be used the PRA, in a FRAP (including through bilateral ZRC transactions) \nor in an RBDC Opt Out, subject to the notification, credit, and non-compliance \nprovisions of Section 69A.7.9."},{"page":59,"startToken":14505,"endToken":14825,"text":"MISO\n69A.3.9\nFERC Electric Tariff\nPenalty Provisions for LMRs\nMODULES\n39.0.0, 42.0.0\nEffective On: October 18, 2026\nPenalty Provisions for LMRs \nUnless an LMR is unavailable as a result of maintenance requirements, for reasons of Force \nMajeure, or because the number of required deployments based on the registered number has \nbeen reached, the Market Participant representing the entity that had ZRCs from LMRs, \nincluding ZG Resources participating as BTMG, that cleared in the PRA, were used in a FRAP, \nor were used in an RBDC Opt Out will be subject to the following penalties in the event the \nLMR is called upon during an Emergency as declared by the Transmission Provider and the \nLMR fails to perform in accordance with its Market Participant’s response to such Market \nParticipant’s Scheduling Instructions.  The penalties defined below will only apply to the portion \nof the Market Participant’s response to such Market Participant’s Scheduling Instruction that is \nnot followed during the Emergency declaration and will only be assessed by the Transmission \nProvider after giving the operator of the LMR an opportunity to provide documentation of the \nspecific circumstances that would justify exemption from such penalties.  There will not be an \nLMR penalty assessed for any portion of the Scheduling Instruction which had already been \naccomplished by an LMR for other reasons (e.g., for economic considerations, self-scheduling at \nor above the credited amount of BTMG or local reliability concerns in accordance with \ninstructions from the Local Balancing Authority) at the time the request for interruption is made \nby the Transmission Provider.  Likewise, for certain Demand Resources that are temperature \ndependent (e.g., a Demand Resource program involving air conditioning load), the specified \nDemand reduction may be adjusted in a manner defined in the measurement and verification \nprocedures developed by the Transmission Provider to reflect the circumstances at the time a \nDemand Resource is called upon to reduce Demand."},{"page":60,"startToken":14825,"endToken":15113,"text":"MISO\n69A.3.9\nFERC Electric Tariff\nPenalty Provisions for LMRs\nMODULES\n39.0.0, 42.0.0\nEffective On: October 18, 2026\na.\nThe Transmission Provider shall assess the responsible Market Participant the \ncosts that were otherwise incurred to replace the deficient Planning Resource at \nthe time the Market Participant’s LMR is called upon by the Transmission \nProvider and does not respond in full or in part consistent with the Market \nParticipant’s response to MISO’s Scheduling Instructions.  These costs will be the \nproduct of the amount of specified Demand reduction not achieved and the \nHourly Real-Time Ex Post LMP at the Load CPNode, plus any applicable \nRevenue Sufficiency Guarantee charges.  The Transmission Provider shall \nallocate any such penalty revenues only to the Market Participants representing \nthe LSEs in the Local Balancing Authority Area(s) that experienced the \nEmergency that required the use of an LMR.  Such revenues shall be distributed \non a Load Ratio Share basis.  For any situation where either an LMR does not \nrespond to an interruption request, including those circumstances where the LMR \nis claimed to be unavailable as a result of maintenance requirements or for \nreasons of Force Majeure, the Transmission Provider shall initiate an \ninvestigation with the Market Participant which has registered the Demand \nResource or BTMG and was qualified as an LMR into the cause of the LMR not \nbeing available when called upon to reduce Demand.   If deemed appropriate by \nthe Transmission Provider, the Transmission Provider will disqualify the Demand \nResource or BTMG from further use as an LMR for the remainder of the current \nPlanning Year, and will discontinue payment of the applicable ACP for the \nremainder of the current Planning Year when the LMR was unavailable. If such"},{"page":61,"startToken":15113,"endToken":15372,"text":"MISO\n69A.3.9\nFERC Electric Tariff\nPenalty Provisions for LMRs\nMODULES\n39.0.0, 42.0.0\nEffective On: October 18, 2026\nLMR was used in a FRAP or cleared in the PRA or used in an RBDC Opt Out, \nthen the Market Participant will be charged the applicable ACP for the remainder \nof the current Planning Year for the Unforced Capacity of the LMR.  The \nrevenues collected will be distributed on a pro rata basis in such LRZ based upon \nan LSE’s Final PRMR.\nb.\nIn the event the same LMR is unavailable on a second occasion (with at least a \nseparation period of 24 hours) when called upon to respond to Scheduling \nInstructions, except for a validated circumstance of maintenance requirements or \nfor reasons of Force Majeure, the Market Participant taking credit for that LMR \nshall make the same penalty payment as indicated in Section 69A.3.9.a above, and \nthe Demand Resource or BTMG will no longer qualify as an LMR and will not \nreceive the applicable ACP for the remainder of the current Planning Year and \nwill not be eligible for LMR status for the next Planning Year. If such LMR was \nused in a FRAP or cleared in the PRA or used in an RBDC Opt Out, then the \nMarket Participant will be charged the applicable ACP for the remainder of the \ncurrent planning year for the Unforced Capacity of the LMR.  The revenues \ncollected will be distributed on a pro rata basis in such LRZ based upon an LSE’s \nFinal PRMR."},{"page":62,"startToken":15372,"endToken":15624,"text":"MISO\n69A.4.1\nFERC Electric Tariff\nSeasonal Accredited Capacity of Capacity Resources\nMODULES\n39.0.0, 43.0.0\nEffective On: October 18, 2026\nSeasonal Accredited Capacity of Capacity Resources \nThe Transmission Provider will determine the Seasonal Accredited Capacity for each Capacity \nResource.\na. \nThe Seasonal Accredited Capacity for a Capacity Resource that is a Generation \nResource, but not a Dispatchable Intermittent Resource, Intermittent Generation, \nElectric Storage Resource, External Resource, or Use Limited Resource, or a ZG \nResource, is based on an evaluation of the type and volume of interconnection \nservice, GVTC value, and Real-Time offered availability of such Generation \nResource or Electric Storage Resource for each Season as set forth in Schedule \n53.  \nb. \nThe Seasonal Accredited Capacity for a Capacity Resource that is an External \nResource, but not a Dispatchable Intermittent Resource, Intermittent Generation \nor Use Limited Resource, is based on the GVTC value and XEFORd values of \nsuch External Resource for each Season. External Resources that are not required \nto report generator availability data will have a forced outage rate based on the \nclass average forced outage rate of the resource type.\nc. \nThe Transmission Provider will determine the Seasonal Accredited Capacity for a \nDRR that qualifies as a Capacity Resource and that interrupts or controls Load, \nbased upon historical performance and availability, for each Season, as set forth in \nSchedule 53.\nd. \nThe Transmission Provider will determine the Seasonal Accredited Capacity for \neach DRR that qualifies as a Capacity Resource and that is a behind the meter"},{"page":63,"startToken":15624,"endToken":15884,"text":"MISO\n69A.4.1\nFERC Electric Tariff\nSeasonal Accredited Capacity of Capacity Resources\nMODULES\n39.0.0, 43.0.0\nEffective On: October 18, 2026\ngeneration facility based on an evaluation of the GVTC value and Real-Time \noffered availability for such behind the meter generation facility for each Season \nas set forth in Schedule 53. If such behind the meter generation facility is \ninterconnected to the Transmission System, the Transmission Provider will \nconsider the type and volume of interconnection service when determining the \nSeasonal Accredited Capacity. \ne. \nThe Seasonal Accredited Capacity for a Capacity Resource that is a Dispatchable \nIntermittent Resource or Intermittent Generation will be determined by the \nTransmission Provider based on historical performance, availability, and type and \nvolume of interconnection service, for each Season in accordance with the BPM \nfor Resource Adequacy.\nf.\nThe Seasonal Accredited Capacity value for a Capacity Resource that is a Hybrid \nResource will be established by the Transmission Provider based on the sum of \nthe Seasonal Accredited Capacity values of its respective Electric Facilities for \nthe production and/or storage for later injection of electricity, up to the level of \nfirm interconnection service, prior to a minimum amount of operating data \nbecoming available. Once sufficient operation data is available, as defined in the \nBPM, the Seasonal Accredited Capacity value for a Hybrid Resource will be \ndetermined by the Transmission Provider based on historical performance, \navailability, and type and volume of interconnection service, for each Season in \naccordance with the BPM.\ng.\nThe Seasonal Accredited Capacity of a Capacity Resource that is an Electric"},{"page":64,"startToken":15884,"endToken":16107,"text":"MISO\n69A.4.1\nFERC Electric Tariff\nSeasonal Accredited Capacity of Capacity Resources\nMODULES\n39.0.0, 43.0.0\nEffective On: October 18, 2026\nStorage Resource will be established by the Transmission Provider based on an \nevaluation of the type and volume of interconnection service, a GVTC value \nbased upon a power and energy test, and an XEFORd. Electric Storage Resources \nthat are not required to report generator availability data will have an XEFORd \nrate based on their class average forced outage rate.\nh.\nThe Seasonal Accredited Capacity for a Capacity Resource that is a Use Limited \nResource will be determined by the Transmission Provider based on the type and \nvolume of interconnection service, the GVTC and XEFORd values of such Use \nLimited Resource in accordance with the BPM for Resource Adequacy.\ni.\nThe Seasonal Accredited Capacity for a ZG Resource shall be determined based \non its participation type as set forth above, subject to the following additional \nrequirements:\n1.\nThe Seasonal Accredited Capacity of a ZG Resource is capped at the \nspecified portion of the Coincident Peak Demand forecast attributable to \nthe ZG Associated Load less any SAC assigned to the ZG Associated \nLoad.\n2.\nThe Seasonal Accredited Capacity of a ZG Resource shall be grossed-up \nby the amount of avoided Transmission Losses, as set forth in Section \n68A.8.b."},{"page":65,"startToken":16107,"endToken":16370,"text":"MISO\n69A.4.5\nFERC Electric Tariff\nAttributes of ZRCs\nMODULES\n38.0.0, 42.0.0\nEffective On: October 18, 2026\nAttributes of ZRCs \nA Market Participant that owns or possesses equivalent contractual rights to a qualified Planning \nResource can convert the convertible Seasonal Accredited Capacity of the Resource (Seasonal \nAccredited Capacity MW) as determined in section 69.A.3.1.g into ZRCs through the MECT in \norder to offer such ZRCs into a PRA.  Market Participants also can unconvert and/or transfer \nZRCs through the MECT to another Market Participant, as described in the BPM for Resource \nAdequacy.  All ZRCs associated with a ZG Resource must be used as part of an LSE’s Fixed \nResource Adequacy Plan (FRAP) or RBDC Opt Out.\nA.\nEligibility for Zonal Resource Credits for a Capacity Resource that is a Planning \nResource that is not Intermittent Generation or Dispatchable Intermittent Resource.\nFor a Capacity Resource that is not Intermittent Generation or Dispatchable Intermittent \nResource the amount of Capacity that is eligible to be converted to Zonal Resource Credits shall \nbe the convertible Seasonal Accredited Capacity value of the Capacity Resource.  The \nconvertible Seasonal Accredited Capacity shall be determined by:\ni.\nDetermining the Installed Capacity; \nii.\nDetermining the Seasonal Accredited Capacity of the Capacity Resource; \niii.\nAllocating the Capacity Resource’s Seasonal Accredited Capacity value where:\na.\nIf the Capacity Resource has only Energy Resource Interconnection Service, \nthe Seasonal Accredited Capacity will be allocated to the Capacity Resource’s \nEnergy Resource Interconnection Service Seasonal Accredited Capacity \nvalue, which will be calculated by multiplying the lesser of the Capacity"},{"page":66,"startToken":16370,"endToken":16566,"text":"MISO\n69A.4.5\nFERC Electric Tariff\nAttributes of ZRCs\nMODULES\n38.0.0, 42.0.0\nEffective On: October 18, 2026\nResource’s ICAP or Energy Resource Interconnection Service by SAC \ndivided by ICAP;\nb. If the Capacity Resource has both Network Resource Interconnection Service \nand Energy Resource Interconnection Service, the Seasonal Accredited \nCapacity will be allocated first to the Capacity Resource’s Network Resource \nInterconnection Service Seasonal Accredited Capacity value, which will be \ncalculated by multiplying the lesser of the Capacity Resource’s ICAP or \nNetwork Resource Interconnection Service by SAC divided by ICAP, as \nprovided below:\nNRIS SAC = MIN (NRIS, ICAP) × (SAC/ICAP)\nc.\nAny remaining total Seasonal Accredited Capacity value will then be \nallocated to Energy Resource Interconnection Service Seasonal Accredited \nCapacity as provided below:\nERIS SAC = MAX (0, (ICAP-NRIS)) × (SAC/ICAP)\nd. The resulting Network Resource Interconnection Service Seasonal Accredited \nCapacity value shall be eligible to be converted into Zonal Resource Credits; \nand\ne.\nThe resulting Energy Resource Interconnection Service Seasonal Accredited \nCapacity value that is coupled with firm Transmission Service shall be \neligible to be converted into Zonal Resource Credits up to the Energy \nResource Interconnection Service Unforced Capacity value of the Capacity"},{"page":67,"startToken":16566,"endToken":16814,"text":"MISO\n69A.4.5\nFERC Electric Tariff\nAttributes of ZRCs\nMODULES\n38.0.0, 42.0.0\nEffective On: October 18, 2026\nResource, by multiplying the firm Transmission Service amount by SAC \ndivided by ICAP.\nf.\nIf the Capacity Resource has ZG Interconnection Service, the Seasonal \nAccredited Capacity will be allocated as one-hundred percent (100%) of SAC.\nB.\nEligibility for Zonal Resource Credits for a Capacity Resource that is an \nIntermittent Generation or Dispatchable Intermittent Resource\nFor Intermittent Generation and Dispatchable Intermittent Resources that are Capacity \nResources, the amount of Capacity eligible to be converted to Zonal Resource Credits shall be \nthe convertible Seasonal Accredited Capacity value of the Intermittent Generation or \nDispatchable Intermittent Resource, which is equal to the total Seasonal Accredited Capacity \nvalue multiplied by the quotient of the deliverability adjusted Capacity factor divided by the peak \nperformance Capacity factor of the Capacity Resource where:\na.\nthe deliverability-adjusted capacity factor is the average of the actual Energy \noutput capped at the demonstrated deliverability of the Intermittent Generation or \nDispatchable Intermittent Resource determined in Section 69A.3.1.g during the \nhighest system peak load observances for each Season that the Capacity Resource \nwas in service divided by the Installed Capacity of the Capacity Resource; and,\nb.\nthe existing peak performance Capacity factor is the average of the actual Energy \noutput during the highest system peak load observances for each Season that the \nCapacity Resource was in service divided by the Installed Capacity of the \nCapacity Resource."},{"page":68,"startToken":16814,"endToken":16881,"text":"MISO\n69A.7.3\nFERC Electric Tariff\nUncleared ZRCs\nMODULES\n33.0.0, 34.0.0\nEffective On: October 18, 2026\nUncleared ZRCs\nOnce the PRA has concluded, a Market Participant may convert back to Seasonal Accredited \nCapacity any ZRCs that do not clear in the PRA.  ZRCs associated with a ZG Resource that are \nnot used in a FRAP may not be used as Uncleared ZRCs."},{"page":69,"startToken":16881,"endToken":17020,"text":"MISO\n69A.7.8\nFERC Electric Tariff\nSelf-Scheduling Option:\nMODULES\n34.0.0, 35.0.0\nEffective On: October 18, 2026\nSelf-Scheduling Option:  \nLSEs with sufficient ZRCs within an LRZ where the LSE has forecasted Demand will be able to \navoid the financial impact of that LRZ’s ACP for the Final PRMR by Self-Scheduling such \nZRCs into the PRA (i.e., by Offering ZRCs into the PRA at a zero price so that the ZRCs will \nclear).  For Planning Resources associated with ZRCs represented outside the LRZ where the \nLSE has PRMR, an LSE would also need to use the financial hedges described in Section \n69A.7.7 to avoid the financial effects of potential price differences between LRZs or between an \nLRZ and an ERZ.  ZRCs obtained from a ZG Resource may not be used in a Self-Schedule."},{"page":70,"startToken":17020,"endToken":17354,"text":"MISO\n69A.9\nFERC Electric Tariff\nUse of FRAP in the Planning Resource Auction\nMODULES\n38.0.0, 39.0.0\nEffective On: October 18, 2026\nUse of FRAP in the Planning Resource Auction\nAn LSE electing to use a Fixed Resource Adequacy Plan (FRAP) in the PRA for any Season can \ncontinue to use its existing resource planning processes to meet all or any portion of its Initial \nPRMR by providing the Transmission Provider with a FRAP, as described below: \na.\nAn LSE electing to use a FRAP for any Season must submit a FRAP for each LRZ to the \nTransmission Provider by the 7th Business Day of March prior to a Planning Year in \norder for the LSE to demonstrate that the LSE has designated ZRCs in order to meet all \nor any portion of the LSE’s Initial PRMR for such LRZ.  Market Participants submitting \nregistrations for new and existing Load Modifying Resources can be included in the \nModule E Capacity Tracking Tool beginning as early as December prior to the Planning \nYear.  Load Modifying Resources registrations submitted to the Transmission Provider \nwill be evaluated to determine if Load Modifying Resources meet the qualification \nrequirements. Market Participants that submit registrations by February 1 prior to the \nPlanning Year will be evaluated by the Transmission Provider and will be notified of the \noutcome on or before February 21 that precedes the Planning Year.\nMarket Participants that submit registrations between February 2 and February 15 prior to \nthe Planning Year will be evaluated by the Transmission Provider and will be notified of \nthe outcome at least two Business Days prior to the FRAP deadline.  The Transmission \nProvider will make a good faith effort to notify Market Participants that submit \nregistrations after February 15 but not later than March 1 of the outcomes of such \nregistrations no later than the FRAP deadline.  All ZRCs associated with a ZG Resource \nmust be used as part of an LSE’s Fixed Resource Adequacy Plan (FRAP) or RBDC Opt"},{"page":71,"startToken":17354,"endToken":17671,"text":"MISO\n69A.9\nFERC Electric Tariff\nUse of FRAP in the Planning Resource Auction\nMODULES\n38.0.0, 39.0.0\nEffective On: October 18, 2026\nOut.  All ZRCs associated with a ZG Resource that are not used in a FRAP shall have no \ncapacity value as set forth in Section 69A.7.3.  The FRAP must include the LSE’s \nforecasted Coincident Peak Demand for each LRZ for each Season and also identify the \nZRCs that the LSE owns, or has contractual rights to, in order to provide Planning \nResources to meet the FRAP designated portion of its Initial PRMR and also its load ratio \nshare of the LCR for each LRZ for each Season.  The Transmission Provider will \nevaluate each LSE’s FRAP to determine if it meets the designated portion of the LSE’s \nInitial PRMR and the LSE’s share of LCR and the Transmission Provider will notify the \nLSE via the MECT prior to March 15th before a Planning Year of the extent that the \nportion of an LSE’s Initial PRMR or share of LCR for each LRZ is not covered by a \nsubmitted FRAP.  The LSE will have until the PRA offer window opens to remedy any \ndeficiencies in their FRAP for each Season.\nb.\nTo the extent that the LSE’s ZRCs satisfy the portion of the LSE’s Initial PRMR for the \napplicable Season(s) submitted through a FRAP, (1) the LSE will not have an obligation \nto make ZRC Offers for the ZRCs included in the FRAP into the PRA, or otherwise \nparticipate in the PRA for such Season; and (2) the LSE will not have an obligation to \npay the applicable ACP for the LSE’s Initial PRMR within such LRZ that is covered by \nthe FRAP.  The Transmission Provider will consider all PRMR and ZRCs, including \nPRMR and ZRCs in FRAPs, as part of the Transmission Provider’s reliability assessment \nwhen conducting the PRA."},{"page":72,"startToken":17671,"endToken":17857,"text":"MISO\n69A.9\nFERC Electric Tariff\nUse of FRAP in the Planning Resource Auction\nMODULES\n38.0.0, 39.0.0\nEffective On: October 18, 2026\nc.\nAny portion of an LSE’s Initial PRMR not covered by the FRAP may be purchased \nthrough the PRA.  An LSE will be charged the applicable ACP for any PRMR that is \nprocured through the PRA.\nd.\nIf an LSE owns or controls ZRCs that are not included in the LSE’s FRAP, then such \nLSE may submit ZRC Offers into the PRA for all such excess ZRCs, subject to Module \nD.  \ne.\nTo the extent that an LSE designates ZRCs in a FRAP that are represented in the same \nLRZ as the LSE’s Demand to meet the LSE’s Initial PRMR for such LRZ, then the LSE \nwill not be subject to a Zonal Deliverability Charge for such ZRCs.\nf.\nAn LSE that contains ZRCs from Planning Resources that are not represented in the same \nLRZ where the LSE has Demand may be subject to a Zonal Deliverability Charge, which \nwill be calculated as described in Section 69A.7.6(b)."},{"page":73,"startToken":17857,"endToken":18174,"text":"MISO\n69A.9.1\nFERC Electric Tariff\nUse of RBDC Opt Out in the Planning Resource Auction\nMODULES\n34.0.0, 35.0.0\nEffective On: October 18, 2026\nUse of RBDC Opt Out in the Planning Resource Auction\nAn LSE electing to use the RBDC Opt Out can continue to use its existing resource planning \nprocesses to meet its Final PRMR by providing the Transmission Provider with an RBDC Opt \nOut, as described below:\na.\nThe RBDC Opt Out Lock-In Period will be three consecutive Planning Years for \nall Seasons.  If an LSE fails to submit an RBDC Opt Out then the LSE will be \nrequired to participate in the PRA through any combination of the other Tariff-\ndefined options, or pay the Capacity Deficiency Charge, for each Planning Year \nin which the LSE does not submit an RBDC Opt Out. \nb.\nAn LSE under state jurisdiction where the State Regulatory Authority has \noverridden the PRM established by the Transmission Provider is not eligible to \nselect the RBDC Opt Out.\nc.\nAn LSE selecting the RBDC Opt Out will be required to meet its Final PRMR for \nthe entirety of its load and losses, and its entire share of LCR for each LRZ, for \neach Season.  All ZRCs associated with a ZG Resource must be used as part of an \nLSE’s Fixed Resource Adequacy Plan (FRAP) or RBDC Opt Out.\nd.\nAn LSE must provide an initial notification of its intent to elect the RBDC Opt \nOut no later than January 15th prior to the upcoming Planning Year.  An LSE \nelecting the RBDC Opt Out must submit its final plan for each LRZ to the \nTransmission Provider by the 7th Business Day of March prior to each Planning \nYear during the RBDC Opt Out Lock-In Period in order for the LSE to \ndemonstrate that the LSE has designated ZRCs in order to meet the LSE’s Final"},{"page":74,"startToken":18174,"endToken":18489,"text":"MISO\n69A.9.1\nFERC Electric Tariff\nUse of RBDC Opt Out in the Planning Resource Auction\nMODULES\n34.0.0, 35.0.0\nEffective On: October 18, 2026\nPRMR, and share of LCR for each LRZ, for each Season.  Market Participants \nusing the RBDC Opt Out must submit all registrations for new and existing \nresources to be used in the RBDC Opt Out through the MECT consistent with the \ntimelines established in the Business Practices Manual for Resource Adequacy.  \nThe RBDC Opt Out must include the LSE’s seasonal forecasted Coincident Peak \nDemand for each LRZ and also identify the ZRCs that the LSE owns, or has \ncontractual rights to, in order to provide Planning Resources to meet its Final \nPRMR, and also its share of the LCR for each LRZ for each Season.  The \nTransmission Provider will evaluate each LSE’s RBDC Opt Out on an annual \nbasis to determine if it meets the LSE’s Final PRMR and the LSE’s share of LCR \nrequirements for all Seasons.  The Transmission Provider will notify the LSE \nprior to March 15th before the applicable Planning Year whether the submitted \nRBDC Opt Out meets the LSE’s Final PRMR, and share of LCR for each LRZ, \nrequirement for each Season during the applicable Planning Year.  The LSE must \nremedy any deficiencies in its RBDC Opt Out for each Season before the PRA \noffer window opens.\ne.\nThe Transmission Provider will notify the RERRA(s) following the submission of \nan initial intent to elect the RBDC Opt Out by an LSE.  RERRA(s) may elect to \nnotify the Transmission Provider within twenty (20) Business Days whether the \nLSE’s load subject to the RERRA’s respective jurisdiction is authorized to select \nthe RBDC Opt Out.  Upon receipt of such a notification from the RERRA(s) that \nthe LSE is not authorized to elect the RBDC Opt Out for the LSE’s load subject to"},{"page":75,"startToken":18489,"endToken":18799,"text":"MISO\n69A.9.1\nFERC Electric Tariff\nUse of RBDC Opt Out in the Planning Resource Auction\nMODULES\n34.0.0, 35.0.0\nEffective On: October 18, 2026\nthe RERRA’s respective jurisdiction, the Transmission Provider will reject the \nLSE’s RBDC Opt Out for such load.  If the Transmission Provider receives no \nnotification from the RERRA(s) within the twenty (20) Business Day period, and \nan LSE has demonstrated that it has designated ZRCs in order to meet its Final \nPRMR, and share of LCR for each LRZ, for each Season, then the proposed \nRBDC Opt Out by the LSE will be deemed accepted by the Transmission \nProvider.\nf.\nTo the extent that the LSE’s ZRCs satisfy the LSE’s Final PRMR for the \napplicable Season(s) submitted through an RBDC Opt Out, (1) the LSE will not \nhave an obligation to make ZRC Offers for the ZRCs included in the RBDC Opt \nOut into the PRA, or otherwise participate in the PRA for such Season; and (2) \nthe LSE will not have an obligation to pay the applicable ACP for the LSE’s Final \nPRMR within such LRZ.  The Transmission Provider will consider all PRMR and \nZRCs, including PRMR and ZRCs in RBDC Opt Outs, as part of the \nTransmission Provider’s reliability assessment when conducting the PRA.\ng.\nIf an LSE owns or controls ZRCs that are not included in the LSE’s RBDC Opt \nOut, then such LSE may submit ZRC Offers into the PRA for all such excess \nZRCs, subject to Module D.  Such ZRC Offers may not include ZRCs associated \nwith a ZG Resource.\nh.\nTo the extent that an LSE designates ZRCs in an RBDC Opt Out that are \nrepresented in the same LRZ as the LSE’s Demand to meet the LSE’s Final \nPRMR for such LRZ, then the LSE will not be subject to a Zonal Deliverability"},{"page":76,"startToken":18799,"endToken":19085,"text":"MISO\n69A.9.1\nFERC Electric Tariff\nUse of RBDC Opt Out in the Planning Resource Auction\nMODULES\n34.0.0, 35.0.0\nEffective On: October 18, 2026\nCharge for such ZRCs.\ni.\nAn LSE that designates ZRCs from Planning Resources that are not represented in \nthe same LRZ where the LSE has Demand may be subject to a Zonal \nDeliverability Charge, which will be calculated as described in Section \n69A.7.6(b).\nj.\nLSEs that submit an RBDC Opt Out may not use any of the other options to \nsatisfy their Final PRMR including: (i) submitting a Fixed Resource Adequacy \nPlan; (ii) Self-Scheduling ZRCs; (iii) purchasing ZRCs through the Planning \nResource Auction process, and/or (iv) paying the Capacity Deficiency Charge to \nmeet all or a portion of their Initial PRMR.\nk.\nLSEs that elect the RBDC Opt Out that do not meet their Final PRMR shall pay \nthe RBDC Opt Out Deficiency Charge, which is 2.748 times applicable LRZ’s \nCONE multiplied by the difference in ZRCs between the LSEs Final PRMR and \nthe amount of ZRCs submitted as the LSEs RBDC Opt Out for each Season in \nwhich the LSE fails to meet its Final PRMR.\nl.\nRBDC Opt Out Deficiency Charge revenues will be distributed to Market \nParticipants representing LSEs on a pro rata basis, based upon their respective \nLSE's share of Final PRMR for the Transmission Provider Region minus the Final \nPRMR associated with the RBDC Opt Out Deficiency Charge.  If the LRZ where \nLSEs incurred RBDC Opt Out Deficiency Charges failed to meet its Local \nClearing Requirement (\"LCR\"), then RBDC Opt Out Deficiency Charge revenues \nwill be distributed to Market Participants representing LSEs on a pro rata basis,"},{"page":77,"startToken":19085,"endToken":19250,"text":"MISO\n69A.9.1\nFERC Electric Tariff\nUse of RBDC Opt Out in the Planning Resource Auction\nMODULES\n34.0.0, 35.0.0\nEffective On: October 18, 2026\nbased upon their respective LSE's share of Final PRMR minus the Final PRMR \nassociated with the RBDC Opt Out Deficiency Charge in such LRZ.\nm.\nThe Transmission Provider will determine the RBDC Opt Out Adder that will be \napplicable for the upcoming Planning Year every year on or before December 15. \nThe RBDC Adder applicable during the first Planning Year in which an LSE \nelects to use the RBDC Opt Out will apply for such LSE’s entire RBDC Opt Out \nLock-In Period.\nn.\nThe Transmission Provider will determine the RBDC Opt Out Adder based on a \nSeasonal average of the RBDC based PRA clearing for the prior three Planning \nYears.  If the prior year RBDC based PRA clearing is not available, simulated \nRBDC based PRA clearing will be used to determine the RBDC Opt Out Adder."},{"page":78,"startToken":19250,"endToken":19529,"text":"MISO\nSCHEDULE 53\nFERC Electric Tariff\nSeasonal Accredited Capacity Calculation\nSCHEDULES\n41.0.0, 42.0.0\nEffective On: October 18, 2026\nSchedule 53\nSeasonal Accredited Capacity Calculation\nI.\nGeneral\nSeasonal Accredited Capacity (SAC) for a Capacity Resource that is a DRR or \nGeneration Resource but not a Dispatchable Intermittent Resource, Intermittent Generation, \nElectric Storage Resource, External Resource, or Use Limited Resource will be determined \npursuant to this Schedule 53.  The resources accredited pursuant to this Schedule 53, as \ndescribed above, are here and after referred to as “Schedule 53 Resources”.  A two-tiered \nweighting structure is used to calculate Seasonal Accredited Capacity for Schedule 53 \nResources.  Outage exemptions for planned outages and exemptions for any operating \nlimitations, such as thermal, voltage, or stability limits referenced in the BPM for Outage \nOperations, provided by the Transmission Provider or Transmission Operator to preserve the \nreliability of the Transmission System, that modify the must offer obligation set forth in Section \n69A.5.a will be factored into calculating the tiers of a Schedule 53 Resource’s Seasonal \nAccredited Capacity.\nII.\nTier 1 and Tier 2 Planned Outage Exemption Requirements\nGenerator Planned Outages scheduled to begin before September 1, 2022, will be granted \na Tier 1 and Tier 2 exemption based on Section 38.2.5.g.ix., and as set forth in the Business \nPractices Manual for Resource Adequacy.  Generator Planned Outages scheduled to begin on or \nafter September 1, 2022, will be evaluated for Tier 1 and Tier 2 exemptions based on the \nfollowing requirements. Only full Generator Planned Outages or full Proposed Generator \nPlanned Outages shall be eligible for the Tier 1 and Tier 2 planned outage exemptions set forth \nbelow."},{"page":79,"startToken":19529,"endToken":19810,"text":"MISO\nSCHEDULE 53\nFERC Electric Tariff\nSeasonal Accredited Capacity Calculation\nSCHEDULES\n41.0.0, 42.0.0\nEffective On: October 18, 2026\nGenerator Outage \nSubmission Criteria\nMaintenance Margin >=0 \nfor duration of outage\nMaintenance Margin <0 for \nany day in the duration of \noutage\n>120 days prior to outage start \ndate, and >120 days from end \nof previous outage for unit\nExempt Tier 1 & 2\nExempt Tier 1 Only\n>120 days Prior to Outage \nStart date and <120 days from \nend of Previous outage for \nunit or Outage submitted \nbetween 31-119 days Prior to \noutage start date\nExempt Tier 1 Only\nNo Exemption\n14-30 days prior to outage \nstart date and passes No Harm \nTest\nExempt Tier 1 Only\nNo Exemption\nOutage moved per MISO \nrequest\nExempt Tier 1 & 2\n(Weather, forced outages, other \nconditions in BPM-008)\nExempt Tier 1 & 2 \n(Weather, forced outages, other \nconditions in BPM-008)\nat Transmission Provider’s \ndiscretion or Tier 1 only at \nTransmission Provider’s \ndiscretion\nA.\nTier 2 Planned Outage exemptions  \ni.\nThe Generator Owner or Generator Operator: (a) schedules its first \nGenerator Planned Outage 120 days or more in advance of the outage start \ndate and 120 days or more beyond the end date of any previously \nscheduled outages for the generator unit; and (b) the Proposed Generator \nPlanned Outage is to occur entirely during a period in which there is \nadequate Maintenance Margin at the time advance notice of the outage is \nprovided to the Transmission Provider. There is adequate margin when the \nMaintenance Margin is greater than or equal to zero megawatts after \nsubtracting the megawatts of the requested Proposed Generator Planned \nOutage. The request shall be determined based on highest queued request."},{"page":80,"startToken":19810,"endToken":20064,"text":"MISO\nSCHEDULE 53\nFERC Electric Tariff\nSeasonal Accredited Capacity Calculation\nSCHEDULES\n41.0.0, 42.0.0\nEffective On: October 18, 2026\nii.\nThe Generator Owner or Generator Operator reschedules its Generator \nPlanned Outage at the Transmission Provider’s request: (a) the Proposed \nGenerator Planned Outage is to occur 120 days or more in advance of the \noutage start date and 120 days or more beyond the end date of any \npreviously scheduled outages for the generator unit; and (b) Generator \nPlanned Outage has inadequate Maintenance Margin at time of submittal \nand moves to a time of adequate Maintenance Margin.  \niii.\nThe Transmission Provider may, at its discretion, grant a Tier 2 Planned \nOutage exemption if the Generator Owner or Generator Operator \nreschedules its Generator Planned Outage at the Transmission Provider’s \nrequest due to weather, forced outages, or other conditions listed in the \nBusiness Practices Manual for Outage Operations without regard to how \nmany days in advance the outage was submitted or whether there was \nprojected to be adequate Maintenance Margin for the duration of the \noutages.\nB.\nTier 1 Planned Outage exemptions\ni.\nThe Generator Owner or Generator Operator receives a Tier 2 Planned Outage \nexemption under section A.i above. \nii. The Generator Owner or Generator Operator: (a) schedules its first Generator \nPlanned Outage 120 days or more in advance of the outage start date and 120 \ndays or more beyond the end date of any previously scheduled outages for the \ngenerator unit; and (b) the Proposed Generator Planned Outage is to occur"},{"page":81,"startToken":20064,"endToken":20342,"text":"MISO\nSCHEDULE 53\nFERC Electric Tariff\nSeasonal Accredited Capacity Calculation\nSCHEDULES\n41.0.0, 42.0.0\nEffective On: October 18, 2026\nduring a period when there is inadequate Maintenance Margin at the time the \noutage is provided to the Transmission Provider. There is inadequate margin \nwhen the Maintenance Margin is less than or equal to zero megawatts, for any \nday of outage, after subtracting the megawatts of the requested Proposed \nGenerator Planned Outage. The request shall be determined based on highest \nqueued request. \niii. Subsequent generator unit outage requests 120 days or more in advance and/or \nGenerator Owners or Generator Operators Generator Planned Outage less than \n120 days in advance and at least 31 days in advance of outage start date. \nProposed Generator Planned Outage to occur entirely during a period in which \nthe generator unit has an adequate projected margin, at the time the outage is \nprovided to the Transmission Provider. There is adequate margin when the \nMaintenance Margin is greater than or equal to zero megawatts after \nsubtracting the megawatts of the requested Proposed Generator Planned \nOutage. The request shall be determined based on highest queued request. \niv. Generator Owners or Generator Operators Generator Planned Outage less than \n31 days in advance and at least 14 days in advance of outage start date. A \nProposed Generator Planned Outage to occur entirely during a period the \ngenerator unit has an adequate Maintenance Margin at the time the outage is \nprovided to the Transmission Provider and the outage passes the No Harm \nTest. There is adequate margin when the Maintenance Margin is greater than \nor equal to zero megawatts after subtracting the megawatts of the requested"},{"page":82,"startToken":20342,"endToken":20588,"text":"MISO\nSCHEDULE 53\nFERC Electric Tariff\nSeasonal Accredited Capacity Calculation\nSCHEDULES\n41.0.0, 42.0.0\nEffective On: October 18, 2026\nProposed Generator Planned Outage. The request shall be determined based \non highest queued request.\nv. Generator Owner or Generator Operator reschedules its Generator Planned \nOutage at the Transmission Provider’s request due to inadequate Maintenance \nMargin for the duration of outage, at the time the outage is provided to the \nTransmission Provider.  Maintenance Margin is less than zero megawatts after \nsubtracting the megawatts of the requested Proposed Generator Planned \nOutage.  This requirement does not include outages submitted less than 14 \ndays in advance of the start date. \nvi. The Transmission Provider may, at its discretion, grant a Tier 1 Planned \nOutage exemption if the Generator Owner or Generator Operator reschedules \nits Generator Planned Outage at the Transmission Provider’s request due to \nweather, forced outages, or other conditions listed in Business Practices \nManual for Outage Operations without regard to how many days in advance \nthe outage was submitted or whether there was projected to be adequate \nMaintenance Margin for the duration of the outages.\nC.\nNo Harm Tests\nOutages submitted between 14 to 30 days of start date will be evaluated for final \napproval and exemption status together.  The No Harm Tests include, but are not \nlimited to, outage approval, compliance with all applicable operation guides, \nreview of possible conflicting outages or system conditions, and system capacity \n(Maintenance Margin, Multiday Operational Margin, 30-day margin). It also"},{"page":83,"startToken":20588,"endToken":20883,"text":"MISO\nSCHEDULE 53\nFERC Electric Tariff\nSeasonal Accredited Capacity Calculation\nSCHEDULES\n41.0.0, 42.0.0\nEffective On: October 18, 2026\nincludes the criteria outlined in the Business Practices Manual for Generator \nOutage.\nD.\nLimitation Provided by Transmission Provider or Transmission Operator\nThe Transmission Provider will grant the equivalent of a Tier 2 Planned Outage \nexemption if a Schedule 53 Resource is provided an operating limitation, such as \nthermal, voltage, or stability limits referenced in the BPM for Outage Operations, \nprovided by the Transmission Provider or the Transmission Operator to preserve \nthe reliability of the Transmission System, that is lower than the must offer \nobligation described in Section 69A.5.a.\nIII.\nResource Adequacy Hours\nResource Adequacy (RA) Hours represent the periods of highest risk and greatest need \nduring a Season and throughout the year. They include hours during Maximum Generation \nEmergency declarations and the hours when the operating margin, a measure of available supply \ncapacity above demand and reserve requirements, is at its lowest. \nResource Adequacy Hours will be identified based on an evaluation of the three (3) most \nrecent completed years using the period beginning September 1st and ending August 31st, which \nwill be used to determine Resource Adequacy Hours for each Season (Seasonal RA Hours) and \nfor each annual period (Annual RA Hours). Both Seasonal RA Hours and Annual RA Hours will \nbe determined for the First Planning Area and Second Planning Area separately. The RA Hours \ndetermined in subpart III.A & III.B below are the only RA Hours that will be used to calculate \nTier 2 ISAC in subpart V.C below. Where certain Seasonal RA Hours do not apply for a \nResource due to a Tier 2 Planned Outage exemption or for periods where the Resource was not"},{"page":84,"startToken":20883,"endToken":21169,"text":"MISO\nSCHEDULE 53\nFERC Electric Tariff\nSeasonal Accredited Capacity Calculation\nSCHEDULES\n41.0.0, 42.0.0\nEffective On: October 18, 2026\ndesignated for RAR under Module E-1 of the Tariff and the Resource does not otherwise have 65 \nRA Hours identified for the Season then a Seasonal RA Hour Deficiency exists per subpart \nIII.A.iii and the Resource’s Annual Average Offered Capacity is multiplied by the Seasonal RA \nHour Deficiency per subpart V.C of this Schedule 53.\nA.\nSeasonal RA Hours.  Seasonal RA Hours will include a target of 65 hours for \neach Season consisting of:\ni.\nAll operating hours during any declared Maximum Generation Emergency \nin a Season, excluding any operating hour where a Resource has a Tier 2 \nPlanned Outage exemption or has periods where the Resource was not \ndesignated for RAR under Module E-1 of the Tariff.  If more than 65 of \nsuch hours exists for any Season, all will be considered Seasonal RA \nHours, and;\nii.\nIf there are fewer than 65 hours identified for the Season in Section III.A.i \nabove, additional hours will be identified up to a total of 65 starting with \nthose hours with the lowest Operating Margin that is below a threshold of \n25 percent excluding any operating hour where a Resource has a Tier 2 \nPlanned Outage exemption or has periods where the Resource was not \ndesignated for RAR under Module E-1 of the Tariff, and;\niii.\nIf 65 hours have still not been identified, then a Seasonal RA Hours \nDeficiency exists which is the number of hours less than 65 for any \nSeason.  \nB.\nAnnual RA Hours will include of a target of 260 hours for each of the three (3)"},{"page":85,"startToken":21169,"endToken":21445,"text":"MISO\nSCHEDULE 53\nFERC Electric Tariff\nSeasonal Accredited Capacity Calculation\nSCHEDULES\n41.0.0, 42.0.0\nEffective On: October 18, 2026\nmost recent periods beginning September 1st and ending August 31st consisting of:\ni.\nAll hours during Maximum Generation Emergency declarations excluding \nany operating hour where a Resource has a Tier 2 Planned Outage \nexemption or has periods where the Resource was not designated for RAR \nunder Module E-1 of the Tariff.  If more than 260 of such hours exists for \nany period, all will be considered Annual RA Hours, and;\nii.\nIf there are fewer than 260 hours identified for the period in Section III.B.i \nabove, additional hours will be identified up to a total of 260 starting with \nthose hours with the lowest Operating Margin that is below a threshold of \n25 percent excluding any operating hour where a Resource has a Tier 2 \nPlanned Outage exemption or has periods where the Resource was not \ndesignated for RAR under Module E-1 of the Tariff.\nC.\nSeasonal Non-RA Hours.  Seasonal Non-RA Hours will consist of all hours not \nincluded in Section III.A.i-iii. If a Resource has a Tier 1 and/or Tier 2 Planned \nOutage exemption for any of the operating hours identified as Seasonal Non-RA \nHours or has periods where the Resource was not designated for RAR under \nModule E-1 of the Tariff, such hours will not be included in the applicable \nSeasonal Accredited Capacity calculation.\nD.\nTier 1 Planned Outage exemptions apply only to Non-RA Hours.  Tier 2 Planned \nOutage exemptions apply for both RA Hours and Non-RA Hours referenced in \nthis Schedule 53.\nIV.\nOperating Margin Calculation"},{"page":86,"startToken":21445,"endToken":21619,"text":"MISO\nSCHEDULE 53\nFERC Electric Tariff\nSeasonal Accredited Capacity Calculation\nSCHEDULES\n41.0.0, 42.0.0\nEffective On: October 18, 2026\nThe Operating Margin is determined using historical information to identify Seasonal RA \nHours and Annual RA Hours within the three (3) most recent periods beginning September 1st \nand ending August 31st.\nOperating Margin Equation\nWhere:\nFor all Resources online and under normal dispatch control.\nFor Resources where all of the following is true: (i) Resource is Offline; (ii) it’s cold-start \nlead-time is less than or equal to 12 hours; and (iii) is not on outage.\nV.\nSeasonal Accredited Capacity Calculation\nA.\nAnnual Average Offered Capacity (AAOC) will be determined for each Resource \nsubject to this Schedule 53 and utilized in the Seasonal Accredited Capacity \ncalculation as applicable. The AAOC for a Resource is calculated by averaging \nHourly Emergency Maximum Limit, or Targeted Demand Reduction Level for \nDRR-1, during the Annual RA Hours identified in Section III.B above for each \n12-month period within the three (3) most recent periods beginning September 1st"},{"page":87,"startToken":21619,"endToken":21906,"text":"MISO\nSCHEDULE 53\nFERC Electric Tariff\nSeasonal Accredited Capacity Calculation\nSCHEDULES\n41.0.0, 42.0.0\nEffective On: October 18, 2026\nand ending August 31st.  For any Annual RA Hour where a Resource is offline \nand the sum of the Resource’s Start-Up Time and Start-Up Notification Time \nOffers exceeds 24 hours, the Resource’s Hourly Emergency Maximum Limit, or \nTargeted Demand Reduction Level for DRR-1, will be set to zero (0).\nB.\nTier 1 Intermediate SAC (ISAC) is calculated as the sum of Hourly Emergency \nMaximum Limit, or Targeted Demand Reduction Level for DRR-1, during each \nof the Resource’s Seasonal Non-RA Hours, divided by the total number of \nSeasonal Non-RA Hours for each Season within the three (3) most recent periods \nbeginning September 1st and ending August 31st.\nC.\nTier 2 ISAC is calculated as the sum of Hourly Emergency Maximum Limit, or \nTargeted Demand Reduction Level for DDR-1, for the Resource’s Seasonal RA \nHours, plus the product of: Annual Average Offered Capacity multiplied by the \nSeasonal RA Hour Deficiency; divided by the total number of Seasonal RA Hours \nplus the Seasonal RA Hour Deficiency for each Season within the three (3) most \nrecent periods beginning September 1st and ending August 31st.  For any \nSeasonal RA Hour where a Resource is offline and the sum of the Resource’s \nStart-Up Time and Start-Up Notification Time Offers exceeds 24 hours, the \nResource’s Hourly Emergency Maximum Limit, or Targeted Demand Reduction \nLevel for DRR-1, will be set to zero (0).\nD.\nFor purposes of paragraphs A through C above, the Hourly Emergency Maximum \nLimit, or Targeted Demand Reduction Level for DRR-1, will be capped at the \ncurrently effective GVTC value of the Resource.  If a Resource is committed for a"},{"page":88,"startToken":21906,"endToken":22108,"text":"MISO\nSCHEDULE 53\nFERC Electric Tariff\nSeasonal Accredited Capacity Calculation\nSCHEDULES\n41.0.0, 42.0.0\nEffective On: October 18, 2026\nportion of its ICAP due to partial clearing, the partial clearing will not reduce the \nvalues in the Offers considered in the accreditation calculations, which will be \ncapped at the currently effective GVTC value of the Resource.\nE.\nIn the case of an increase in generating Capacity of a Generation Resource, for \npurposes of paragraphs A through C above, the historical values for Hourly \nEmergency Maximum Limit will be adjusted up for those hours prior to such \nincrease going into effect as set forth in the Business Practices Manual for \nResource Adequacy.\nF.\nRA Hours will receive a greater weight than non-RA hours. \nG.\nISAC will be calculated using the following equation:\nISAC = ISACTier1_value × ISACTier1_weighting + ISACTier2_value × ISACTier2_weighting\nWhere:\nWeighting by Planning Year\nTier\n2023- 2024 \nPlanning Year\n2024-2025 \nPlanning Year\n2025-2026 Planning \nYear and beyond\nISAC𝑇𝑖𝑒𝑟1_𝑤𝑒𝑖𝑔ℎ𝑡𝑖𝑛𝑔\n40%\n30%\n20%\nISAC𝑇𝑖𝑒𝑟2_𝑤𝑒𝑖𝑔ℎ𝑡𝑖𝑛𝑔\n60%\n70%\n80%\nH.\nA system-wide conversion ratio will be determined using the following equation:\nThe system-wide conversion ratio will be determined on an annual basis \nconsistent with the schedule established in the BPM."},{"page":89,"startToken":22108,"endToken":22358,"text":"MISO\nSCHEDULE 53\nFERC Electric Tariff\nSeasonal Accredited Capacity Calculation\nSCHEDULES\n41.0.0, 42.0.0\nEffective On: October 18, 2026\nI.\nSeasonal Accredited Capacity will be calculated for each Resource by multiplying \nits ISAC by the system-wide conversion ratio determined above using the \nfollowing equation:\nVI.\nNew Resources or Resources with Insufficient Performance Data\nNew Resources or existing Resources that do not have at least 60 days of Real-Time \noffered availability when designated for RAR over the last three (3) years for each Season \n(Summer, Fall, Winter, Spring) will have a SAC based on the Class Average SAC to ICAP Ratio \nfor its Resource type, not to exceed the identified Coincident Peak Demand forecast of the ZG \nAssociated Load, if any.  For Planning Year 2022/23 Schedule 53 Resources that were not \ncommitted under the annual construct during the period considered in the SAC calculations can \ndirect MISO to accredit them in accord with their offers as described in Section IV above instead \nof using a class average.  Resources on a Catastrophic Generator Outage during a Season they \nare designated for RAR may elect to use a SAC based on the Class Average SAC to ICAP Ratio \nfor its Resource type, not to exceed the identified Coincident Peak Demand forecast of the ZG \nAssociated Load, if any, the next time it is accredited for that Season provided all of its \ncommitted ZRCs were replaced with Uncleared ZRCs and that it has successfully returned from \nthe Catastrophic Generator Outage."},{"page":90,"startToken":22358,"endToken":22589,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nATTACHMENT X \n \nGENERATOR INTERCONNECTION PROCEDURES (GIP) \n \n \nSECTION 1. DEFINITIONS. \n \n10 kW Inverter Process shall mean the procedure for evaluating an Interconnection \nRequest for a certified inverter-based Small Generating Facility no larger than 10 kW that uses \nthe screen set forth in Section 14. \n \nAdverse System Impact shall mean the negative effects due to technical or operational \nlimits on conductors or equipment being exceeded that may compromise the safety and \nreliability of the electric system. \n \nAffected System(s) shall mean an electric transmission system or the electric system \nassociated with an Existing Generating Facility or of a higher queued Generating Facility, which \nis an electric system other than the Transmission Provider’s Transmission System that is affected \nby the Interconnection Request.  An Affected System may or may not be subject to FERC \njurisdiction. \n \nAffected System Interconnection Customer shall mean any entity that submits an \ninterconnection request for a Generating Facility to a transmission system other than \nTransmission Provider’s Transmission System that may cause the need for Affected System \nNetwork Upgrades on the Transmission Provider’s Transmission System. \n \nAffected System Network Upgrades shall mean the additions, modifications, and \nupgrades to Transmission Provider’s Transmission System required to accommodate Affected \nSystem Interconnection Customer’s proposed interconnection to a transmission system other \nthan Transmission Provider’s Transmission System."},{"page":91,"startToken":22589,"endToken":22858,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nAffected System Operator shall mean the entity that operates an Affected System. \n \nAffected System Queue Position shall mean the queue position of an Affected System \nInterconnection Customer in Transmission Provider’s interconnection queue relative to \nTransmission Provider’s Interconnection Customers’ Queue Position. \n \nAffected System Study shall mean the evaluation of Affected System Interconnection \nCustomers’ proposed interconnection(s) to a transmission system other than the Transmission \nProvider’s Transmission System that have an impact on Transmission Provider’s Transmission \nSystem, as described in Section 8 of this GIP. \n \nAffected System Study Agreement shall mean the agreement contained in Appendix 16 \nto this GIP that is made between Transmission Provider and host transmission provider, in \nabsence of JOA, JPA, or other agreement filed with the Commission, as noted in Section 8 of \nthis GIP. \n \nAffected System Study Report shall mean the report issued following completion of an \nAffected System Study. \n \nAffiliate shall mean, with respect to a corporation, partnership or other entity, each such \nother corporation, partnership or other entity that directly or indirectly, through one or more \nintermediaries, controls, is controlled by, or is under common control with, such corporation, \npartnership or other entity. \n \nAncillary Services shall mean those services that are necessary to support the \ntransmission of capacity and energy from resources to loads while maintaining reliable operation \nof the Transmission System in accordance with Good Utility Practice. \n \nApplicable Laws and Regulations shall mean all duly promulgated applicable federal, \nstate and local laws, regulations, rules, ordinances, codes, decrees, judgments, directives, or"},{"page":92,"startToken":22858,"endToken":23147,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\njudicial or administrative orders, permits and other duly authorized actions of any Governmental \nAuthority having jurisdiction over the Parties, their respective facilities and/or the respective \nservices they provide.  \n \nApplicable Reliability Standards shall mean the requirements and guidelines of the \nElectric Reliability Organization and the Balancing Authority Area of the Transmission System \nto which the Generating Facility is directly interconnected. \n \nAutomatic Withdrawal Penalty shall mean the penalty assessed by Transmission \nProvider to an Interconnection Customer that chooses to withdraw or is deemed to have \nwithdrawn its Interconnection Request from Transmission Provider’s interconnection queue in \ncertain specified circumstances.  The calculation of the Withdrawal Penalty is set forth in Section \n7.6.2.1.1 of this GIP. \n \nBalancing Authority shall mean an entity that integrates resource plans ahead of time, \nmaintains demand and resource balance within a Balancing Authority Area, and supports \ninterconnection frequency in real time. \n \nBalancing Authority Area shall mean the collection of generation, transmission, and \nloads within the metered boundaries of the Balancing Authority.  The Balancing Authority \nmaintains load-resource balance within this area. \n \nBase Case shall mean the base case power flow, short circuit, and stability databases \nused for the Interconnection Studies by Transmission Provider or Interconnection Customer. \n \nBase Case Data shall mean base case power flow, short circuit and stability databases, \nincluding all underlying assumptions, and contingency lists.  Such databases and lists, hereinafter \nreferred to as Base Cases, shall include all (1) generation projects and (2) transmission projects, \nincluding merchant transmission projects that are proposed for the Transmission System for \nwhich a transmission expansion plan has been submitted and approved by the MISO Board."},{"page":93,"startToken":23147,"endToken":23409,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \nBreach shall mean the failure of a Party to perform or observe any material term or \ncondition of the Generator Interconnection Agreement. \n \nBreaching Party shall mean a Party that is in Breach of the Generator Interconnection \nAgreement. \n \nBusiness Day shall mean Monday through Friday, excluding Federal Holidays. \n \nCalendar Day shall mean any day including Saturday, Sunday or a Federal Holiday. In \nthe event that a period specified in this GIP is calculated in Calendar Days ends on a non-\nbusiness day, such period shall be deemed to conclude on the following business day. \n \nCluster shall mean a group of one or more Interconnection Requests that are studied \ntogether for the purpose of conducting a Group Study. \n \nCommercial Operation shall mean the status of a Generating Facility that has \ncommenced generating electricity for sale, excluding electricity generated during Trial \nOperation. \n \nCommercial Operation Date (COD) of a unit shall mean the date on which the \nGenerating Facility commences Commercial Operation as agreed by the Parties pursuant to \nAppendix E to the Generator Interconnection Agreement. \n \nCommitment Projection shall mean a projection of the number of MW expected to \ncommit to the JTIQ Portfolio from ERAS and all DPP study clusters that already have passed \nDP1 as described in Section 9.4.2.e.ii of Rate Schedule 6 (MISO SPP-JOA).  \n \nCommon Use Upgrade shall mean an Interconnection Facility, Network Upgrade, \nSystem Protection Facility, or any other classified addition, alteration, or improvement on the"},{"page":94,"startToken":23409,"endToken":23727,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nTransmission System or the transmission system of an Affected System, not classified under \nAttachment FF as a Baseline Reliability Project, Market Efficiency Project, or Multi-Value \nProject, that is needed for the interconnection of multiple Interconnection Customers’ Generating \nFacilities and which is the shared responsibility of such Interconnection Customers.   \n \nConfidential Information shall mean any proprietary or commercially or competitively \nsensitive information, trade secret or information regarding a plan, specification, pattern, \nprocedure, design, device, list, concept, policy or compilation relating to the present or planned \nbusiness of a Party, or any other information as specified in Article 22 of the GIA, which is \ndesignated as confidential by the Party supplying the information, whether conveyed orally, \nelectronically, in writing, through inspection, or otherwise, that is received by another Party. \n \nConnection Facilities shall mean the Transmission Owner’s Connection Facilities and \nthe MHVDC Connection Customer’s Connection Facilities, as defined in the MHCP. \n \nContingent Facilities shall mean those unbuilt Interconnection Facilities and Network \nUpgrades upon which the Interconnection Request’s costs, timing and study findings are \ndependent, and if delayed or not built, could cause a need for restudies of the Interconnection \nRequest or a reassessment of the Interconnection Facilities and/or Network Upgrades and/or \ncosts and timing.  Contingent Facilities may include facilities identified in MTEP that if delayed \nor not built could impact the timing of the Interconnection Request. \n \nCustomer Engagement Window shall mean the time period prior to the start of \nDefinitive Planning Phase I set forth in Section 3.3.4 of this GIP. \n \nDefault shall mean the failure of a Breaching Party to cure its Breach in accordance with \nArticle 17 of the Generator Interconnection Agreement. \n \nDefinitive Planning Phase shall mean the Generator Interconnection Procedures process \nwhich leads to a Generator Interconnection Agreement.  An Interconnection Customer enters the"},{"page":95,"startToken":23727,"endToken":24062,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nDefinitive Planning Phase pursuant to GIP Section 7.2.  The Definitive Planning Phase includes \nthree distinct phases (Definitive Planning Phases I, II, and III) pursuant to Section 7 of the \nGenerator Interconnection Procedures. \n \nDefinitive Planning Phase Queue Position shall mean the order of a valid \nInterconnection Request, relative to all other pending valid Interconnection Requests, in the \nDefinitive Planning Phase.  The Definitive Planning Phase Queue Position is established based \nupon the date of initial submission of the Interconnection Request provided that the \nInterconnection Request subsequently satisfies all of the requirements of GIP Section 7.2 of the \nGenerator Interconnection Procedures to enter the Definitive Planning Phase and is accepted as \nvalid by the Transmission Provider.  All Interconnection Requests within the same Definitive \nPlanning Phase cycle shall have equal priority (i.e. similarly queued). \n \nDemonstrated Capability shall mean the continuous net real power output that the \nGenerating Facility is required to demonstrate in compliance with Applicable Reliability \nStandards.   \n \nDispute Resolution shall mean the procedure for resolution of a dispute between or \namong the Parties in which they will first attempt to resolve the dispute on an informal basis.  \n \nDistribution System shall mean the Transmission Owner’s facilities and equipment, or \nthe Distribution System of another party that is interconnected with Transmission Owner’s \nTransmission System, if any, connected to the Transmission System, over which facilities \nTransmission Service or Wholesale Distribution Service under the Tariff is available at the time \nInterconnection Customer has requested interconnection of a Generating Facility for the purpose \nof either transmitting electric energy in interstate commerce or selling electric energy at \nwholesale in interstate commerce and which are used to transmit electricity to ultimate usage \npoints such as homes and industries directly from nearby generators or from interchanges with \nhigher voltage transmission networks which transport bulk power over longer distances.  The \nvoltage levels at which distribution systems operate differ among Local Balancing Authorities"},{"page":96,"startToken":24062,"endToken":24400,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nand other entities owning distribution facilities interconnected to the Transmission System.   \n \nDistribution Upgrades shall mean the additions, modifications, and upgrades to the \nDistribution System at or beyond the Point of Interconnection to facilitate interconnection of the \nGenerating Facility and render the delivery service necessary to affect Interconnection \nCustomer’s wholesale sale of electricity in interstate commerce.  Distribution Upgrades do not \ninclude Interconnection Facilities. \n \nEffective Date shall mean the date on which the Generator Interconnection Agreement \nbecomes effective upon execution by the Parties subject to acceptance by the Commission, or if \nfiled unexecuted, upon the date specified by the Commission. \n \nElectric Reliability Organization shall mean the North American Electric Reliability \nCorporation or its successor organization. \n \nEmergency Condition shall mean a condition or situation:  (1) that in the reasonable \njudgment of the Party making the claim is imminently likely to endanger, or is contributing to \nthe endangerment of, life, property, or public health and safety; or (2) that, in the case of either \nTransmission Provider or Transmission Owner, is imminently likely (as determined in a non-\ndiscriminatory manner) to cause a material adverse effect on the security of, or damage to the \nTransmission System, Transmission Owner’s Interconnection Facilities or the electric systems of \nothers to which the Transmission System is directly connected; or (3) that, in the case of \nInterconnection Customer, is imminently likely (as determined in a non-discriminatory manner) \nto cause a material adverse effect on the security of, or damage to, the Generating Facility or \nInterconnection Customer’s Interconnection Facilities.  System restoration and blackstart shall be \nconsidered Emergency Conditions; provided that Interconnection Customer is not obligated by \nthe Generator Interconnection Agreement to possess blackstart capability.  Any condition or \nsituation that results from lack of sufficient generating capacity to meet load requirements or that \nresults solely from economic conditions shall not constitute an Emergency Condition, unless one \nof the enumerated conditions or situations identified in this definition also exists."},{"page":97,"startToken":24400,"endToken":24660,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \nEnergy Displacement Agreement shall mean an agreement between an Interconnection \nCustomer with an Existing Generating Facility on the Transmission Provider’s Transmission \nSystem and an Interconnection Customer with a proposed Generating Facility seeking to \ninterconnect with Surplus Interconnection Service.  The Energy Displacement Agreement \nspecifies the term of operation, the Generating Facility Interconnection Service limit, and the \nmode of operation for energy production (common or singular operation). \n \nEnergy Resource Interconnection Service (ER Interconnection Service) shall mean \nan Interconnection Service that allows Interconnection Customer to connect its Generating \nFacility to the Transmission System or Distribution System, as applicable, to be eligible to \ndeliver the Generating Facility’s electric output using the existing firm or non-firm capacity of \nthe Transmission System on an as available basis.  Energy Resource Interconnection Service \ndoes not convey transmission service. \n \nEngineering & Procurement (E&P) Agreement shall mean an agreement that \nauthorizes Transmission Owner to begin engineering and procurement of long lead-time items \nnecessary for the establishment of the interconnection in order to advance the implementation of \nthe Interconnection Request. \n \nEnvironmental Law shall mean Applicable Laws or Regulations relating to pollution or \nprotection of the environment or natural resources.  \n \nExisting Generating Facility shall mean a Generating Facility that is either under \nconstruction or is in service, and has an unsuspended interconnection agreement with its host \ntransmission provider. \n \nExpanded Scope Analysis shall mean the analysis described in Section 9.4.2.d.iv.a of \nRate Schedule 6 (MISO-SPP JOA)."},{"page":98,"startToken":24660,"endToken":24958,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nExpedited Resource Addition Study (ERAS) shall mean the temporary procedure for \nexpediting interconnection projects identified for claimed resource adequacy and/or reliability \nneeds. \n \nExpedited Resource Addition Study (ERAS) Quarterly Study Period shall mean the \nperiod of time in which ERAS Interconnection Requests are submitted to the Transmission \nProvider and compiled for study.  There are four study periods in a year with the following start \nand end dates: \nQuarter 1: The first Business Day of March through the last Business Day of May; \nQuarter 2: The first Business Day of June through the last Business Day of August; \nQuarter 3: The first Business Day of September through the last Business Day of \nNovember; \nQuarter 4: The first Business Day of December through the last Business Day of \nFebruary. \n \nExpedited Generator Interconnection Agreement (EGIA) shall mean the \ninterconnection agreement for the Expedited Resource Addition Study established between the \nTransmission Provider and/or the Transmission Owner and the Interconnection Customer as set \nforth in Section 3.9 of this Attachment X.  This agreement shall take the form of the \nTransmission Provider’s pro forma Generator Interconnection Agreement modified for the \nExpedited Resource Addition Study.  Unless otherwise provided in the GIP, all requirements \napplicable to the pro forma Generator Interconnection Agreement shall apply to the Expedited \nGenerator Interconnection Agreement. \n \nFacilities Construction Agreement (FCA) shall mean the form of facilities construction \nagreement, set forth in Appendix 8 to these Generator Interconnection Procedures.  The FCA \nshall be used when an Interconnection Customer or an Affected System Interconnection \nCustomer causes the need for the construction of Network Upgrades, Affected System Network \nUpgrades, or System Protection Facilities on the transmission system of the Transmission \nProvider."},{"page":99,"startToken":24958,"endToken":25254,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \nFast Track Process shall mean the procedure for evaluating an Interconnection Request \nfor a certified Small Generating Facility no larger than five MW that includes the screen set forth \nin Section 14, customer options meeting, and optional supplemental review. \n \nFederal Holiday shall mean a Federal Reserve Bank holiday for a Party that has its \nprincipal place of business in the United States and a Canadian Federal or Provincial banking \nholiday for a Party that has its principal place of business located in Canada. \n \nFederal Power Act shall mean the Federal Power Act, as amended, 16 U.S.C. §§ 791a \net seq. \n \nFERC shall mean the Federal Energy Regulatory Commission, also known as \nCommission, or its successor. \n \nFinal System Impact Study shall mean the Interconnection System Impact Study \nperformed during Definitive Planning Phase III. \n \nForce Majeure shall mean any act of God, labor disturbance, act of the public enemy, \nwar, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or \nequipment, any order, regulation or restriction imposed by governmental, military or lawfully \nestablished civilian authorities, or any other cause beyond a Party’s control.  A Force Majeure \nevent does not include an act of negligence or intentional wrongdoing by the Party claiming \nForce Majeure. \n \nGenerating Facility shall mean Interconnection Customer’s device(s) for the production \nand/or storage for later injection of electricity identified in the Interconnection Request, but shall \nnot include the Interconnection Customer’s Interconnection Facilities and shall not include a \nSATOA as defined in Module A. A Generating Facility consists of one or more generating \nunit(s) and/or storage device(s) which usually can operate independently and be brought online"},{"page":100,"startToken":25254,"endToken":25526,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nor taken offline individually. \n \nGenerating Facility Capacity shall mean the net capacity of the Generating Facility and \nthe aggregate net capacity of the Generating Facility where it includes more than one device for \nthe production and/or storage for later injection of electricity. \n \nGenerating Facility Modification shall mean modification to an Existing Generating \nFacility, including comparable replacement of only a portion of the equipment at the Existing \nGenerating Facility. \n \nGenerating Facility Replacement shall mean replacement of one or more generating \nunits and/or storage devices at an Existing Generating Facility with one or more generating units \nor storage devices at the same electrical Point of Interconnection as those being decommissioned \nand electrically disconnected.  \n \nGenerator Interconnection Agreement (GIA) shall mean the form of interconnection \nagreement, set forth in Appendix 6 to these Generator Interconnection Procedures. \n \nGenerator Interconnection Procedures (GIP) shall mean the interconnection \nprocedures set forth herein. \n \nGenerator Upgrades shall mean the additions, modifications, and upgrades to the \nelectric system of an Existing Generating Facility or of a higher queued Generating Facility at or \nbeyond the Point of Interconnection to facilitate interconnection of the Generating Facility and \nrender the Transmission Service necessary to affect Interconnection Customer’s wholesale sale \nof electricity in interstate commerce. \n \nGood Utility Practice shall mean any of the practices, methods and acts engaged in or \napproved by a significant portion of the electric industry during the relevant time period, or any \nof the practices, methods and acts which, in the exercise of reasonable judgment in light of the"},{"page":101,"startToken":25526,"endToken":25834,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nfacts known at the time the decision was made, could have been expected to accomplish the \ndesired result at a reasonable cost consistent with good business practices, reliability, safety and \nexpedition.  Good Utility Practice is not intended to be limited to the optimum practice, method, \nor act to the exclusion of all others, but rather to be acceptable practices, methods, or acts \ngenerally accepted in the region. \n \nGovernmental Authority shall mean any federal, state, local or other governmental \nregulatory or administrative agency, court, commission, department, board, or other \ngovernmental subdivision, legislature, rulemaking board, tribunal, or other governmental \nauthority having jurisdiction over the Parties, their respective facilities, or the respective services \nthey provide, and exercising or entitled to exercise any administrative, executive, police, or \ntaxing authority or power; provided, however, that such term does not include Interconnection \nCustomer, Transmission Provider, Transmission Owner, or any Affiliate thereof. \n \nGroup Restudy shall mean a restudy of a Group Study conducted pursuant to Section \n7.5 of this GIP. \n \nGroup Study(ies) shall mean the evaluation of one or more Interconnection Requests \nwithin a Cluster as described in Section 7 of this GIP.  Group Studies are divided into phases as \ndescribed in section 7.3 of this GIP. \n \nHazardous Substances shall mean any chemicals, materials or substances defined as or \nincluded in the definition of “hazardous substances,” “hazardous wastes,” “hazardous materials,” \n“hazardous constituents,” “restricted hazardous materials,” “extremely hazardous substances,” \n“toxic substances,” “radioactive substances,” “contaminants,” “pollutants,” “toxic pollutants” or \nwords of similar meaning and regulatory effect under any applicable Environmental Law, or any \nother chemical, material or substance, exposure to which is prohibited, limited or regulated by \nany applicable Environmental Law.  \n \nHVDC Facilities shall mean the high voltage direct current transmission facilities,"},{"page":102,"startToken":25834,"endToken":26128,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nincluding associated alternating current facilities, if any, that are subject to Section 27A of the \nTariff and that are specifically identified in (i) any Agency Agreement pertaining to such \nfacilities between Transmission Provider and Transmission Owner that owns or operates such \nfacilities, or (ii) in any other arrangement that permits or will permit Transmission Provider to \nprovide HVDC Service over such facilities as set forth in Section 27A of the Tariff. \n \nHVDC Service shall mean Firm and Non-Firm Point-To-Point Transmission Service \nprovided by Transmission Provider on HVDC Facilities pursuant to Section 27A of the Tariff. \n \nInitial Synchronization Date shall mean the date upon which the Generating Facility is \ninitially synchronized and upon which Trial Operation begins. \n \nInjection Rights shall mean the Transmission Provider’s pre-certification of the \nTransmission System’s capability to receive capacity and energy from the MHVDC \nTransmission Line at the requested Point of Connection, and in the specified MW quantity, \nwithout degrading the reliability of the Transmission System, as described in Section 16 of the \nGIP and Section 3.2.3 of the MHCP. \n \nIn-Service Date (ISD) shall mean the date upon which Interconnection Customer \nreasonably expects it will be ready to begin use of the Transmission Owner’s Interconnection \nFacilities to obtain back feed power. \n \nInterconnection Customer shall mean any entity, including Transmission Provider, \nTransmission Owner or any of the Affiliates or subsidiaries of either, that proposes to \ninterconnect its Generating Facility with the Transmission System. \n \nInterconnection Customer Decision Point I shall mean the time period beginning when \nthe Interconnection Customer is provided the Preliminary System Impact Study results including \ncost estimates for upgrades and concludes after fifteen (15) Business Days."},{"page":103,"startToken":26128,"endToken":26430,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nInterconnection Customer Decision Point II shall mean the time period beginning \nwhen the Interconnection Customer is provided the Revised System Impact Study results \nincluding cost estimates for upgrades and concludes after fifteen (15) Business Days. \n \nInterconnection Customer’s Interconnection Facilities (ICIF) shall mean all facilities \nand equipment, as identified in Appendix A of the Generator Interconnection Agreement, that \nare located between the Generating Facility and the Point of Change of Ownership, including \nany modification, addition, or upgrades to such facilities and equipment necessary to physically \nand electrically interconnect the Generating Facility to the Transmission System or Distribution \nSystem, as applicable.  Interconnection Customer’s Interconnection Facilities are sole use \nfacilities. \n \nInterconnection Facilities shall mean the Transmission Owner’s Interconnection \nFacilities and the Interconnection Customer’s Interconnection Facilities.  Collectively, \nInterconnection Facilities include all facilities and equipment between the Generating Facility \nand the Point of Interconnection, including any modification, additions or upgrades that are \nnecessary to physically and electrically interconnect the Generating Facility to the Transmission \nSystem.  Interconnection Facilities shall not include Distribution Upgrades, Generator Upgrades, \nStand Alone Network Upgrades or Network Upgrades. \n \nInterconnection Facilities Study(ies) shall mean a study conducted by Transmission \nOwner, or its agent, for Interconnection Customer(s)  to determine a list of facilities (including \nInterconnection Customer’s Interconnection Facilities or Affected System Interconnection \nCustomer’s interconnection facilities, Transmission Owner’s Interconnection Facilities, System \nProtection Facilities, and if such upgrades have been determined, Network Upgrades, \nDistribution Upgrades, Generator Upgrades, Common Use Upgrades, and Affected System \nNetwork Upgrades, as identified in the Interconnection System Impact Study, Affected System \nStudy, or Affected System Operator’s applicable study), the cost of those facilities, and the time \nrequired to interconnect with the Transmission System or the Affected System Operator’s \ntransmission system."},{"page":104,"startToken":26430,"endToken":26757,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \nInterconnection Request shall mean (1) an Interconnection Customer’s request, in the \nform of Appendix 1 to the Generator Interconnection Procedures, to interconnect a new \nGenerating Facility or a request for the Expedited Resource Addition Study for a new generation \ncapacity, or to increase the capacity of, or make a Material Modification to the operating \ncharacteristics of, an Existing Generating Facility that is interconnected with the Transmission \nSystem, or to interconnect an Existing Generating Facility that is external to the Transmission \nSystem, or to change Energy Resource Interconnection Service to Network Resource \nInterconnection Service for an Existing Generating Facility; or (2) an MHVDC Connection \nCustomer’s request, in the form of Appendix 1 to the Generator Interconnection Procedures, to \nobtain Injection Rights. \n \nInterconnection Service shall mean the service provided by Transmission Provider \nassociated with interconnecting the Generating Facility to the Transmission System, or external \nhost transmission provider if applicable, and enabling it to receive electric energy and capacity \nfrom the Generating Facility at the Point of Interconnection pursuant to the terms of the \nGenerator Interconnection Agreement or Point of Delivery as set forth in Service Agreement for \nNetwork Resource Interconnection Service for an External Generating Facility and, if applicable, \nthe Tariff. \n \nInterconnection Study (or Study) shall mean any of the following studies: the \nReplacement Impact Study, the Reliability Assessment Study, the Optional Interconnection \nStudy, the Interconnection System Impact Study including evaluations for Surplus \nInterconnection Service, and the Interconnection Facilities Study, or the Restudy of any of the \nabove, described in the Generator Interconnection Procedures. \n \nInterconnection System Impact Study shall mean an engineering study that evaluates \nthe impact of the proposed interconnection on the safety and reliability of Transmission System \nand, if applicable, an Affected System.  The study shall identify and detail the system impacts \nthat would result if the Generating Facility were interconnected without project modifications or"},{"page":105,"startToken":26757,"endToken":26990,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nsystem modifications, or to study potential impacts, including but not limited to those identified \nin the Scoping Meeting as described in the Generator Interconnection Procedures. \n \nInterconnection Study Agreement shall mean the forms of agreement contained in \nAttachment B to Appendix 1 of the Generator Interconnection Procedures for conducting all \nstudies required by the Generator Interconnection Procedures. \n \nIRS shall mean the Internal Revenue Service. \n \nJoint Operating Agreement (“JOA”) shall mean an agreement between adjacent \nbalancing authorities or transmission providers for the coordination of operations. \n \nJoint Planning Agreement (“JPA”) shall mean an agreement between adjacent \nbalancing authorities or transmission providers for the coordination of planning. \n \nJoint Operating Agreement between the Midcontinent Independent System \nOperator, Inc. and Southwest Power Pool, Inc. (MISO-SPP JOA) shall mean Rate Schedule \n6 to the MISO Tariff. \n \nJoint Targeted Interconnection Queue (JTIQ) shall refer to the study and processes \ndescribed in Section 9.4.2 of Rate Schedule 6 (MISO-SPP JOA). \n \nJoint Targeted Interconnection Queue Study (“JTIQ Study”) shall mean a \ntransmission planning study conducted jointly by SPP and MISO to facilitate the interconnection \nof new generator capacity in both Parties’ regions. \n \nJTIQ Commitment Group Member shall mean any JTIQ Commitment Group Member \nincluded in a Commitment Group consistent with Section 9.4 of Rate Schedule 6 (MISO-SPP \nJOA)."},{"page":106,"startToken":26990,"endToken":27324,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nJTIQ Commitment Group or Commitment Group shall mean a group of JTIQ \nCommitment Group Members that have executed a JTIQ Generator Interconnection Agreement \nwithin the twelve (12) month period ending April 30th of each year.  The Commitment Group \nshall also include JTIQ Commitment Group Members for which a JTIQ Generator \nInterconnection Agreement has been filed unexecuted by SPP or the Transmission Provider and \nthe Commission has accepted the agreement within the twelve (12) month period ending April \n30th of each year. \n \nJTIQ Generator Charge shall mean the charge to JTIQ Commitment Group Members \nto recover the JTIQ Commitment Group Member’s share of the JTIQ Monthly Revenue \nRequirement for each of the JTIQ Upgrades in the JTIQ Portfolio in the Transmission Provider’s \nRegion. \n \nJTIQ Participation Group shall mean the group of Interconnection Requests that shall \nconsist of all interconnection customers included in the JTIQ Screening Groups whose \ninterconnection request meets the distribution factor and impact criteria specified in Section \n9.4.2(d)((ii) of Rate Schedule 6 (MISO-SPP JOA). \n \nJTIQ Portfolio shall mean a group of JTIQ Upgrades identified pursuant to Section 9.4 \nof Rate Schedule 6 (MISO-SPP JOA). \n \nJTIQ Screening Group shall mean a group of MISO Interconnection Customers and \nSPP interconnection customers whose Interconnection Requests will be screened for inclusion in \na JTIQ Participation Group. The JTIQ Screening Group shall consist of all interconnection \ncustomers who have submitted interconnection requests into a MISO ERAS, SPP ERAS, DPP \nstudy cluster, or SPP DISIS study cluster that: (1) has a study commencement or kick off date \nthat is after the date that the Parties’ respective Boards of Directors have approved a JTIQ \nPortfolio; and (2) has not commenced DPP Phase I, a MISO ERAS, the SPP ERAS, or DISIS \nPhase One studies pursuant to each party’s OATT as of the date that the Parties have declared \nthe JTIQ Portfolio fully subscribed."},{"page":107,"startToken":27324,"endToken":27643,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \nJTIQ Service Agreements shall mean the JTIQ Commitment Agreement attached to the \nMISO GIA as Appendix 17 and the SPP’s pro forma agreement(s)  that obligate interconnection \ncustomers to provide security for and  pay the JTIQ Generator Charge for JTIQ Network \nUpgrades included in the applicable JTIQ Portfolio. \n \nJTIQ Upgrade shall mean a Network Upgrade included in a JTIQ portfolio pursuant to \nSection 9.4 of Rate Schedule 6 (MISO-SPP JOA).  \n \nLocal Balancing Authority shall mean an operational entity or a Joint Registration \nOrganization which is (i) responsible for compliance with the subset of the Electric Reliability \nOrganization Balancing Authority Reliability Standards defined in the Balancing Authority \nAgreement for their local area within the MISO Balancing Authority Area, (ii) a Party to \nBalancing Authority Agreement, excluding MISO, and (iii) provided in the Balancing Authority \nAgreement. \n \nLocal Resource Zone (LRZ) shall mean a geographic area within the Transmission \nProvider Region that is prescribed by the Transmission Provider, based upon the criteria in \nSection 68A.3, to address congestion that limits Planning Resource deliverability. \n \nLoss shall mean any and all damages, losses, claims, including claims and actions \nrelating to injury to or death of any person or damage to property, demand, suits, recoveries, \ncosts and expenses, court costs, attorney fees, and all other obligations by or to third parties, \narising out of or resulting from the other Party’s performance, or non-performance of its \nobligations under the Generator Interconnection Agreement on behalf of the indemnifying Party, \nexcept in cases of gross negligence or intentional wrongdoing, by the indemnified party. \n \nMaterial Modification shall mean: (1) modification to an Interconnection Request in the \nqueue that has a material adverse impact on the cost or timing of any other Interconnection \nRequest with an equal or later queue priority date; or a Qualified Change."},{"page":108,"startToken":27643,"endToken":27907,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \nMerchant HVDC Connection Customer (MHVDC Connection Customer) shall mean \nany entity that proposes to interconnect an MHVDC Transmission Line with the Transmission \nSystem, as set forth in the MHCP. \n \nMerchant HVDC Connection Procedures (MHCP) shall mean the connection \nprocedures set forth in Attachment GGG to the Tariff. \n \nMerchant HVDC Transmission Connection Request (MHVDC Transmission \nConnection Request) shall mean an MHVDC Connection Customer’s request, in the form of \nAppendix 1 to the MHCP to interconnect a new MHVDC Transmission Line, increase the \ncapacity of an existing MHVDC Transmission Line, or make a substantial modification to the \noperating characteristics of an existing MHVDC Transmission Line. \n \nMerchant HVDC Transmission Connection Agreement (Transmission Connection \nAgreement or TCA) shall mean the form of the transmission connection agreement for \nmerchant HVDC transmission facilities set forth in Appendix 2 to the MHCP. \n \nMerchant HVDC Transmission Line (MHVDC Transmission Line) shall mean the \nmerchant high voltage direct current transmission line external to the Transmission System that \nis proposed for connection to the Transmission System, as defined in the MHCP. \n \nMetering Equipment shall mean all metering equipment installed or to be installed at \nthe Generating Facility, Interconnection Customer’s Interconnection Facilities, and/or \nTransmission Owner's Interconnection Facilities pursuant to the Generator Interconnection \nAgreement at the metering points, including but not limited to instrument transformers, MWh-\nmeters, data acquisition equipment, transducers, remote terminal unit, communications \nequipment, phone lines, and fiber optics. \n \nMonitoring and Consent Agreement shall mean an agreement that defines the terms"},{"page":109,"startToken":27907,"endToken":28210,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nand conditions applicable to a Generating Facility acquiring Surplus Interconnection Service.  \nThe Monitoring and Consent Agreement will list the roles and responsibilities of an \nInterconnection Customer seeking to interconnect with Surplus Interconnection Service and \nTransmission Owner to maintain the total output of the Generating Facility inside the parameters \ndelineated in the GIA. \n \nMulti-Party Facilities Construction Agreement (MPFCA) shall mean the form of \nfacilities construction agreement, set forth in Appendix 9 to these Generator Interconnection \nProcedures.  The MPFCA shall be used when multiple Interconnection Requests or \ninterconnection requests from Affected System Interconnection Customers cause the need for the \nconstruction of Common Use Upgrades on the Transmission System and share cost \nresponsibility for such Common Use Upgrades.   \n \nNetwork Customer shall have that meaning as provided in the Tariff. \n \nNetwork Resource shall mean any designated generating resource owned, purchased, or \nleased by a Network Customer under the Tariff.  Network Resources do not include any \nresource, or any portion thereof, that is committed for sale to third parties or otherwise cannot be \ncalled upon to meet the Network Customer’s Network Load on a non-interruptible basis. \n \nNetwork Resource Interconnection Service (NR Interconnection Service) shall mean \nan Interconnection Service that allows Interconnection Customer to integrate its Generating \nFacility with the Transmission System in the same manner as for any Generating Facility being \ndesignated as a Network Resource.  Network Resource Interconnection Service does not convey \ntransmission service.  Network Resource Interconnection Service shall include any network \nresource interconnection service established under an agreement with, or the tariff of, a \nTransmission Owner prior to integration into MISO, that is determined to be deliverable through \nthe integration deliverability study process. \n \nNetwork Upgrades shall mean the additions, modifications, and upgrades to the"},{"page":110,"startToken":28210,"endToken":28486,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nTransmission System required at or beyond the point at which the Interconnection Facilities \nconnect to the Transmission System or Distribution System, as applicable, to accommodate the \ninterconnection of the Generating Facility(ies) to the Transmission System.  Network Upgrades \nshall not include any HVDC Facility Upgrades. \n \nNotice of Dispute shall mean a written notice of a dispute or claim that arises out of or in \nconnection with the Generator Interconnection Agreement or its performance. \n \nOptional Interconnection Study shall mean a sensitivity analysis based on assumptions \nspecified by Interconnection Customer in the Optional Interconnection Study Agreement. \n \nOptional Interconnection Study Agreement shall mean the form of agreement \ncontained in Appendix 5 of the Generator Interconnection Procedures for conducting the \nOptional Interconnection Study. \n \nOutage Transfer Distribution Factor (OTDF) Outage Transfer Distribution Factor, as \ndefined by the Electric Reliability Organization. \n \nParty or Parties shall mean Transmission Provider, Transmission Owner, \nInterconnection Customer, or any combination of the above. \n \nPermissible Technological Advancement shall mean advancements to turbines, \ninverters, plant supervisory controls, excitation systems, or other technological advancements \nsubmitted to the Transmission Provider prior to the issuance of a draft Generator Interconnection \nAgreement for such project provided that such advancements does not: (1) degrade the electrical \ncharacteristics of the generating equipment; (2) does not cause any material adverse impact on the \nTransmission System with regard to short circuit capability limits, steady-state thermal and \nvoltage limits, or dynamic system stability and response; (3) does not increase the installed \ncapacity of the Generating Facility; or (4) change the fuel source of the proposed Generating"},{"page":111,"startToken":28486,"endToken":28712,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nFacility.   \n \nPoint of Change of Ownership (PCO) shall mean the point, as set forth in Appendix A \nto the Generator Interconnection Agreement, where the Interconnection Customer’s \nInterconnection Facilities connect to the Transmission Owner’s Interconnection Facilities. \n \nPoint of Connection shall mean the point, as set forth in an MHVDC Transmission \nConnection Request, where the MHVDC Transmission Line connects to the Transmission \nSystem. \n \nPoint of Interconnection (POI) shall mean the point, as set forth in Appendix A of the \nGIA, where the Interconnection Facilities connect to the Transmission System. \n \nPoint(s) of Withdrawal (POW) shall mean the point(s) where a non-transmission \nfacility that is used to withdraw Energy from the Transmission System to serve Load connects to \nthe Transmission System. \n \nPotential MW Total shall mean a projection of the number of MW that may commit to \nthe JTIQ Portfolio from all ERAS and study clusters to date, including the current study \ncluster(s).   \n \nPower Transfer Distribution Factor (PTDF) Power Transfer Distribution Factor, as \ndefined by the Electric Reliability Organization. \n \nPreliminary System Impact Study shall mean the Interconnection System Impact Study \nperformed during Definitive Planning Phase I \n \nPre-Queue Phase shall mean Interconnection Customer outreach and education effort \nundertaken prior to the submission of the Interconnection Request."},{"page":112,"startToken":28712,"endToken":29028,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nProportional Impact Method shall mean a technical analysis conducted by \nTransmission Provider to determine the degree to which each Generating Facility in the Group \nStudy contributes to the need for a specific Network Upgrade. \n \nProvisional Generator Interconnection Agreement shall mean the interconnection \nagreement for Provisional Interconnection Service established between the Transmission \nProvider and/or the Transmission Owner and the Interconnection Customer as set forth in \nSection 7.9 of this Attachment X.  This agreement shall take the form of the Generator \nInterconnection Agreement modified for provisional purposes.  Unless otherwise provided in the \nGIP, all requirements applicable to the Generator Interconnection Agreement shall apply to the \nProvisional Generator Interconnection Agreement. \n \nProvisional Interconnection Service shall mean Interconnection Service provided by \nthe Transmission Provider associated with interconnecting the Interconnection Customer’s \nGenerating Facility to the Transmission Provider’s Transmission System and enabling that \nTransmission System to receive electric energy and capacity from the Generating Facility at the \nPoint of Interconnection, pursuant to the terms of the Provisional Generator Interconnection \nAgreement and the Tariff. \n \nProvisional Interconnection Study shall mean an engineering study, performed at \nInterconnection Customer’s request, as a condition to entering into a Provisional Generator \nInterconnection Agreement, that evaluates the impact of the proposed interconnection on the \nsafety and reliability of the Transmission System and, if applicable, any Affected System.  The \nstudy shall identify and detail the impacts on the Transmission System and, if applicable, an \nAffected System, from stability, short circuit, and voltage issues that would result if the \nGenerating Facility were interconnected without project modifications or system modifications. \n \nQualified Change shall mean a planned modification to an Existing Generating Facility \nthat is undergoing evaluation for a Generating Facility Modification or Generating Facility \nReplacement, and has a material adverse impact on the Transmission System with respect to: i)"},{"page":113,"startToken":29028,"endToken":29340,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nsteady-state thermal or voltage limits, ii) dynamic system stability and response, or iii) short-\ncircuit capability limit; compared to the impacts of the Existing Generating Facility prior to the \nmodification or replacement. \n \nQueue Position shall mean the order of a valid Interconnection Request, relative to all \nother pending valid Interconnection Requests.  The Queue Position is established based upon the \ndate and time of initial receipt of the Interconnection Request by Transmission Provider pursuant \nto section 4.1 of this GIP. \n \nReasonable Efforts shall mean, with respect to an action required to be attempted or \ntaken by a Party under the Generator Interconnection Agreement, efforts that are timely and \nconsistent with Good Utility Practice and are otherwise substantially equivalent to those a Party \nwould use to protect its own interests. \n \nRelevant Electric Retail Regulatory Authority (RERRA) shall mean an entity that has \njurisdiction over and establishes prices and/or policies for providers of retail electric service to \nend-customers, such as the city council for a municipal utility, the governing board of a \ncooperative utility, the state public utility commission or any such entity. \n \nReliability Assessment Study shall mean an engineering study that evaluates the impact \nof a proposed Generating Facility Replacement on the reliability of Transmission System during \nthe time period between the date that the Existing Generating Facility ceases commercial \noperations and the Commercial Operation Date of the Replacement Generating Facility. \n \nReplacement Generating Facility shall mean a Generating Facility that replaces an \nExisting Generating Facility, or a portion thereof, at the same electrical Point of Interconnection \npursuant to Section 3.7 of this Attachment X. \n \nReplacement Impact Study shall mean an engineering study that evaluates the impact of \na proposed Generating Facility Replacement on the reliability of the Transmission System."},{"page":114,"startToken":29340,"endToken":29649,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \nRevised System Impact Study shall mean the Interconnection System Impact Study \nperformed during Definitive Planning Phase II \n \nScoping Meeting shall mean the meeting between representatives of Interconnection \nCustomer or MHVDC Connection Customer, Transmission Owner, Affected System and \nTransmission Provider conducted for the purpose of discussing the proposed Interconnection \nRequest and any alternative interconnection options, exchanging information including any \ntransmission data and earlier study evaluations that would be reasonably expected to impact such \ninterconnection options, refining information and models provided by Interconnection \nCustomer(s), discussing the Group Study materials posted to OASIS pursuant to Section 3.4 of \nthis GIP, and analyzing such information. \n \nShared Interconnection Request shall mean (1) multiple Interconnection Customer’s \nrequest, in the form of Appendix 1 to the Generator Interconnection Procedures, to interconnect \nnew Generating Facilities, or to increase the capacity of, or make a Material Modification to the \noperating characteristics of, Existing Generating Facilities that are interconnected with the \nTransmission System, or to interconnect Existing Generating Facilities that are external to the \nTransmission System, or to change Energy Resource Interconnection Service to Network \nResource Interconnection Service for Existing Generating Facilities; or (2) multiple MHVDC \nConnection Customer’s request, in the form of Appendix 1 to the Generator Interconnection \nProcedures, to obtain Injection Rights. \n \nShared Network Upgrade shall mean a Network Upgrade or Common Use Upgrade that \nis funded by an Interconnection Customer(s), including when the Transmission Owner elects to \nfund the capital cost of such a Network Upgrade or Common Use Upgrade under Section 11.3 of \nthe GIA, and also benefits other Interconnection Customer(s) or MHVDC Connection \nCustomer(s) that are later identified as beneficiaries.  \n \nSite Control shall mean a documented right for one or more parcels of land for the"},{"page":115,"startToken":29649,"endToken":29998,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\npurpose of constructing a Generating Facility, Interconnection Customer’s Interconnection \nFacilities, and, if applicable (i.e., when the Interconnection Customer is providing the site \nfor such facilities), the Transmission Owner’s Interconnection Facilities and Network \nUpgrades at the POI that the Interconnection Customer will develop.  Such documented \nright shall be one of the following: (1) ownership of a site; (2) a leasehold interest in a site; \n(3) an option to purchase or acquire a leasehold interest in a site; or (4) any other \ncontractual or legal right to possess or occupy a site.  Transmission Provider will maintain \nacreage requirements for each Generating Facility type on its OASIS or public website. \n \nSmall Generating Facility shall mean a Generating Facility that has an aggregate net \nGenerating Facility Capacity of no more than five MW and meets the requirements of Section 14 \nand Appendix 3. \n \nSouthwest Power Pool (SPP) shall refer to the Southwest Power Pool, Inc. the Regional \nTransmission Organization that is the counterparty to Rate Schedule 6 (MISO-SPP JOA). \n \nSpecial Protection System (SPS) shall mean an automatic protection system or remedial \naction scheme designed to detect abnormal or predetermined system conditions, and take \ncorrective actions other than and/or in addition to the isolation of faulted components, to \nmaintain system reliability.  Such action may include changes in demand (MW and MVar), \nenergy (MWh and Mvarh), or system configuration to maintain system stability, acceptable \nvoltage, or power flows.  An SPS does not include: (a) underfrequency or undervoltage load \nshedding; (b) fault conditions that must be isolated; (c) out-of-step relaying not designed as an \nintegral part of an SPS; or (d) Transmission Control Devices. \n \nStand-Alone Network Upgrades shall mean Network Upgrades, that are not part of an \nAffected System or a JTIQ Upgrade, that Interconnection Customer or MHVDC Connection \nCustomer may construct without affecting day-to-day operations of the Transmission System \nduring their construction.  Transmission Provider, Transmission Owner and Interconnection \nCustomer or MHVDC Connection Customer must agree as to what constitutes Stand Alone"},{"page":116,"startToken":29998,"endToken":30327,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nNetwork Upgrades and identify them in Appendix A to the Generator Interconnection \nAgreement or Appendix B of the Transmission Connection Agreement.  If the Transmission \nProvider or Transmission Owner and Interconnection Customer disagree about whether a \nparticular Network Upgrade is a Stand Alone Network Upgrade, the Transmission Provider or \nTransmission Owner that disagrees with the Interconnection Customer must provide the \nInterconnection Customer a written technical explanation outlining why the Transmission \nProvider or Transmission Owner does not consider the Network Upgrade to be a Stand Alone \nNetwork Upgrade within fifteen (15) Business Days of its determination. \n \nSubstation Network Upgrades shall mean Network Upgrades that are required at or \nnear the Point of Interconnection and are identified in the first portion of the Interconnection \nFacilities Study as described in GIP Section 7.3.2.5. \n \nSupplemental Affected System Analysis shall mean the affected systems analysis \ndescribed in Section 7.3.2.3.1 of this GIP and Section 9.4.2.e.iii.a.i of the Rate Schedule 6 \n(MISO-SPP JOA) to determine if Supplemental Affected System Upgrades are required for one \nor more JTIQ Participation Group member(s). \n \nSupplemental Affected System Upgrade shall mean a Network Upgrade in addition to \nthose required to address the impact of interconnection requests in the current study cluster as \ndescribed in Section 9.4.2.e.iii.a.i of Rate Schedule 6 (MISO-SPP-JOA). \n \nSurplus Host Unit shall mean the Generating Facility from which Surplus \nInterconnection Service will be obtained. \n \nSurplus Interconnection Service shall mean any Interconnection Service that is derived \nfrom the unneeded portion of Interconnection Service established in a GIA or in agreement with, \nor under the tariff of, a Transmission Owner prior to integration into MISO, such that if Surplus \nInterconnection Service is utilized the total amount of Interconnection Service at the Point of \nInterconnection would remain the same."},{"page":117,"startToken":30327,"endToken":30649,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \nSystem Planning and Analysis Phase shall mean the phase of the Generator \nInterconnection Procedure process, prior to January 4, 2017, which consisted of an \nInterconnection System Impact Study for those Interconnection Requests that were studied in \nthis phase.   \n \nSystem Protection Facilities shall mean the equipment, including necessary protection \nsignal communications equipment, required to protect (1) the Transmission System or other \ndelivery systems or other generating systems from faults or other electrical disturbances \noccurring at the Generating Facility and (2) the Generating Facility from faults or other electrical \nsystem disturbances occurring on the Transmission System or on other delivery systems or other \ngenerating systems to which the Transmission System is directly connected. \n \nTarget MW Value shall mean the projected new generation interconnection MW \nenabled by the JTIQ Portfolio.  The Target MW Value for each JTIQ Portfolio shall be identified \nin Section 9.4 and related subsections of Rate Schedule 6. \n \nTariff shall mean the Transmission Provider’s Tariff through which open access \ntransmission service and Interconnection Service are offered, as filed with the Commission, and \nas amended or supplemented from time to time, or any successor tariff.   \n \nThreshold Charge shall mean the charge calculated using an estimate of plant in service \nvalue for the JTIQ Portfolio, excluding amounts funded under the GRIP Program, as described in \nSection 9.4.2 of Rate Schedule 6 (MISO-SPP JOA). \n \nTransient Tolerance Window shall mean the period of time after a reduction or loss of \nload by the ZG Associated Load by the end of which window the Generating Facility with ZG \nInterconnection Service must have reduced its injections to an amount not greater than the Load \nof the ZG Associated Load.  The Transient Tolerance Window shall be no greater than 20 \nseconds, and is further described by the Business Practices Manual for Large Load.  The"},{"page":118,"startToken":30649,"endToken":30985,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nTransient Tolerance Window will be subject to Transmission Owner local planning criteria. \n \nTransmission Control Devices shall mean a generally accepted transmission device that \nis planned and designed to provide dynamic control of electric system quantities, and are usually \nemployed as solutions to specific system performance issues.  Examples of such devices include \nfast valving, high response exciters, high voltage DC links, active or real power flow control and \nreactive compensation devices using power electronics (e.g., unified power flow controllers), \nstatic var compensators, thyristor controlled series capacitors, braking resistors, and in some \ncases mechanically switched capacitors and reactors.  In general, such systems are not \nconsidered to be Special Protection Systems. \n \nTransmission Owner shall mean that Transmission Owner as defined in the Tariff, \nwhich includes an entity that owns, leases or otherwise possesses an interest in the portion of the \nTransmission System at which Interconnection Customer proposes to interconnect or otherwise \nintegrate the operation of the Generating Facility.  Transmission Owner should be read to include \nany Independent Transmission Company that manages the transmission facilities of \nTransmission Owner and shall include, as applicable, the owner and/or operator of distribution \nfacilities interconnected to the Transmission System, over which facilities transmission service \nor Wholesale Distribution Service under the Tariff is available at the time Interconnection \nCustomer requests Interconnection Service and to which Interconnection Customer has requested \ninterconnection of a Generating Facility for the purpose of either transmitting electric energy in \ninterstate commerce or selling electric energy at wholesale in interstate commerce. \n \nTransmission Provider shall mean the Midcontinent Independent System Operator, Inc. \n(“MISO”), the Regional Transmission Organization that controls or operates the transmission \nfacilities of its transmission-owning members used for the transmission of electricity in interstate \ncommerce and provides transmission service under the Tariff. \n \nTransmission Owner’s Interconnection Facilities (TOIF) shall mean all facilities and \nequipment owned by Transmission Owner from the Point of Change of Ownership to the Point"},{"page":119,"startToken":30985,"endToken":31258,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nof Interconnection as identified in Appendix A to the Generator Interconnection Agreement, \nincluding any modifications, additions or upgrades to such facilities and equipment.  \nTransmission Owner’s Interconnection Facilities are sole use facilities and shall not include \nDistribution Upgrades, Generator Upgrades, Stand Alone Network Upgrades or Network \nUpgrades.  \n \nTransmission System shall mean the facilities owned by Transmission Owner and \ncontrolled or operated by Transmission Provider or Transmission Owner that are used to provide \ntransmission service (including HVDC Service) or Wholesale Distribution Service under the \nTariff. \n \nTrial Operation shall mean the period during which Interconnection Customer is \nengaged in on-site test operations and commissioning of the Generating Facility prior to \nCommercial Operation. \n \nUser-Defined Model shall mean any set of programming code created by equipment \nmanufacturers or developers that captures the latest features of controllers that are mainly \nsoftware-based and represent the entities’ control strategy but does not necessarily correspond to \nany particular generic library model, as contained in Attachment A to Appendix 1 of the GIP.    \n \nVariable Energy Resource shall mean a device for the production of electricity that is \ncharacterized by an energy source that: (1) is renewable; (2) cannot be stored by the facility \nowner or operator; and (3) has variability that is beyond the control of the facility owner or \noperator. \n \nWholesale Distribution Service shall have that meaning as provided in the Tariff.  \nWherever the term “transmission delivery service” is used, Wholesale Distribution Service shall \nalso be implied. \n \nZero Injection Generation (ZG) Associated Load shall mean a source of electrical load"},{"page":120,"startToken":31258,"endToken":31588,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nthat has a Point of Withdrawal that is at the same substation as the Point of Interconnection to the \nTransmission System (i.e. same voltage level at the interconnecting substation) as the Generating \nFacility with ZG Interconnection Service that will serve it. \n \nZero Injection Generation (ZG) Interconnection Service shall mean a limited form of \nInterconnection Service that allows an Interconnection Customer to connect its Generating \nFacility to the Transmission System or Distribution System, as applicable, for the limited \npurpose of delivering energy to ZG Associated Load.  ZG Interconnection Service does not grant \nany right to inject energy onto the Transmission System except as may be authorized by Section \n3.11 of the Generator Interconnection Procedures.  ZG Interconnection Service does not convey \nTransmission Service.  ZG Interconnection Service also does not provide a right to serve, or a \nright to Transmission Service to serve, a ZG Associated Load or retail customer except as \nallowed by applicable state law. \n \nZero Injection Generation (ZG) Resource shall mean a generating resource with an \nAttachment X defined ZG Interconnection Agreement.  A ZG Resource may participate as a \nGeneration Resource, Dispatchable Intermittent Resource, Electric Storage Resource, or Behind \nthe Meter Generation resource. \n \nZG Facilities Study shall mean the study described in Section 3.2.5.2.2 of these GIP that \nis used to identify any Network Upgrades or Interconnection Facilities that may be needed to for  \nan Interconnection Request seeking ZG Interconnection Service. \n \nZG Impact Assessment shall mean the study described in Section 3.2.5.2.1 of these GIP \nthat is used to evaluate the impact of an Interconnection Request seeking ZG Interconnection \nServices. \n \nZG Interconnection Agreement (ZGIA) shall mean the form of interconnection \nagreement governing the terms and conditions of ZG Interconnection Service, set forth in \nAppendix 19 to the GIP.  This agreement shall follow the form of the Transmission Provider’s"},{"page":121,"startToken":31588,"endToken":31777,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\npro forma Generator Interconnection Agreement with modifications to reflect ZG \nInterconnection Service and the ZG Interconnection Service study process.  Unless otherwise \nprovided in the GIP, all requirements applicable to the pro forma Generator Interconnection \nAgreement shall apply to the ZGIA.  A ZGIA is a form of GIA and, where used in the Tariff, \nreferences to Generator Interconnection Agreements or GIAs encompasses ZGIAs. \n \nZG Interconnection Process Quarterly Study Period shall mean the period of time in \nwhich Interconnection Requests seeking ZG Interconnection Service are submitted to the \nTransmission Provider and compiled for study.  There are four study periods in a year with the \nfollowing start and end dates: \nQuarter 1: The first Business Day of March through the last Business Day of May; \nQuarter 2: The first Business Day of June through the last Business Day of August; \nQuarter 3: The first Business Day of September through the last Business Day of \nNovember; \nQuarter 4: The first Business Day of December through the last Business Day of \nFebruary."},{"page":122,"startToken":31777,"endToken":32071,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nSECTION 2. SCOPE AND APPLICATION. \n \n2.1 \nApplication of Generator Interconnection Procedures. \na. \nSections 2 through 13 of the GIP apply to processing an Interconnection Request \npertaining to a Generating Facility.  The GIP specifically applies when one of the \nfollowing is proposed by an Interconnection Customer:  (i) a new Generating \nFacility at a new Point of Interconnection that does not meet the criteria set forth \nin Sections 2.1 (b) or (c), (ii) additional generation at an existing Point of \nInterconnection, (iii) an increase in the capacity of an Existing Generating \nFacility, (iv) a Generating Facility Modification that may constitute a Material \nModification to the operating characteristics of an Existing Generating Facility, or \n(v) a Replacement Generating Facility.  The evaluation in subpart (iv) will be \nperformed expeditiously depending on the specific information regarding any \nproposed Generating Facility Modification and the existence of an Emergency \nCondition. \n \nb. \nSection 14 of the GIP applies to a request to interconnect a certified Small \nGenerating Facility meeting the certification criteria set forth in Appendix 3.   \n \nc. \nA request to interconnect a certified inverter-based Small Generating Facility no \nlarger than 10 kW shall be evaluated under the Appendix 4 – 10 kW Inverter \nProcess. \n \nd. \nA request to interconnect to HVDC Facilities subject to Section 27A of the Tariff \nwill be incorporated into the queue as described in Sections 2 through 13 of the \nGIP.  Modifications to the process necessitated by the physics of a connection to \nHVDC Facilities are found in Section 15 of the GIP, and will apply to those \nrequests to interconnect to HVDC Facilities. \n \ne. \nNetwork Resource Interconnection Service is available to Existing Generating"},{"page":123,"startToken":32071,"endToken":32362,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nFacilities connected to facilities external to the Transmission System, including \nany Existing Generating Facilities connected to any MHVDC Transmission Line.  \nSuch a request for Network Resource Interconnection Service shall be \nmemorialized with a Service Agreement as found in Appendix 13 of the GIP. \n \nf. \nSections 1 through 7, Section 10, Section 13 and Section 16 of the GIP apply to \nprocessing an Interconnection Request pertaining to Injection Rights for an \nMHVDC Transmission Line.  Any such request for Injection Rights will be \nincorporated into the queue as described in Sections 2 through 7 of the GIP.  \nProcedures for obtaining Injection Rights and the conversion of those rights to \nexternal Network Resource Interconnection Service are set forth in Section 16 of \nthe GIP. All references to MHVDC Connection Customer(s) in these GIP shall be \nunderstood to refer to MHVDC Connection Customer(s) seeking Injection Rights. \n \ng. \nA request for Replacement Generating Facility shall be evaluated pursuant to \nSection 3.7 of the GIP. \n \nh. \nA request for Generating Facility Modification for an Existing Generating Facility \nmust be submitted to and coordinated with the Transmission Provider pursuant to \nthe provisions set forth in the Generator Interconnection Business Practices \nManual to allow the Transmission Provider to determine whether the proposed \nmodification would result in a substantive modification to the operating \ncharacteristics of such Existing Generating Facility. \n \ni.  \nAn Interconnection Request for a new Generating Facility to be studied through \nthe Expedited Resource Addition Study process shall be evaluated pursuant to \nSection 3.9.2. \n \nj. \nA request for ZG Interconnection Service shall be evaluated pursuant to Section \n3.11 of the GIP."},{"page":124,"startToken":32362,"endToken":32640,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n2.2 \nComparability. \nTransmission Provider shall receive, process and analyze all Interconnection Requests in \na timely manner as set forth in the GIP.  Transmission Provider shall process and analyze \nInterconnection Requests from all Interconnection Customers comparably, regardless of \nGenerating Facility ownership, and from all MHVDC Connection Customers \ncomparably, regardless of MHVDC Transmission Line ownership. \n \n2.3 \nBase Case Data. \nTransmission Provider shall maintain base power flow, short circuit and stability \ndatabases, including all underlying assumptions, and contingency list on a password-\nprotected website, subject to confidentiality provisions in GIP Section 13.1.  In addition, \nTransmission Provider shall maintain network models and underlying assumptions on \nsuch password-protected website.  Such network models and underlying assumptions \nshould reasonably represent those used during the most recent Interconnection Study and \nbe representative of current system conditions.  A link to the information is provided on \nTransmission Provider’s OASIS site.  Interconnection Customers and password-protected \nwebsite users must sign a confidentiality agreement before the release of commercially \nsensitive information or Critical Energy Infrastructure Information in the Base Case data.  \nSuch databases and lists shall include all (i) generation projects and (ii) transmission \nprojects, including merchant transmission projects that are proposed for the Transmission \nSystem for which a transmission expansion plan has been submitted and approved by the \nMISO Board. \n \n2.4 \nNo Applicability to Transmission Service. \nNothing in the GIP shall constitute a request for transmission service or confer upon an \nInterconnection Customer or MHVDC Connection Customer any right to receive \ntransmission service or Wholesale Distribution Service under the Tariff.   \n \nSECTION 3. INTERCONNECTION REQUESTS."},{"page":125,"startToken":32640,"endToken":32999,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n3.1 \nGeneral. \nAn Interconnection Customer or MHVDC Connection Customer shall submit to \nTransmission Provider an Interconnection Request in the form of Appendix 1 to the GIP \nand the deposit along with the other items listed in Section 3.3.1 of these GIP in the \nmanner specified by the Generator Interconnection Business Practices Manual (BPM-\n015).  Transmission Provider shall apply the deposit towards the cost of any \nInterconnection Study.  Interconnection Customer or MHVDC Connection Customer \nshall submit a separate Interconnection Request for each site.  Where multiple Generating \nFacilities share a site, Interconnection Customer(s) may submit separate Interconnection \nRequests or a single Interconnection Request in accordance with Section 3.3.1 of these \nGIP.  An Interconnection Request to evaluate one site at two different voltage levels shall \nbe treated as two Points of Interconnection; provided, however, that an Interconnection \nRequest for Injection Rights shall only evaluate one voltage level at each Point of \nConnection. \n \nTransmission Provider shall have a process in place to consider requests for \nInterconnection Service below the Generating Facility Capacity.  These requests for \nInterconnection Service shall be studied at the level of Interconnection Service requested \nfor purposes of Interconnection Facilities and Network Upgrades, and associated costs, \nbut may be subject to other studies at the full Generating Facility Capacity to ensure \nsafety and reliability of the system, with the study costs borne by the Interconnection \nCustomer.  If after the additional studies are complete, Transmission Provider determines \nthat additional Network Upgrades are necessary, then Transmission Provider must: (1) \nspecify which additional Network Upgrade costs are based on which studies; and (2) \nprovide a detailed explanation of why the additional Network Upgrades are necessary.  \nAny Interconnection Facility and/or Network Upgrade costs required for safety and \nreliability also will be borne by the Interconnection Customer.  Interconnection \nCustomers may be subject to additional control technologies as well as testing and \nvalidation of those technologies consistent with Article 6 of the GIA.  The necessary \ncontrol technologies and protection systems shall be established in Appendix C of the"},{"page":126,"startToken":32999,"endToken":33323,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nexecuted, or requested to be filed unexecuted, GIA. \n \nInterconnection Requests that include at least one electric storage resource shall \ndocument their operating assumptions (i.e., whether the interconnecting Generating \nFacility will or will not charge from the Transmission System and at what level) pursuant \nto Attachment X, Appendix 1.  Notwithstanding the foregoing, Transmission Provider \nshall apply the charging operating assumptions contained in the fuel dispatch \nmethodology as specified by the Generator Interconnection Business Practices Manual \n(BPM-015).  The operating assumptions for charging as modified by the fuel dispatch \nmethodology cannot be higher than those documented in the Interconnection Request.   \n \nTransmission Provider may determine that Good Utility Practice, including Applicable \nReliability Standards, otherwise requires the use of different operating assumptions.  If \nTransmission Provider finds Interconnection Customer’s requested operating \nassumptions conflict with Good Utility Practice, Transmission Provider must provide \nInterconnection Customer an explanation in writing of why the submitted operating \nassumptions are insufficient or inappropriate by no later than thirty (30) Calendar Days \nbefore the end of the Customer Engagement Window and allow Interconnection \nCustomer to revise and resubmit requested operating assumptions one time at least ten \n(10) Calendar Days prior to the end of the Customer Engagement Window.   \n \nTransmission Provider shall study these requests for Interconnection Service, with the \nstudy costs borne by Interconnection Customer, using the submitted operating \nassumptions for purposes of Interconnection Facilities, Network Upgrades, and \nassociated costs.  These requests for Interconnection Service also may be subject to other \nstudies at the full Generating Facility Capacity to ensure safety and reliability of the \nsystem, with the study costs borne by Interconnection Customer.  Interconnection \nCustomer’s Generating Facility may be subject to additional control technologies as well \nas testing and validation of such additional control technologies consistent with Article 6 \nof the GIA.  The necessary control technologies and protection systems shall be set forth"},{"page":127,"startToken":33323,"endToken":33637,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nin Appendix C of the executed, or requested to be filed unexecuted, GIA. \n \n3.2 \nIdentification of Types of Services. \nAt the time the Interconnection Request is submitted, Interconnection Customer must \nrequest NR Interconnection Service, ER Interconnection Service, ZG Interconnection \nService, or Surplus Interconnection Service, as described; provided, however, any \nInterconnection Customer requesting NR Interconnection Service may also request that it \nbe concurrently studied as an ER Interconnection Service, up to the expiration of \nInterconnection Customer Decision Point II.  Interconnection Customer may then elect to \nproceed with NR Interconnection Service or to proceed under a lower level of NR \nInterconnection Service to the extent that only certain upgrades will be completed. A \ndescription of the modeling details used when studying a project as ER Interconnection \nService or NR Interconnection Service can be found in Section 6 of the Generator \nInterconnection Business Practices Manual (BPM-015). MHVDC Connection Customer \nmay only request Injection Rights pursuant to Section 16 of the GIP and shall not be \neligible to receive any Interconnection Services specified in the GIP.   \n \n3.2.1 Energy Resource Interconnection Service (ER Interconnection Service). \n \n3.2.1.1 The Product.  ER Interconnection Service allows Interconnection \nCustomer to connect the Generating Facility to the Transmission System \nor Distribution System, as applicable, and be eligible to deliver the \nGenerating Facility’s output using the existing firm or non-firm capacity \nof the Transmission System on an “as available” basis and may be granted \non a conditional basis.  ER Interconnection Service does not in and of \nitself convey any right to deliver electricity to any specific customer or \nPoint of Delivery. \n \n \n3.2.1.2 The Study.  The study consists of short circuit/fault duty, steady state \n(thermal and voltage) and stability analyses.  The short circuit/fault duty"},{"page":128,"startToken":33637,"endToken":33946,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nanalysis would identify the Interconnection Facilities required and the \nNetwork Upgrades necessary to address short circuit issues associated \nwith the Interconnection Facilities.  The stability and steady state studies \nwould identify necessary upgrades to allow full output of the proposed \nGenerating Facility and would also identify the maximum allowed output, \nat the time the study is performed, of the interconnecting Generating \nFacility without requiring additional Network Upgrades.  Notwithstanding \nthe foregoing, the output of the Generating Facility and the charging of \nelectric storage resources will be modified by Transmission Provider’s \nfuel dispatch methodology in the manner specified by the Generator \nInterconnection Business Practices Manual (BPM-015). \n \n3.2.2 Network Resource Interconnection Service (NR Interconnection Service). \n \n3.2.2.1 The Product.  Transmission Provider must conduct the necessary studies \nand Transmission Owner shall cause the construction of the Network \nUpgrades, System Protection Facilities, Distribution Upgrades or \nGenerator Upgrades, subject to the approval of Governmental Authorities, \nneeded to integrate the Generating Facility in the same manner as for any \nGenerating Facility being designated as a Network Resource.  NR \nInterconnection Service allows the Generating Facility to be designated as \na Network Resource, up to the Generating Facility’s full output on the \nsame basis as existing Network Resources that are interconnected to the \nTransmission or Distribution System as applicable, and to be studied as a \nNetwork Resource on the assumption that such a designation will occur.  \nNR Interconnection Service may be granted on a conditional basis \npursuant to the terms of Article 4.1.2.3 of the GIA.  A Generating Facility \nrequesting NR Interconnection Service shall be deemed to request ER \nInterconnection Service of an equivalent amount to the extent that the \nGenerating Facility does not already have ER Interconnection Service in"},{"page":129,"startToken":33946,"endToken":34225,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\norder to allow Interconnection Customer to connect the Generating \nFacility to the Transmission System or Distribution System, as applicable, \nand be eligible to deliver the Generating Facility’s output. The total NR \nInterconnection Service shall not exceed the total ER Interconnection for a \nGenerating Facility.  Interconnection Customer with an in-service \nGenerating Facility or with an executed GIA, having ER Interconnection \nService or equivalent interconnection service can request NR \nInterconnection Service by making an Interconnection Request for \nobtaining only NR Interconnection Service. \n \n3.2.2.2 The Study.  The Interconnection Study for NR Interconnection Service \nshall assure that the Generating Facility meets the requirements for NR \nInterconnection Service and will qualify the Generating Facility as a \nNetwork Resource under Module B and the RAR of the Transmission \nProvider’s Tariff.  As a general matter, the Generating Facility’s \ninterconnection is studied with the Transmission System at both off-peak \nand peak loads, under a variety of severely stressed conditions, to \ndetermine whether, with the Generating Facility at full output, the \naggregate of generation in the local area can be delivered to the aggregate \nof load on the Transmission System or Distribution System, as applicable, \nconsistent with Applicable Reliability Standards.  This approach assumes \nthat some portion of existing Network Resources is displaced by the \noutput of the Generating Facility.  NR Interconnection Service does not \nconvey any right to deliver electricity to any specific customer or Point of \nDelivery. \n \n3.2.3 Surplus Interconnection Service. \n \n3.2.3.1 The Product.  Surplus Interconnection Service is restricted \nInterconnection Service that allows an Interconnection Customer to"},{"page":130,"startToken":34225,"endToken":34540,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nincrease the gross generating capability at the same Point of \nInterconnection of an Existing Generating Facility without increasing the \ntotal amount of Interconnection Service at the Point of Interconnection. \nThe total combined generating output at the Point of Interconnection for \nBoth the original and surplus Interconnection Customer is limited to and \nshall not exceed the total amount of Interconnection Service of an Existing \nGenerating Facility.  Surplus Interconnection Service does not convey any \nright to deliver electricity to any specific customer or Point of Delivery.  If \nthe Existing Generating Facility has only ERIS, any Surplus \nInterconnection Service associated with that Existing Generating Facility \nat the same Point of Interconnection shall be ERIS.  If the Existing \nGenerating Facility has NRIS, any Surplus Interconnection Service \nassociated with that Existing Generating Facility at the same Point of \nInterconnection could be either ERIS or NRIS. \n \n3.2.3.2 The Study.  The Interconnection Study for Surplus Interconnection \nService consists of reactive power, short circuit/fault duty, stability \nanalyses, and steady-state (thermal/voltage) analyses may be performed as \nnecessary to ensure that all required reliability conditions are studied.  If \nthe Existing Generating Facility’s Interconnection Service was not studied \nunder off-peak conditions, and if warranted, in the Transmission \nProvider's sole discretion, by the fuel-based dispatch assumptions \nspecified in the Generator Interconnection Business Practices Manual, off-\npeak steady state analyses shall be performed to the required level \nnecessary to demonstrate reliable operation of the Surplus Interconnection \nService.  If the Transmission Provider is unable to verify that the Existing \nGenerating Facility was previously studied for the granted level of \nInterconnection Service as provided in Section 3.3.1.1(3) of this GIP, the \nTransmission Provider may perform steady state analyses to demonstrate \nreliable operation of the Surplus Interconnection Service in accordance"},{"page":131,"startToken":34540,"endToken":34835,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nwith the GIP and Generator Interconnection Business Practice Manual.  \nThe Transmission Provider will perform the applicable studies for the \nsurplus Interconnection Request, pursuant to the provisions set forth in the \nGenerator Interconnection Business Practices Manual, to determine \nwhether the Surplus Interconnection Service proposed in the surplus \nInterconnection Request would result in material adverse impact on the \nTransmission System and/or Affected Systems, as compared to the \nimpacts that are created by the Existing Generating Facility, respecting its \ndispatch levels from the original steady state interconnection study, \nwithout the inclusion of the proposed Surplus Interconnection Service.  If \nno original study is available, the Transmission Provider shall apply the \ncurrent fuel dispatch assumptions used for new Generating Facilities to the \nExisting Generating Facility in the steady state study.  If Transmission \nProvider determines that the proposed Surplus Interconnection Service \nwould result in a material adverse impact on the Transmission System \nand/or Affected Systems, then the proposed surplus Interconnection \nRequest is deemed to be a Qualified Change and the Interconnection \nCustomer shall proceed through Definitive Planning Phase cycle similar to \na request for interconnection of a new Generating Facility or withdraw the \nsurplus Interconnection Request.  The Interconnection Study for the \nsurplus Interconnection Request will identify the Interconnection Facilities \nrequired and the Network Upgrades necessary to address reliability issues \nassociated with the Interconnection Facilities. \n \nTransmission Provider shall study Surplus Interconnection Service \nrequests for a Generating Facility that includes at least one electric storage \nresource and for which Transmission Provider approves operating \nassumptions pursuant to Section 3.1 according to the Transmission \nProvider’s fuel dispatch methodology in the manner specified by the \nGenerator Interconnection Business Practices Manual (BPM-015)."},{"page":132,"startToken":34835,"endToken":35135,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \n3.2.4  Injection Rights \n \n \n3.2.4.1 The Product.  Injection Rights serve as a pre-certification of the \nTransmission System’s capability to receive capacity and energy from the \nMHVDC Transmission Line at the requested Point of Connection, and in the \nspecified MW quantity, without degrading the reliability of the Transmission \nSystem.  Injection Rights do not grant Interconnection Service or Transmission \nService to the MHVDC Connection Customer.  Injection Rights must be \nconverted to external Network Resource Interconnection Service as set forth in \nSection 16.2 of the GIP before those rights may be used to offer energy or \ncapacity into the MISO markets. \n \n \n3.2.4.2 The Study.  Requests for Injection Rights shall include both ERIS-level \nand NRIS-level evaluations.  For ERIS-level evaluation, the study will include \nshort circuit/fault duty, steady state (thermal and voltage) and stability analyses.  \nThe stability and steady state studies would identify necessary upgrades to allow \nfull output of the proposed MHVDC Transmission Line and would also identify \nthe maximum allowed output, at the time the study is performed, of the \ninterconnecting MHVDC Transmission Line without requiring any additional \nupgrades. \n \n \nFor NRIS-level evaluation, the study will assure that the output of the MHVDC \nTransmission Line meets the requirements for NR Interconnection Service and \nwill qualify any Existing Generating Facility connected to the MHVDC \nTransmission Line as a Network Resource under Module B and the RAR of the \nTransmission Provider Tariff.  As a general matter, such Generating Facility’s \ninterconnection with the Transmission System is studied at both off-peak and \npeak loads, under a variety of severely stressed conditions, to determine whether, \nwith such Generating Facility at full output, the aggregate of generation in the"},{"page":133,"startToken":35135,"endToken":35436,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nlocal area can be delivered to the aggregate of load on the Transmission System or \nDistribution System, as applicable, consistent with Applicable Reliability \nStandards.  This approach assumes that some portion of an existing Network \nResource is displaced by the output of such Generating Facility. \n3.2.5 ZG Interconnection Service \n3.2.5.1 The Product.  ZG Interconnection Service is restricted Interconnection \nService that allows an Interconnection Customer to connect its Generating \nFacility to the Transmission System or Distribution System, as applicable, \nfor the limited purpose of delivering energy to a source of electrical load \nthat is at the same substation as the Point of Interconnection to the \nTransmission System (i.e. same voltage level at the interconnecting \nsubstation) as the Generating Facility with ZG Interconnection Service \nthat will serve it. \n \nThis service is available only if the study required by Section 3.2.3.2 of \nthese GIP determines that the proposed interconnection:   \n(1) will not result in any injections of Energy onto the Transmission \nSystem beyond the substation identified in the Interconnection Request \nas the Point of Interconnection.  The restriction on Energy injection in \nthis paragraph shall not apply to transient, limited injections associated \nwith a reduction or loss of Load by the ZG Associated Load provided \nthese remain within any Transient Tolerance Window established in \nthe Business Practices Manual for Large Load.   \n \n(2) Will not require the construction or modification of any Network \nUpgrades to address impacts to the Transmission System with the \nexception of Network Upgrades located at the same substation as the \nPOI, except for System Protection Facilities at adjacent substations.  \n \nZG Interconnection Service is specific to the ZG Associated Load(s) that the"},{"page":134,"startToken":35436,"endToken":35746,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nGenerating Facility identifies in its Interconnection Request, and which shall be \nmemorialized in the ZGIA.  ZG Interconnection Service does not grant any right \nto inject energy onto the Transmission System beyond the Point of \nInterconnection except as may be authorized by Section 3.11 of these Generator \nInterconnection Procedures.  ZG Interconnection Service does not provide \ninterconnection service for the purpose of serving Load other than the ZG \nAssociated Load(s) identified in the Interconnection Request and memorialized in \nthe ZGIA.  ZG Interconnection Service does not convey transmission service, \nwhich is obtained through a separate process, and does not provide a right to \nserve, or a right to transmission service to serve, a retail customer except as \nspecifically allowed by state laws and regulations.   \n \nThe ZG Interconnection Service product does not supersede any state or local \nlaws or regulations nor does it authorize operations that would violate state or \nlocal laws and regulations, including those establishing which entities have the \nright or obligation to serve load.  Interconnection Customers are separately \nresponsible for adhering to all Applicable Laws and Regulations.  \n \n3.2.5.2 The Study.  The Study shall include a ZG System Impact Assessment \nand, if needed, a ZG Facilities Study as described below.   \n \nThe Generating Facility’s requesting ZG Interconnection Service will be \nstudied at a level not to exceed the Demand of the ZG Associated Load \nother than as necessary to study outages of the ZG Associated Load.  The \nGenerating Facility’s requesting ZG Interconnection Service will be \ndispatched, and granted service at a level not to exceed the total Demand \nof the ZG Associated Load. \n \n3.2.5.2.1  ZG Impact Assessment.  The ZG Impact Assessment shall \nconsist of a review of the proposed configuration of the"},{"page":135,"startToken":35746,"endToken":36013,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nGenerating Facility, its electrical connection both to the \ndesignated ZG Associated Load(s) and to the Transmission \nSystem, and the proposed control equipment and/or operating \nprocedures to determine whether these are sufficient to prevent \ninjections onto the Transmission System beyond the substation \nwhere the Point of Interconnection is located.  The \nTransmission Provider shall perform short circuit/fault duty, \nstability analyses, and steady state (thermal and voltage) if \nnecessary based on the proposed configuration.  The stability \nand steady state studies shall study the ability of the Generating \nFacility to interconnect to the Transmission System without \nrequiring additional Network Upgrades to maintain reliability, \nincluding analysis for the ZG Associated Load tripping offline \nconsistent with the Transient Tolerance Window established in \nthe Business Practices Manual for Large Load.  For ZG \nInterconnection Service to be granted, these analyses must \ndetermine that no Network Upgrades are needed to maintain \nsystem reliability other than Network Upgrades at the same \nsubstation as the Point of Interconnection or System Protection \nFacilities.   \n \n3.2.5.2.2  ZG Facilities Study.  The ZG Facilities Study shall identify \nany Network Upgrades at the same substation as the POI, \nand/or operating procedures that are required to prevent \ninjections of Energy, other than transient injections during \nLoad reduction or loss events, and to maintain reliability during \nthese permitted transient injections.  The ZG Facilities Study \nshall identify any required system protection facilities and \nequipment.  Further, the study shall identify any \nInterconnection Facilities required to interconnect the proposed"},{"page":136,"startToken":36013,"endToken":36329,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nGenerating Facility to the Transmission System.  \n \nThe portion of the ZG Facilities Study for Interconnection \nFacilities will start at the same time as the ZG Impact \nAssessment.  The ZG Facilities Study will identify estimates \nfor cost and the time required to construct the Interconnection \nFacilities.  The portion of the ZG Facilities Study for Network \nUpgrades shall begin upon the identification of a need for such \nNetwork Upgrades in the ZG Impact Assessment but not later \nthan one Business Day after the ZG Impact Study results are \nprovided to the Interconnection Customer.   \n \n3.3 \nValid Interconnection Request.  \n \n3.3.1 Initiating an Interconnection Request. \nThe Transmission Provider shall post on the MISO public website a notice of an \napplication deadline for a cluster entering DPP studies at least 45 calendar days prior to \nthe application deadline.  An Interconnection Customer or an MHVDC Connection \nCustomer wishing to join the next Definitive Planning Phase shall submit their \nInterconnection Request to the Transmission Provider in the manner required by the \nGenerator Interconnection Business Practices Manual (BPM-015) no later than the \napplication deadline, which will be at least ninety (90) Calendar Days prior to the \nscheduled kick-off of the Definitive Planning Phase I of that cycle, published on the \nMISO public website.  Beginning with the third Group Study after the Commission-\napproved effective date of Transmission Provider’s filing made in compliance with the \nFinal Rule in Docket No. RM22-14-000, the Transmission Provider shall set an \napplication deadline for the next Definitive Planning Phase Group Study, which deadline \nshall be 45 Calendar Days (or next Business Day if the 45th Calendar Day falls on a \nweekend or holiday) after the close of Decision Point 2 of the previous Definitive \nPlanning Phase Group Study.  Any Interconnection Request received after the application"},{"page":137,"startToken":36329,"endToken":36682,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ndeadline published on the MISO public website shall, subject to section 4.1.1, be applied \ntowards a subsequent Definitive Planning Phase cycle.  A Provisional Generator \nInterconnection Agreement may be requested as set forth in Section 7.9 of the GIP.  The \nGenerating Facility described in a valid Interconnection Request may not connect to, or \npropose to connect to, the transmission facilities of any transmission provider other than \nthe Transmission Provider except that: 1) an Interconnection Customer may propose to \ninclude a Generating Facility already connected to a different transmission system in an \nInterconnection Request to the Transmission Provider if the Interconnection Request \ncontains a commitment by the Interconnection Customer to disconnect the Generating \nFacility from such other transmission system prior to achieving Commercial Operation \nunder a Generator Interconnection Agreement with the Transmission Provider and, 2) an \nInterconnection Customer may proposed to connect an Existing Generating Facility to the \ntransmission facilities of another transmission provider provided such Interconnection \nCustomer retires the Existing Generating Facility in accordance with Attachment Y to the \nTariff prior to the date such generating facilities achieve commercial operation with such \nother transmission provider.  Submission of Generating Facilities included in an \nInterconnection Request to another transmission provider for connection to their systems \nshall result in such Interconnection Request being deemed withdrawn pursuant to Section \n3.6 of these Generator Interconnection Procedures. \n \nAn Interconnection Customer requesting to join the next Expedited Resource Addition \nStudy (ERAS) shall submit their Interconnection Request to the Transmission Provider \nno later than the ERAS application deadline as published on the MISO public website, at \nleast fifteen (15) Business Days prior to the scheduled kick-off of the ERAS cycle \npublished on the MISO public website.  The valid ERAS request shall be included in an \nERAS Quarterly Study Period that commences after it was submitted. \n \nStudy deposits for the Definitive Planning Phase (DPP) and the Expedited Resource \nAddition Study are required based on the Megawatt amount of the new Interconnection \nService requested per the following schedule:"},{"page":138,"startToken":36682,"endToken":36978,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \nAmount of new \nInterconnection Service \nand/or Injection Rights \nrequested (MW) \nNon-Refundable \nDeposit 1 (D1) \nStudy Deposit 2 (D2) \n< 6 MW \nCalculated according to \nthe procedure in 3.3.1 \nand posted by \nTransmission Provider \nprior to the application \ndeadline. \n$50,000 \n20 ≥ MW ≥ 6 \n$120,000 \n50 ≥ MW > 20  \n$180,000 \n100 ≥ MW > 50 \n$270,000 \n200 ≥ MW > 100 \n$320,000 \n500 ≥ MW > 200 \n$420,000 \n1000 > MW > 500 \n$530,000 \nMW ≥ 1000 \n$640,000 \n \nThe Transmission Provider shall calculate the amount of the Non-Refundable Deposit 1 \n(D1) by determining the inflation adjustment in accordance with the inflation calculator \nlocated at the U.S. Bureau of Labor Statistics website.  The inflation adjustment shall be \ncalculated from the effective date of the original D1 amount of $5,000, August 2008, to \nthe most up-to-date data available at the time the notification takes place, where such \namount will be rounded to the nearest $100 and posted on the Transmission Provider’s \nwebsite.  The Transmission Provider shall post a Non-Refundable Deposit 1 (D1) once \nevery three years.  The Non-Refundable Deposit 1 (D1) amount calculated pursuant to \nthis paragraph shall be applicable to all study groups with an application deadline that is \nsixty (60) or more Calendar Days after the date that the Transmission Provider posts such \namount and to all Interconnection Requests seeking ZG Interconnection Service that are \nreceived by the Transmission Provider after the date of such posting.  The posting and \nwill remain effective until Transmission Provider posts a revised calculation pursuant to \nthis paragraph. \n \nAn Interconnection Request for the Expedited Resource Addition Study shall be \naccompanied by a Non-Refundable Deposit 1 (D1) of $100,000."},{"page":139,"startToken":36978,"endToken":37245,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \nAn Interconnection Request for a Replacement Generating Facility and/or an \nInterconnection Request seeking ZG Interconnection Service or Surplus Interconnection \nService shall be accompanied by a Non-Refundable Deposit 1 (D1) and a study deposit in \nthe amount of $150,000. \n \nThirty (30) Calendar Days after the execution of a non-Provisional Generator \nInterconnection Agreement or a Transmission Connection Agreement in which the \nInjection Rights option has been selected, Interconnection Customer or MHVDC \nConnection Customer may replace any non-encumbered balance of the study deposits \nwith an irrevocable letter of credit or surety reasonably acceptable to Transmission \nProvider.  The surety bond must be issued by an insurer reasonably acceptable to \nTransmission Provider and must specify a reasonable expiration date.  The Transmission \nProvider may establish additional requirements for what constitutes a surety bond, \nincluding but not limited to, duration satisfaction, demand timeframe and issuer \nrequirements through the Generator Interconnection Business Practices manual (BPM-\n015). \n \nInterconnection Customer or MHVDC Connection Customer shall be required to provide \nto Transmission Provider the following data as further described in the Generator \nInterconnection Business Practices Manual (BPM-015) along with its Interconnection \nRequest: \n \n(i) \na detailed stability model for the proposed Generating Facility or MHVDC \nTransmission Line;  \n(ii) \na detailed power flow model for the proposed Generating Facility or \nMHVDC Transmission Line;  \n(iii) \nTechnical data as outlined in Attachment A of Appendix 1 of this GIP; \n(iv) \nan Interconnection Study Agreement executed by Interconnection \nCustomer or MHVDC Connection Customer in the form of Appendix 1,"},{"page":140,"startToken":37245,"endToken":37529,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nAttachment B;   \n(v) \na definitive Point of Interconnection or Point of Connection; \n(vi) \nfor Interconnection Requests proposing to share Interconnection Customer \nInterconnection Facilities with another pending Interconnection Request \nor existing project, a consent agreement in accordance with Section 3.3.1.4 \nof these Generator Interconnection Procedures;   \n(vii) \na one line diagram showing the Generating Facility or MHVDC \nTransmission Line and associated electrical equipment with appropriate \nrating and impedance information;  \n(viii) Megawatt amount of new Interconnection Service or Injection Rights \nrequested; and \n(ix)  \nIf applicable, (1) the requested operating assumptions to be used by \nTransmission Provider that reflect the proposed charging behavior of the \nGenerating Facility that includes at least one electric storage resource, and \n(2) a description of any control technologies (software and/or hardware) \nthat will limit the operation of the Generating Facility to the operating \nassumptions submitted by Interconnection Customer. \n \nIn addition, Interconnection Customer or MHVDC Connection Customer proposing to \nenter the Definitive Planning Phase shall provide the Definitive Planning Phase entry \nmilestone in the form of either cash, irrevocable letter of credit or surety bond reasonably \nacceptable to Transmission Provider.  The surety bond must be issued by an insurer \nreasonably acceptable to Transmission Provider and must specify a reasonable expiration \ndate.  The Transmission Provider may establish additional requirements for what \nconstitutes a surety bond, including but not limited to, duration satisfaction, demand \ntimeframe and issuer requirements through the Generator Interconnection Business \nPractices manual (BPM-015).   \n \nThe Definitive Planning Phase entry milestone (M2) will be calculated as $8,000 per \nMegawatt amount of new Interconnection Service or Injection Rights requested."},{"page":141,"startToken":37529,"endToken":37838,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \nThe Expedited Resource Addition Study entry milestone (M2) will be calculated as \n$24,000 per Megawatt for the amount of new Interconnection Service requested. \n \nExcept as otherwise provided for Site Control in Section 7.2 of this GIP, all applicable \ndeposits, milestone payments, and data required to enter the Definitive Planning Phase, \nincluding the exemptions noted in Section 4.1.2, must be received at the time  of the \nsubmission of the interconnection request on the Transmission Provider website. \n \nAll applicable deposits, milestone payments and data required to enter the Expedited \nResource Addition Study must be received at the time the application is submitted. \n \nInterconnection Customer shall provide proof of Site Control or a cash deposit in lieu of \nSite Control in accordance with the requirements and timing established in Section 7.2 of \nthis GIP.  In the event that an Interconnection Customer or MHVDC Connection \nCustomer has a state regulatory requirement to process two Points of Interconnection or \nPoints of Connection through the entire process, that Interconnection Customer or \nMHVDC Connection Customer is not required to comply with the Site Control \nrequirements in Section 7.2 for the second Interconnection Request, provided it is \nproperly identified as the required alternative. \n \nThe Non-Refundable Deposit 1 (D1) and Study Deposit 2 (D2) shall be applied toward \nthe costs related to processing the Interconnection Request, including costs of \nInterconnection Studies and GIA negotiation. \n \nThe expected In-Service Date of the Generating Facility or MHVDC Transmission Line \nshall be no later than the process window for the Transmission Provider’s regional \nexpansion planning period not to exceed seven years from the date the Interconnection \nRequest is received by Transmission Provider, unless Interconnection Customer or \nMHVDC Connection Customer demonstrates that engineering, permitting and"},{"page":142,"startToken":37838,"endToken":38205,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nconstruction of the Generating Facility or MHVDC Transmission Line will take longer \nthan the regional expansion planning period, nor shall it be any sooner than the process \ntime described in the Generator Interconnection Procedures and confirmed in the Pre-\nQueue Phase.  The In-Service Date may succeed the date the Interconnection Request is \nreceived by Transmission Provider by a period up to ten years, or longer where \nInterconnection Customer or MHVDC Connection Customer and Transmission Provider \nagree, such agreement not to be unreasonably withheld. \n \nThe expected Commercial Operation Date of a Replacement Generating Facility shall be \nno more than three (3) years from the date of cessation of operation of the Existing \nGenerating Facility.  For Existing Generating Facilities that have not yet reached \nCommercial Operation, the specified Commercial Operation Date in the GIA of a \nReplacement Generating Facility shall be no later than the specified Commercial \nOperation Date in the GIA of the Existing Generating Facility.  For Existing Generating \nFacility that is in suspension pursuant to Section 38.2.7 of the Tariff or in Forced Outage, \nthe start date of suspension or outage shall be considered the date of cessation of \noperation of the Existing Generating Facility for purposes of calculating the three (3) year \nlimit. If the requested period of time between the cessation of operation of the Existing \nGenerating Facility and expected Commercial Operation Date of the Replacement \nGenerating Facility is more than three (3) years, the request shall be treated as an \nInterconnection Request for a new Generating Facility.  An Existing Generating Facility \nthat was in suspension pursuant to Section 38.2.7 of the Tariff is subject to the time \nlimitations in Section 38.2.7(n) of the Tariff. \n \nWhere multiple Generating Facilities owned by a single Interconnection Customer share \na site, such Interconnection Customer may submit separate Interconnection Requests or \nsingle Interconnection Request.  Where multiple Generating Facilities are owned by \ndifferent Interconnection Customers and share a site, Interconnection Customers may \nsubmit a single Interconnection Request (Shared Interconnection Request), but the \nInterconnection Request must include an agreement between the Interconnection"},{"page":143,"startToken":38205,"endToken":38497,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nCustomers which designates a primary point of contact for communications and \ndesignates a single authorized contact for payments and refunds, and the agreement must \nclearly identify ownership of each proposed Generating Facility.  An existing \nInterconnection Request may not be combined with another to form a Shared \nInterconnection Request. \n \nAn Interconnection Request for a Generating Facility requesting processing through the \nExpedited Resource Addition Study shall identify the claimed resource adequacy and/or \nreliability need(s) for which it is being submitted.  This should include the location (i.e. \nthe county and state, the electrical bus location(s), and the Local Resource Zone) of any \nload to be served via the off take agreement as well as the peak demand for electricity \nexpected over any one hour period in MWs—the amount of Interconnection Service \nrequested must not exceed 150 percent of the identified MW need. The Generating \nFacility and the associated resource adequacy and/or reliability need(s) must be within \nthe same Local Resource Zone, unless the resource adequacy and/or reliability need is \nincluded in a resource filing made to the RERRA that is providing the verification \nrequired in Section 3.9.1.  \n \nThe expected Commercial Operation Date included in the Interconnection Request for a \nGenerating Facility requesting processing through the Expedited Resource Addition \nStudy shall be no later than three calendar years from the submission date of the \nInterconnection Request. \n \n3.3.1.1 Additional Requirements for a Surplus Interconnection Request \napplication \n \nA request for Surplus Interconnection Service made by an Interconnection \nCustomer must meet the requirements listed in section 3.3.1 above, plus the \nfollowing requirements:"},{"page":144,"startToken":38497,"endToken":38806,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n1. \nThe Interconnection Customer of the Existing Generating Facility, or one \nof its affiliates, shall have priority to utilize Surplus Interconnection \nService.  If the Interconnection Customer of the Existing Generating \nFacility or one of its affiliates does not exercise its priority, then the \nInterconnection Customer may make Surplus Interconnection Service \navailable to other potential Interconnection Customers.  \n \n2. \nThe surplus Interconnection Request shall be accompanied by written \nconfirmation from an officer of the Interconnection Customer of the \nSurplus Host Unit , indicating: (i) the amount of Surplus Interconnection \nService made available by the Interconnection Customer of the Surplus \nHost Unit; (ii) the type of Interconnection Service (i.e., ERIS or NRIS) \nmade available by the Interconnection Customer of the Surplus Host Unit \nin accordance with the provisions of Section 3.2.3.1 of this GIP; (iii) the \ncircumstances under which the proposed Surplus Interconnection Service \nwould be available, including an indication of whether the proposed \nInterconnection Service would be available on a continuous basis (i.e., a \ncertain number of MW of Surplus Interconnection Service would always \nbe available for use by a co-located generating facility) or on a scheduled, \nperiodic basis (i.e., a specified number of MW of Surplus Interconnection \nService that would be available intermittently. \n \n3. \nExcept as provided in Section 3.3.1.1(3)(a) of this Attachment X, the \nInterconnection Customer must include the MISO Interconnection System \nImpact Study performed for the Existing Generating Facility when the \nGenerating Facility was originally proposed for interconnection to the \nMISO Transmission System or, for Generating Facilities studied under a \npredecessor transmission provider’s interconnection process, the original \nsystem impact study performed at the time such Generating Facility was \noriginally studied for interconnection to the transmission system."},{"page":145,"startToken":38806,"endToken":39064,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nTransmission Provider will use that study to appropriately scope the study \nfor evaluation of the surplus Interconnection Request.  If the \nInterconnection Customer cannot provide such system impact study with \nits application, it shall indicate that such study is not available. \n \na. \nA Request for Surplus Interconnection Service may be submitted \nby an Interconnection Customer prior to the date that the Surplus \nHost Unit has obtained an effective Generator Interconnection \nAgreement provided the following requirements are met: \n \n1. \nThe Surplus Host Unit has a valid Interconnection Request \nand has completed Interconnection Customer Decision \nPoint II of the GIP prior to the date that the surplus \nInterconnection Request is submitted; \n2. \nThe surplus Interconnection Request satisfies each of the \nrequirements of Section 3.3.1.1 of this GIP except that \ninstead of providing the MISO Interconnection System \nImpact Study for an Existing Generating Facility specified \nby Section 3.3.1.1(3), the Surplus Interconnection \nCustomer shall provide the most recently completed \nInterconnection System Impact Study in the form of the \nRevised System Impact Study for Definitive Planning \nPhase II or the Final System Impact Study for Definitive \nPlanning Phase III for the Surplus Host Unit with the \nsurplus Interconnection Request;  \n3. \nThe Surplus Interconnection Customer identifies the study \ncycle and project number of the Surplus Host Unit in the \nsurplus Interconnection Request; and \n4. \nIf sharing Interconnection Customer Interconnection \nFacilities with the Existing Generating Facility, evidence"},{"page":146,"startToken":39064,"endToken":39320,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nthat the Interconnection Customer has entered into a \nconsent agreement that meets the requirements of Section \n3.3.1.4. \n5. \nIf the Surplus Interconnection Customer Generating \nFacility partially or completely consists of energy storage \ndevices, the Surplus Interconnection Customer \nInterconnection Request shall contain a description of any \ncontrol technologies (software and/or hardware) that will \nlimit the concurrent operation of the Existing Generating \nFacilities and Surplus Facilities to the original \nInterconnection Service limit. \n \n4. \nThe surplus Interconnection Request must be submitted to the \nTransmission Provider by the Interconnection Customer at least one (1) \nyear prior to the Commercial Operation Date of the Generating Facility \nrequesting Surplus Interconnection Service. \n \n5. \nIf a Material Modification study for the Surplus Host Unit is pending at \nthe time the surplus Interconnection Request is submitted, then the surplus \nInterconnection Study for Surplus Interconnection Service shall not \nkickoff until the Material Modification study has completed and any \napproved modifications have been added to Generation Interconnection \nAgreement. \n \nThe Transmission Provider shall commence processing and studying a surplus \nInterconnection Request that conforms to the requirements of this Section \n3.3.1.1(3)(a) of the GIP in accordance with the provision of Section 3.3.1.2 of this \nGIP provided that no GIA may be tendered for such surplus Interconnection \nRequest prior to the date that the Surplus Host Unit has become subject to an \neffective Generator Interconnection Agreement."},{"page":147,"startToken":39320,"endToken":39582,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \n3.3.1.2 Evaluation Process for Surplus Interconnection Request and the \nRequirements for the Request to Remain Valid \n \nThe following conditions will apply for evaluation of surplus Interconnection \nRequest: \n \n1. \nWithin thirty (30) Calendar Days of the Transmission Provider’s receipt of \nthe completed surplus Interconnection Request, Transmission Provider \nwill commence a study of the proposed Surplus Interconnection Service \npursuant to Section 3.2.3.2 of this GIP to determine whether such service \nwould result in any material adverse impact to the Transmission System \nand/or Affected Systems and amounts to a Material Modification.  After \nthe commencement of the surplus Interconnection Study for Surplus \nInterconnection Service, if a Material Modification request on the Surplus \nHost Unit is submitted, the surplus Interconnection Request will be \npaused.  Once the Material Modification request has been approved, the \nsurplus Interconnection Request will be reevaluated and may require the \nInterconnection Customer to update the surplus Interconnection Request.  \nThe updated surplus Interconnection Request is subject to the surplus \nInterconnection Request timing requirements.  Transmission Provider \nshall use Reasonable Efforts to complete the study of the surplus \nInterconnection Request within ninety (90) Calendar Days.  If \nTransmission Provider determines that the surplus Interconnection \nRequest would result in a material adverse impact to the Transmission \nSystem and/or Affected Systems, then the surplus Interconnection Request \nshall proceed through the Definitive Planning Phase as a new \nInterconnection Request. \n \n2. \nWithin thirty (30) Calendar Days after having received results of the"},{"page":148,"startToken":39582,"endToken":39896,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nTransmission Provider’s evaluation, Interconnection Customer requesting \nSurplus Interconnection Service shall inform Transmission Provider of its \nelection to proceed with its surplus Interconnection Request.  After \nreceiving the Interconnection Customer’s election notice, Transmission \nProvider will initiate an Interconnection Facilities Study or tender a draft \nGIA, as appropriate.  If the Interconnection Customer fails to provide a \nnotice of its election to proceed within thirty (30) Calendar Days after \nhaving received results of the Transmission Provider’s evaluation, the \nTransmission Provider will deem the Interconnection Request withdrawn \npursuant to Section 3.6 of this GIP. \n \nThe Interconnection Facilities Study will be performed, if needed, and will \nbe completed within ninety (90) Calendar Days.  If an Interconnection \nFacilities Study is necessary, the Transmission Provider shall tender a \ndraft pro forma GIA within the later of thirty (30) Calendar Days after \nfinal Interconnection Facilities Study reports are issued or the date that the \nGIA for the Surplus Host Unit becomes effective.  If an Interconnection \nFacilities Study is not necessary, the Transmission Provider shall tender a \ndraft pro forma GIA or an amended GIA that conforms to the currently \neffective pro forma GIA, as applicable by the later of thirty (30) Calendar \nDays after the Interconnection Customer communicates its election to \nproceed with Surplus Interconnection Service request, or the date that the \nGIA for the Surplus Host Unit becomes effective.  \n \n \nInterconnection Customer shall submit an executed Energy Displacement \nAgreement and Monitoring and Consent Assignment to the Transmission \nProvider prior to the conclusion of negotiations for the associated GIA, \npursuant to Section 11 of this GIP.  The executed Monitoring and Consent \nAgreement shall be in the form of Appendix 11 of the GIP to be effective \nupon execution of a GIA and must remain in effect during the term of the"},{"page":149,"startToken":39896,"endToken":40150,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nGIA.    \n \n \nThe executed Energy Displacement Agreement shall be in the form of \nAppendix 12 of the GIP to be effective upon execution of a GIA and must \nremain in effect during the term of the GIA.  If the Interconnection \nCustomer fails to provide an executed Energy Displacement Agreement \nand a Monitoring and Consent Agreement to the Transmission Provider \nprior to the conclusion of negotiations for the associated GIA, the \nTransmission Provider will deem the Interconnection Request withdrawn \npursuant to Section 3.6 of this GIP. \n \n \nIf at any time prior to execution of the GIA the Energy Displacement \nAgreement or Monitoring and Consent Agreement required above is no \nlonger in effect, the Interconnection Request for Surplus Interconnection \nService shall be deemed to have been withdrawn. \n \n3.3.1.3 Requirements for continuation of Surplus Interconnection Service \nafter retirement or cessation of commercial operation of an Existing \nGenerating Facility \n \n1. \nIn the event that the Interconnection Customer seeks to continue Surplus \nInterconnection Service following the retirement and permanent cessation \nof commercial operation of the Existing Generating Facility associated \nwith that Surplus Interconnection Service, Transmission Provider shall \npermit the Surplus Interconnection Service to continue for a limited period \nnot to exceed one (1) year if the Existing Generating Facility retired and if \nthe following conditions are met: \n \n(i) \nTransmission Provider studied the Surplus Interconnection Service \nGenerating Facility for sole operation at that Point of"},{"page":150,"startToken":40150,"endToken":40410,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nInterconnection as a part of Interconnection Study for the Surplus \nInterconnection Service Generating Facility, and such studies \nconfirm that the Surplus Interconnection Service Generating \nFacility can be solely and reliably operated after the retirement of \nthe Existing Generating Facility; and \n \n(ii) \nThe Existing Generating Facility Interconnection Customer must \nprovide written consent to the continued operation of the Surplus \nInterconnection Service Generating Facility at either: (a) the \nlimited level of Surplus Interconnection Service that is reflected in \nthe Surplus Interconnection Service Generating Facility’s \nGenerator Interconnection Agreement; or (b) at any level below \nsuch limit. \n \n3.3.1.4 Additional Requirements for Interconnection Requests Proposing to \nShare Interconnection Customer Interconnection Facilities  \n \nInterconnection Customer may submit an Interconnection Request that proposes \nto share Interconnection Customer Interconnection Facilities with one or more \nexisting projects or pending Interconnection Requests.  Interconnection Requests \nproposing such an arrangement shall so indicate in their Interconnection Request \nand attach a consent agreement executed by all Interconnection Customers with \nprojects that propose to connect, or are connected, to the shared Interconnection \nCustomer Interconnection Facilities.  After an Interconnection Request has been \nsubmitted, an Interconnection Customer may only propose to share \nInterconnection Customer Interconnection Facilities as part of a Point of \nInterconnection modification.  Such consent agreement shall, in accordance with \nthe Business Practices Manuals, describe the proposed configuration of the \nprojects, the proposed ownership of the Interconnection Customer Interconnection \nFacilities, the division of rights and responsibilities among the parties with respect"},{"page":151,"startToken":40410,"endToken":40732,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nto operations, maintenance, and repair of the Interconnection Customer \nInterconnection Facilities, and such other information regarding the operation of \nthe Generating Facilities under this arrangement as may be specified in the \nGenerator Interconnection Business Practice Manual. The consent agreement \nshall indicate the parties’ consent to sharing the Interconnection Customer \nInterconnection Facilities in the manner described in the Interconnection \nRequest(s).  Interconnection Requests from multiple Interconnection Customers \nfor multiple Generating Facilities that share a site must include a contract or other \nagreement that allows for shared land use as specified in section 7.2.1.1.ii.b.3.  \n \n3.3.1.5 Evaluation Process for Interconnection Requests Proposing to Share \nInterconnection Customer Interconnection Facilities \n  \nInterconnection Requests proposing shared Interconnection Customer \nInterconnection Facilities shall require the consent of the Transmission Provider \nto proceed, which consent shall not be unreasonably withheld, conditioned, or \ndelayed. The Transmission Provider shall review Interconnection Requests \nproposing to share Interconnection Customer Interconnection Facilities amongst \nmultiple projects to confirm compliance with the requirements of Section 3.3.1.4 \nof these Generator Interconnection Procedures, that all Interconnection Customer \nresponsibilities have been appropriately accounted for, and that all parties have \nconsented to the described arrangement.  The Transmission Provider shall \ncomplete this review and notify the parties whether the Transmission Provider \nconsents to the proposed arrangement no later than five (5) days prior to the start \nof the Scoping Meeting in which their requests are discussed, or within ten (10) \nBusiness Days after receipt if the consent agreement is submitted as part of a \nPoint of Interconnection modification.  In the event that the Transmission \nProvider does not consent, the Transmission Provider shall provide a written \nstatement of the reasons for such decision to each of the parties.  Interconnection \nRequests that do not receive the Transmission Provider’s consent for the sharing"},{"page":152,"startToken":40732,"endToken":41054,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nof Interconnection Customer Interconnection Facilities may be revised and \nresubmitted for inclusion in the applicable cycle prior to the start of DPP Phase I.  \nIn the event that the consent agreement is submitted as part of a Point of \nInterconnection modification, the consent for the sharing of Interconnection \nCustomer Interconnection Facilities may be revised and resubmitted within five \n(5) Business Days of receiving the Transmission Provider’s written statement of \nreasons. \n \nAny Interconnection Customer that has an Interconnection Request pending in the \nDPP as of August 14, 2019 and that intends to share Interconnection Customer \nInterconnection Facilities for that Interconnection Request with one or more \nexisting projects or other Interconnection Requests shall satisfy each of the terms \nof Sections 3.3.1.4 and 3.3.1.5 of these Generator Interconnection Procedures, \nprior to the start of GIA negotiations for any Interconnection Request that remains \npending in the DPP and that will participate in the sharing arrangement. \n \n3.3.2 Acknowledgment of Interconnection Request. \nTransmission Provider shall acknowledge receipt of the Interconnection Request within \nfive (5) Business Days of receipt of the Interconnection Request.  Transmission Provider \nshall tender to Interconnection Customer or MHVDC Connection Customer a copy of the \ncountersigned Interconnection Study Agreement within ten (10) Business Days after the \nTransmission Provider notifies Interconnection Customer that it has accepted the \nInterconnection Request as valid pursuant to Section 3.3.3 of this GIP.  In addition, \nwithin ten (10) Business Days after notifying Interconnection Customer that an \nInterconnection Request is accepted as valid, Transmission Provider shall submit a \nsummary of the Interconnection Request to Interconnection Customer or MHVDC \nConnection Customer and likely affected Transmission Owners.  All acknowledgments \nand other communications may be made via e-mail and/or other electronic means. \n \n3.3.3 Review of Interconnection Request and Cure of Deficiencies."},{"page":153,"startToken":41054,"endToken":41451,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nAn Interconnection Request will not be considered to be a valid request until all items in \nSection 3.3.1 have been received by Transmission Provider.  If an Interconnection \nRequest fails to meet the requirements set forth in Section 3.3.1, Transmission Provider \nshall notify Interconnection Customer or MHVDC Connection Customer within fifteen \n(15) Business Days of receipt of the initial Interconnection Request either that the \nTransmission Provider has accepted the Interconnection Request as valid or has \ndetermined that the Interconnection Request does not constitute a valid request due to one \nor more deficiencies.  In the event Transmission Provider determines that the \nInterconnection Request does not constitute a valid request, Transmission Provider shall \nalso provide an explanation of the reasons for such determination. Interconnection \nCustomer shall have ten (10) Business Days from the date that the Transmission Provider \nidentifies the Interconnection Request as deficient to provide the additional requested \ninformation needed to constitute a valid request.  In the event Transmission Provider \ndiscovers or verifies a deficiency later in the GIP process, Transmission Provider will \nnotify Interconnection Customer or MHVDC Connection Customer as soon as \npracticable.  At any time, if Transmission Provider finds that the technical data provided \nby Interconnection Customer is incomplete or contains errors, Transmission Provider will \nissue a deficiency notice to Interconnection Customer and Interconnection Customer and \nTransmission Provider shall work expeditiously and in good faith to remedy such issues.   \nInterconnection Customer or MHVDC Connection Customer shall provide Transmission \nProvider the additional requested information needed to constitute a valid request no later \nthan ten (10) Business Days after the request is made.  Failure by Interconnection \nCustomer or MHVDC Connection Customer to comply with this Section 3.3.3 will result \nin the Interconnection Request not being processed until such deficiency is cured.  In the \nevent that the deficiency is not cured within the required ten (10) business day period, the \nInterconnection Request shall immediately be deemed withdrawn as of the date of such \ndeadline without any further cure period and the Non-Refundable Deposit 1 (D1) shall be \nforfeited.  The Transmission Provider shall provide written notice to Interconnection \nCustomer or MHVDC Connection Customer of the deemed withdrawal and an \nexplanation of the reasons for such deemed withdrawal upon the expiration of the ten"},{"page":154,"startToken":41451,"endToken":41799,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n(10) business day period.  Any refunds of deposits other than the D1 will be processed in \naccordance with Section 3.6 of this GIP.  \n \n3.3.4  Customer Engagement Window  \nImmediately after the application deadline for a Group Study, Transmission Provider \nshall open a eighty-five (85) Calendar Day period (Customer Engagement Window).  \nDuring the Customer Engagement Window, Transmission Provider, applicable \nTransmission Owner and Interconnection Customer shall conduct the activities set forth \nin sections 3.3.5 (Scoping Meeting), 7.1.1 (Screening Analysis Prior to Definitive \nPlanning Phase I), and section 7.2.1.3 (Transmission Provider Review of Site Control \nSufficiency).  Notwithstanding the preceding requirements and upon written consent of \nall Interconnection Customers within the Group, Transmission Provider may shorten the \nCustomer Engagement Window and begin the Group Study.  Within thirty (30) Business \nDays of the opening of the Customer Engagement Window, Transmission Provider shall \npost on its OASIS a list of Interconnection Requests for that Group.  The list shall \nidentify, for each anonymized Interconnection Request: (1) the requested amount of \nInterconnection Service; (2) the location by county and state; (3) the station or \ntransmission line or lines where the interconnection will be made; (4) the projected In-\nService Date; (5) the type of Interconnection Service requested; and (6) the type of \nGenerating Facility or Facilities to be constructed, including fuel types, such as coal, \nnatural gas, solar, or wind.  The Transmission Provider must ensure that project \ninformation is anonymized and does not reveal the identity or commercial information of \ninterconnection customers with submitted requests.  During the Customer Engagement \nWindow, Transmission Provider shall provide to Interconnection Customer a non-binding \nupdated good faith estimate of the cost and timeframe for completing the Group Study \nand a Interconnection Study Agreement to be executed prior to the close of the Customer \nEngagement Window. \n \nTransmission Provider shall initiate the Group Study described in Section 7 of this GIP 5 \nBusiness Days following the close of the Customer Engagement Window."},{"page":155,"startToken":41799,"endToken":42125,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \n3.3.5 Scoping Meeting. \nDuring the Customer Engagement Window, the Transmission Provider shall establish a \ndate agreeable to Interconnection Customer and Transmission Owner for a Scoping \nMeeting, and such date shall be at least five (5) Business Days prior to and no more than \nforty-five (45) Calendar days prior to the kick-off of the Definitive Planning Phase, \nunless otherwise mutually agreed upon by Transmission Provider, Transmission Owner \nand Interconnection Customer or MHVDC Connection Customer.  The Transmission \nProvider, Interconnection Customer, or MHVDC Connection Customer, and \nTransmission Owner must attend the Scoping Meeting.  Transmission Provider shall use \nReasonable Efforts to include any other Affected System Operators in the Scoping \nMeeting. \n \nThe purpose of the Scoping Meeting shall be to discuss alternative interconnection \noptions, to exchange information including any transmission data that would reasonably \nbe expected to impact such interconnection options, to analyze such information and to \ndetermine the potential feasible Points of Interconnection.  For purposes of clustering \nInterconnection Requests, Transmission Provider or Transmission Owner may propose \nchanges to the requested Point of Interconnection to facilitate efficient interconnection of \nInterconnection Customers at common Point(s) of Interconnection.  The requesting \nTransmission Provider or Transmission Owner shall notify Interconnection Customers in \nwriting of any intended changes to the requested Point of Interconnection within two (2) \nBusiness Days after the conclusion of the Scoping Meeting, and the Point of \nInterconnection shall only change upon mutual agreement.  Transmission Provider, \nTransmission Owner and Interconnection Customer or MHVDC Connection Customer \nwill bring to the meeting such technical data including, but not limited to, known:  (i) \ngeneral facility loadings, (ii) general instability issues, (iii) general short circuit issues, \n(iv) general voltage issues including voltage and frequency ride-through capabilities for \nthe Generating Facility, (v) general power quality issues including voltage flicker, \nharmonics, (vi) general reliability issues; and (vii) diagrams and/or layout of applicable"},{"page":156,"startToken":42125,"endToken":42500,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nsubstations as may be reasonably required to accomplish the purpose of the meeting.  \nTransmission Provider and Interconnection Customer or MHVDC Connection Customer \nwill also bring to the meeting personnel and other resources as may be reasonably \nrequired to accomplish the purpose of the meeting in the time allocated for the meeting.  \nOn the basis of the meeting, Interconnection Customer or MHVDC Connection Customer \nmay modify its Point of Interconnection/Connection.  Notwithstanding the foregoing, \nmodifications to the Point of Interconnection are prohibited if the modification causes the \nproject to move from one study region to another once the Transmission Provider has \nnotified Interconnection Customers that its Interconnection Request will be included in a \nstudy group pursuant to Section 4.1.1.3 of this GIP.  Interconnection Customer or \nMHVDC Connection Customer will have until the beginning of DPP Phase I submit to \nTransmission Provider its modified Point of Interconnection/Connection as a result of the \nScoping Meeting; if the modified Point of Interconnection includes shared \nInterconnection Customer Interconnection Facilities, the Interconnection Customer shall \nsubmit a consent agreement that meets requirements of Section 3.3.1.4 by the beginning \nof DPP Phase I.  The duration of the meeting shall be sufficient to accomplish its \npurpose. \n \n3.4 \nOASIS Posting. \n3.4.1 Transmission Provider will maintain on its OASIS or its website a list of all \nInterconnection Requests.  If Transmission Provider posts this information on its website, \na link to the information must be provided on Transmission Provider’s OASIS site.  The \nlist will identify, for each Interconnection Request:  (i) the maximum summer and winter \nmegawatt electrical output; (ii) the location by county and state; (iii) the substation or \ntransmission line or lines where the interconnection will be made; (iv) the projected In-\nService Date; (v) the status of the Interconnection Request, and when applicable, \nDefinitive Planning Phase Queue Position; (vi) the type of Interconnection Service being \nrequested or whether the Interconnection Request is for Injection Rights; (vii) the \navailability of any studies related to the Interconnection Request; (viii) the date of the \nInterconnection Request; (ix) the type of Generating Facility to be constructed including"},{"page":157,"startToken":42500,"endToken":42861,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ntechnology and fuel type); (x) for Interconnection Requests that have not resulted in a \ncompleted interconnection, an explanation as to why it was not completed; (xi) associated \nInterconnection System Impact Study phase costs by Definitive Planning Phase; and (xii) \nfor a Generating Facility Replacement, the planned date of cessation of operation for the \nExisting Generating Facility or actual date if the Existing Generating Facility already has \nceased commercial operations, the expected Commercial Operation Date of the \nreplacement facility and requested Interconnection Service.  Except for projects \nsubmitted through the ERAS process as noted in Section 3.9, the list will not disclose the \nidentity of Interconnection Customer or MHVDC Connection Customer until \nInterconnection Customer or MHVDC Connection Customer executes a GIA or a TCA or \nrequests that Transmission Provider file an unexecuted GIA or TCA with FERC.  \nTransmission Provider shall post to its OASIS site or its website any deviations from the \nstudy timelines set forth herein.  Interconnection Study reports shall be posted to the \nTransmission Provider’s OASIS site or its website prior to the meeting between \nInterconnection Customer and Transmission Provider to discuss the applicable study \nresults.  Transmission Provider shall also post any known deviations in the Generating \nFacility’s In-Service Date.  \n \nTransmission Provider will also maintain on its OASIS or its website a Transmission \nOwner’s general non-binding indication as to whether the Transmission Owner intends to \nelect to fund the capital costs (self-fund) for Network Upgrades and System Protection \nFacilities.  If Transmission Provider posts this information on its website, a link to the \ninformation must be provided on Transmission Provider’s OASIS site. \n \n3.4.2 Transmission Provider will maintain on its OASIS or its website summary \nstatistics related to processing Interconnection Studies pursuant to Interconnection \nRequests, updated quarterly. If Transmission Provider posts this information on its \nwebsite, a link to the information must be provided on Transmission Provider’s OASIS \nsite. For each calendar quarter, Transmission Providers must calculate and post the \ninformation detailed in sections 3.4.2.1 through 3.4.2.6.  For the Study Metrics provided"},{"page":158,"startToken":42861,"endToken":43179,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nin Sections 3.4.2.2 and 3.4.2.3, if the relevant 10 Business Days includes one or more \nholidays, then the number of Business Days will be correspondingly extended and the \nstudy will not be considered untimely if completed within the extended period. \n \n3.4.2.1 Preliminary System Impact Studies in Definitive Planning Phase I \nProcessing Time.  \n \n(A)  \nNumber of Interconnection Requests that had Preliminary System Impact \nStudies in Definitive Planning Phase I completed within Transmission \nProvider’s coordinated region during the reporting quarter,  \n(B)  \nNumber of Interconnection Requests that had Preliminary System Impact \nStudies in Definitive Planning Phase I completed within Transmission \nProvider’s coordinated region during the reporting quarter that were \ncompleted more than the sum of 10 Business Days for Model Review and \n65 Calendar Days for the Preliminary System Impact Study, as per the \ntimelines listed in 7.3.1 of the Generator Interconnection Procedures \n(“GIP”) after the periodic, scheduled start of the Definitive Planning Phase \nI, which shall commence in conformity with Section 3.3.1 of the GIP, \n(C)  \nAt the end of the reporting quarter, the number of active valid \nInterconnection Requests with ongoing incomplete Preliminary System \nImpact Studies in Definitive Planning Phase I exceeding the sum of 10 \nBusiness Days for Model Review and 65 Calendar Days for the \nPreliminary System Impact Study report as per the timelines listed in 7.3.1 \nof the GIP, after the periodic, scheduled start of the Definitive Planning \nPhase I,  \n(D)  \nMean time (in Calendar Days), for Preliminary System Impact Studies in \nDefinitive Planning Phase I completed within Transmission Provider’s \ncoordinated region during the reporting quarter, from the periodic, \nscheduled start of the Definitive Planning Phase I, to the date when \nTransmission Provider provided the completed Preliminary System Impact"},{"page":159,"startToken":43179,"endToken":43496,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nStudy report to the Interconnection Customer, \n(E)  \nPercentage of Interconnection Requests with Preliminary System Impact \nStudies in Definitive Planning Phase I exceeding the sum of 10 Business \nDays for Model Review and 65 Calendar Days for the Preliminary System \nImpact Study report to complete this reporting quarter, calculated as the \nsum of 3.4.2.1(B) plus 3.4.2.1(C) divided by the sum of 3.4.2.1(A) plus \n3.4.2.1(C)).  \n \n3.4.2.2 Revised System Impact Studies in Definitive Planning Phase II \nProcessing Time.  \n \n(A)  \nNumber of Interconnection Requests that had Revised System Impact \nStudy reports in Definitive Planning Phase II completed within \nTransmission Provider’s coordinated region during the reporting quarter, \n(B)  \nNumber of Interconnection Requests that had Revised System Impact \nStudies in Definitive Planning Phase II completed within Transmission \nProvider’s coordinated region during the reporting quarter that were \ncompleted more than the sum of 6 Business Days for Model Review and \n75 Calendar Days for the Revised System Impact Study report after the \ndate the Interconnection Customer Decision Point I window expired, as \nper the timelines listed in Section 7.3.2 of the GIP, \n(C)  \nAt the end of the reporting quarter, the number of active valid \nInterconnection Requests with ongoing incomplete Revised System \nImpact Studies in Definitive Planning Phase II exceeding the sum of 6 \nBusiness Days for Model Review and75 Calendar Days for the Revised \nSystem Impact Study report, as per the timelines listed in 7.3.2 of the GIP, \nafter the Interconnection Customer Decision Point I window expired,  \n(D)  \nMean time (in Calendar Days), for Revised System Impact Studies in \nDefinitive Planning Phase II completed within Transmission Provider’s \ncoordinated region during the reporting quarter, from the day after the"},{"page":160,"startToken":43496,"endToken":43807,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nInterconnection Customer Decision Point I window expired to the date \nwhen Transmission Provider provided the completed Revised System \nImpact Study report to the Interconnection Customer, \n(E)  \nPercentage of Interconnection Requests with Revised System Impact \nStudy reports in Definitive Planning Phase II exceeding the sum of 6 \nBusiness Days for Model Review and 75 Calendar Days for the Revised \nSystem Impact Study, to complete this reporting quarter, calculated as the \nsum of 3.4.2.2(B) plus 3.4.2.2(C) divided by the sum of 3.4.2.2(A) plus \n3.4.2.2(C)).  \n \n3.4.2.3 Final System Impact Studies in Definitive Planning Phase III \nProcessing Time.  \n \n(A)  \nNumber of Interconnection Requests that had Final System Impact Study \nreports in Definitive Planning Phase III completed within Transmission \nProvider’s coordinated region during the reporting quarter,  \n(B)  \nNumber of Interconnection Requests that had Final System Impact Study \nreports in Definitive Planning Phase III completed within Transmission \nProvider’s coordinated region during the reporting quarter that were \ncompleted more than the sum of 6 Business Days for Model Review and \n50 Calendar Days as per the timelines listed in 7.3.3 of the GIP, after the \nInterconnection Customer Decision Point II window expired, \n(C)  \nAt the end of the reporting quarter, the number of active valid \nInterconnection Requests with ongoing incomplete Final System Impact \nStudy reports in Definitive Planning Phase III exceeding the sum of 6 \nBusiness Days for Model Review and 50 Calendar Days, as per the \ntimelines listed in 7.3.3 of the GIP, after the Interconnection Customer \nDecision Point II window expired,  \n(D)  \nMean time (in Calendar Days), for Final System Impact Studies in \nDefinitive Planning Phase III completed within Transmission Provider’s"},{"page":161,"startToken":43807,"endToken":44087,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ncoordinated region during the reporting quarter, from the day after the \nInterconnection Customer Decision Point II window expired to the date \nwhen Transmission Provider provided the completed Final System Impact \nStudy to the Interconnection Customer,  \n(E)  \nPercentage of Interconnection Requests with Final System Impact Study \nreports in Definitive Planning Phase III exceeding the sum of 6 Business \nDays for Model Review and 50 Calendar Days to complete this reporting \nquarter, calculated as the sum of 3.4.2.3(B) plus 3.4.2.3(C) divided by the \nsum of 3.4.2.3(A) plus 3.4.2.3(C)).  \n \n3.4.2.4 Interconnection Facilities Studies Processing Time.  \n \n(A)  \nNumber of Interconnection Requests that had Interconnection Facilities \nStudies for Interconnection Facilities or Connection Facilities that are \ncompleted within Transmission Provider’s coordinated region during the \nreporting quarter,  \n(B)  \nNumber of Interconnection Requests that had Interconnection Facilities \nStudies for Interconnection Facilities or Connection Facilities that are \ncompleted within Transmission Provider’s coordinated region during the \nreporting quarter that were completed more than 90 Calendar Days after \nthe Interconnection Customer Decision Point I window expired, \n(C)  \nAt the end of the reporting quarter, the number of active valid \nInterconnection Requests with ongoing incomplete Interconnection \nFacilities Studies for Interconnection Facilities or Connection Facilities \nwhere such Interconnection Requests had exceeded more than 90 Calendar \nDays,  \n(D)  \nMean time (in Calendar Days), for Interconnection Facilities Studies for \nInterconnection Facilities or Connection Facilities completed within \nTransmission Provider’s coordinated region during the reporting quarter, \ncalculated from the day after the Interconnection Customer Decision Point"},{"page":162,"startToken":44087,"endToken":44366,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nI window expired to the date when Transmission Provider provided the \ncompleted Interconnection Facilities Study report for Interconnection \nFacilities or Connection Facilities to the Interconnection Customer,  \n(E)  \nPercentage of Interconnection Requests with delayed Interconnection \nFacilities Study report for Interconnection Facilities or Connection \nFacilities this reporting quarter, calculated as the sum of 3.4.2.4(B) plus \n3.4.2.4(C) divided by the sum of 3.4.2.4(A) plus 3.4.2.4(C)). \n  \n3.4.2.5 Interconnection Facilities Studies for Network Upgrades Processing \nTime.  \n \n(A)  \nNumber of Interconnection Requests that had Interconnection Facilities \nStudy reports for Network Upgrades that are completed within \nTransmission Provider’s coordinated region during the reporting quarter,  \n(B)  \nNumber of Interconnection Requests that had Interconnection Facilities \nStudy reports for Network Upgrades that are completed within \nTransmission Provider’s coordinated region during the reporting quarter \nthat were completed more than 90 Calendar Days after completion of the \nDefinitive Planning Phase III Final System Impact Study, \n(C)  \nAt the end of the reporting quarter, the number of active valid \nInterconnection Requests with ongoing incomplete Interconnection \nFacilities Study reports for Network Upgrades where such Interconnection \nRequests had exceeded more than 90 Calendar Days,  \n(D)  \nMean time (in Calendar Days), for Interconnection Facilities Studies for \nNetwork Upgrades completed within Transmission Provider’s coordinated \nregion during the reporting quarter, calculated from the day after \ncompletion of the Definitive Planning Phase III Final System Impact \nStudy to the date when Transmission Provider provided the completed \nInterconnection Facilities Study report for Network Upgrades to the \nInterconnection Customer,"},{"page":163,"startToken":44366,"endToken":44634,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n(E)  \nPercentage of Interconnection Requests with delayed Interconnection \nFacilities Studies for Network Upgrades this reporting quarter, calculated \nas the sum of 3.4.2.5(B) plus 3.4.2.5(C) divided by the sum of 3.4.2.5(A) \nplus 3.4.2.5(C).  \n \n3.4.2.6 Interconnection Requests Withdrawn from Interconnection  \nQueue.  \n \n(A)  \nNumber of Interconnection Requests withdrawn from Transmission \nProvider’s interconnection queue during the reporting quarter,  \n(B)  \nNumber of Interconnection Requests withdrawn from Transmission \nProvider’s interconnection queue during the reporting quarter before the \nstart of the Definitive Planning Phase I, pursuant to Section 3.3.1 of the \nGIP,  \n(C)  \nNumber of Interconnection Requests withdrawn from Transmission \nProvider’s interconnection queue during the reporting quarter from start of \nthe Definitive Planning Phase I, pursuant to Section 3.3.1 of the GIP, to at \nor before the Interconnection Customer Decision Point I window expired, \n(D)  \nNumber of Interconnection Requests withdrawn from Transmission \nProvider’s interconnection queue during the reporting quarter after the \nInterconnection Customer Decision Point I window expired to at or before \nthe Interconnection Customer Decision Point II window expired,  \n(E)  \nNumber of Interconnection Requests withdrawn from Transmission \nProvider’s interconnection queue during the reporting quarter after the \nInterconnection Customer Decision Point II window expired to before \nexecution of a Generator Interconnection Agreement or Interconnection \nCustomer requests the filing of an unexecuted, new interconnection \nagreement  \n(F) \nNumber of Interconnection Requests withdrawn from Transmission \nProvider’s interconnection queue after execution of a Generator"},{"page":164,"startToken":44634,"endToken":45014,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nInterconnection Agreement or Interconnection Customer requests the \nfiling of an unexecuted, new interconnection agreement,  \n(G)  \nMean time (in Calendar Days), for all withdrawn Interconnection \nRequests, from the date when the request was determined to be valid to \nwhen Transmission Provider received the request to withdraw from the \nqueue.  \n \n3.4.3   Transmission Provider is required to post on OASIS or its website the measures in \nparagraph 3.4.2.1(A) through paragraph 3.4.2.6(G) for each calendar quarter within 30 \nCalendar Days of the end of the calendar quarter.  Transmission Provider will keep the \nquarterly measures posted on OASIS or its website for three calendar years with the first \nrequired report to be in the first quarter of 2020. If Transmission Provider retains this \ninformation on its website, a link to the information must be provided on Transmission \nProvider’s OASIS site.  \n \n3.4.4  In the event that any of the values calculated in paragraphs 3.4.2.1(E), 3.4.2.2(E), \n3.4.2.3(E), 3.4.2.4(E), or 3.4.2.5(E) exceeds 25 percent for two consecutive calendar \nquarters, Transmission Provider will have to comply with the measures below for the \nnext four consecutive calendar quarters and must continue reporting this information until \nTransmission Provider reports four consecutive calendar quarters without the values \ncalculated in 3.4.2.1(E), 3.4.2.2(E), 3.4.2.3(E), 3.4.2.4(E), or 3.4.2.5(E)) exceeding 25 \npercent for two consecutive calendar quarters:  \n \n(i) \nTransmission Provider must submit a report to the Commission describing the \nreason for each Group Study, individual Interconnection Facilities Study, or \nRestudy pursuant to one or more Interconnection Request(s) that exceeded its \ndeadline completion  of each phase as specified in Sections 7.3.1, 7.3.2 and 7.3.3 \nof this GIP, and Section 7.5 of this GIP for restudies. Transmission Provider must \ndescribe the reasons for each study delay and any steps taken to remedy these \nspecific issues and, if applicable, prevent such delays in the future. The report"},{"page":165,"startToken":45014,"endToken":45331,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nmust be filed at the Commission within 45 Calendar Days of the end of the \ncalendar quarter.  \n \n(ii)  \nTransmission Provider shall aggregate the total number of employee-hours and \nthird party consultant hours expended towards interconnection studies within its \ncoordinated region that quarter and post on OASIS or its website.  If Transmission \nProvider posts this information on its website, a link to the information must be \nprovided on Transmission Provider’s OASIS site.  This information is to be \nposted within 30 Calendar Days of the end of the calendar quarter. \n \n3.5 \nCoordination with Affected Systems. \nExcept as modified by Sections 3.5.1 andthrough 3.5.23 of these GIP, Interconnection \nCustomer or MHVDC Connection Customer, Transmission Provider, Transmission \nOwner and Affected System Operator shall each coordinate and cooperate on studies \nrequired to determine the impact of the Interconnection Request on Affected Systems.  \nTransmission Provider will include such Affected System Operators, whose \nrepresentatives either abide by FERC’s Standards of Conduct pursuant to 18 C.F.R \nParts 37 and 358 or have executed a non-disclosure agreement with Transmission \nProvider, in all meetings held with Interconnection Customer as required by the GIP.  If \nthe Affected System is not under the functional control of Transmission Provider, the \nAffected System Operator’s procedures shall be applicable.  Interconnection Customer or \nMHVDC Connection Customer will be separately responsible to adhere to the Affected \nSystems Operator’s procedures and costs related to studies and modifications to the \nAffected System.   \n \nInterconnection Customer or MHVDC Connection Customer will cooperate with \nTransmission Provider in all matters related to the conduct of studies and the \ndetermination of modifications to Affected Systems.  Transmission Provider may limit \nInterconnection Service or Injection Rights for an Interconnection Request until needed \nreliability upgrades on an Affected System(s) are complete under separate agreements."},{"page":166,"startToken":45331,"endToken":45591,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nEach Interconnection Customer or MHVDC Connection Customer shall provide notice to \nTransmission Owner and Transmission Provider that the facilities built under such \nagreements are in service. \n3.5.1 Additional Requirements for Interconnection Requests Subject to JTIQ. \nTransmission Provider shall use the rules and procedures contained in Section \n9.4.2 of Rate Schedule 6 (MISO-SPP JOA) to apply to Interconnection Customers \nand Interconnection Requests that have been designated for inclusion in a JTIQ \nParticipation Group or a JTIQ Commitment Group. Interconnection Customers \nincluded in a JTIQ Screening Group, JTIQ Participation Group or a JTIQ  \nCommitment Group shall be responsible for adhering to all applicable \nrequirements set forth Section 9.4.2 of the Rate Schedule 6 (MISO-SPP JOA), \nthese Generator Interconnection Procedures, the GIA, and applicable JTIQ \nService Agreements. \n3.5.1.1:  Inclusion in a JTIQ Screening Group, JTIQ Participation Group, \nand JTIQ Commitment Group. \n(1) Interconnection Requests shall be included in the JTIQ Screening Group if \nthey are submitted into a DPP study group or an ERAS that: (1) has a study \ncommencement or kick off date that is after the date that the Parties’ respective \nBoards of Directors have approved a JTIQ Portfolio; and (2) has not commenced \nDPP Phase I studies or an ERAS as of the date that the Transmission Provider and \nSPP  have declared the JTIQ Portfolio fully subscribed. \n \n(2) Interconnection Requests shall be included in a JTIQ Participation Group if"},{"page":167,"startToken":45591,"endToken":45858,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nthey meet the following criteria: \n(a) \nthe Interconnection Request is determined to have an impact \ngreater than five percent (5%) distribution factor (OTDF or \nPTDF1) on one or more facilities of SPP’s transmission system modelled \nwith all transmission facilities rated 100 kV and above; and \n(b) the Interconnection Request is determined to have greater than \n1.00 MW (positive) impact on at least one JTIQ Upgrade \nincluded in the JTIQ Portfolio. \nAny new Interconnection Request for an Existing Generating Facility that is \nseeking to convert to or increase the level of NRIS service will only be included \nin the JTIQ Participation Group to the extent of any additional ERIS service \nrequested. \n(3) Interconnection Customers shall enter a JTIQ Commitment Group upon \nobtaining an effective GIA and JTIQ Commitment Agreement that obligate such \nInterconnection Customer to pay, and provide security for, JTIQ Generator \nCharges.   Placement into the applicable JTIQ Commitment Group shall be \ngoverned by the terms of the Commitment Agreement and Section 2 of \nAttachment JJJ to the Tariff.   \n3.5.2. Application of Affected Systems Coordination Procedures to \nInterconnection Requests Included in an Expedited Resource \n \n1  \nPower Transfer Distribution Factor (PTDF) - The percentage of power transfer flowing through a facility or \na set of facilities for a particular transfer when there are no contingencies. Outage Transfer Distribution \nFactor (OTDF) - The percentage of a power transfer that flows through the monitored facility for a \nparticular transfer when the contingency facility is switched out of service."},{"page":168,"startToken":45858,"endToken":46182,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nAddition Study \nThe Transmission Provider shall apply to ERAS Interconnection Requests, \nand the ERAS Interconnection Customer shall adhere to, the same \ncoordination procedures and same screening criteria applicable to \nInterconnection Requests included in a DPP Study Group with the \nfollowing exceptions: (1) The Transmission Provider will submit all \ninformation necessary to enable an Affected System to study the impacts \nof an ERAS Interconnection Request not later than ten (10) Calendar Days \nprior to the kickoff of the applicable ERAS study for such project; (2) The \nTransmission Provider will provide any affected systems analysis received \nfrom the affected system to the ERAS Interconnection Customer promptly \nupon receipt; (3) In the event that affected systems studies and cost \ninformation are not available at the time the EGIA is tendered, such EGIA \nshall include an obligation to execute any agreements for the study, \nconstruction, or funding of Network Upgrades identified by the affected \nsystem within fifteen (15) Calendar Days after such agreement is tendered \nfor execution to the Interconnection Customer; (4) The Transmission \nProvider shall submit ERAS Interconnection Requests to the applicable \naffected system individually and request that such affected system study \nthe impacts of ERAS Interconnection Requests on a serial basis; and (5) \nFor those affected systems where MISO and the affected system utilize a \nspecified point in MISO’s multi-phase process such as a Decision Point or \nphase kickoff date to establish the queue priority date of MISO \nInterconnection Requests, MISO shall assert a queue priority date for \nERAS projects as of the date MISO commences the ERAS System Impact \nStudy unless the controlling agreement between MISO and the affected \nsystem expressly provide an alternate queue priority date for ERAS \nprojects.  Interconnection requests with an earlier queue priority date as \ndetermined in accordance with this Section 9.4.3(a) will have a higher"},{"page":169,"startToken":46182,"endToken":46511,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nrelative queue priority than those with a later queue priority date. \n3.5.3. Application of Affected Systems Coordination Procedures to \nInterconnection Requests Seeking ZG Interconnection Service \nThe Transmission Provider shall apply to ZG Interconnection Requests, \nand the ZG Interconnection Customer shall adhere to, the same \ncoordination procedures and same screening criteria applicable to \nInterconnection Requests included in a DPP Study Group with the \nfollowing exceptions:  (1) The Transmission Provider will submit all \ninformation necessary to enable an Affected System to study the impacts \nof a ZG Interconnection Request not later than ten (10) Calendar Days \nprior to the kickoff of the applicable ZG Impact Assessment for such \nproject; (2) The Transmission Provider will provide any affected systems \nanalysis received from the affected system to the ZG  Interconnection \nCustomer promptly upon receipt; (3) In the event that affected systems \nstudies and cost information are not available at the time the ZGIA is \ntendered, such ZGIA shall include an obligation to execute any \nagreements for the study, construction, or funding of Network Upgrades \nidentified by the affected system within fifteen (15) Calendar Days after \nsuch agreement is tendered for execution to the Interconnection Customer; \n(4) The Transmission Provider shall submit ZG Interconnection Requests \nto the applicable affected system individually and request that such \naffected system study the impacts of ZG Interconnection Requests on a \nserial basis; and (5) For those affected systems where MISO and the \naffected system utilize a specified point in MISO’s multi-phase process \nsuch as a Decision Point or phase kickoff date to establish the queue \npriority date of MISO Interconnection Requests, MISO shall assert a \nqueue \npriority \ndate \nfor \nInterconnection \nRequests \nseeking \nZG \nInterconnection Service as of the date MISO commences the ZG Study \nunless the controlling agreement between MISO and the affected system \nexpressly provide an alternate queue priority date for ZG projects."},{"page":170,"startToken":46511,"endToken":46832,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nInterconnection requests with an earlier queue priority date as determined \nin accordance with this Section 3.5.3 will have a higher relative queue \npriority than those with a later queue priority date. \n \n3.6 \nWithdrawal. \nInterconnection Customer or MHVDC Connection Customer may withdraw its \nInterconnection Request at any time by written notice of such withdrawal to \nTransmission Provider.  In addition, if Interconnection Customer fails to adhere to all \nrequirements of the GIP, except as provided in Section 13.5 (Disputes), Transmission \nProvider shall deem the Interconnection Request to be withdrawn and shall provide \nwritten notice to Interconnection Customer or MHVDC Connection Customer of the \ndeemed withdrawal and an explanation of the reasons for such deemed withdrawal.  \nUnless otherwise provided in this GIP, upon receipt of such written notice, \nInterconnection Customer or MHVDC Connection Customer shall have fifteen (15) \nBusiness Days in which to either respond with information or actions that cure the \ndeficiency or to notify Transmission Provider of its intent to pursue Dispute Resolution. \n \nIn the event that an MHVDC Transmission Connection Request is withdrawn or deemed \nwithdrawn in accordance with the terms of Attachment GGG to the Tariff, then all \nInterconnection Requests associated with that MHVDC Transmission Connection \nRequest will also be deemed withdrawn. \n \nWithdrawal prior to or during Interconnection Customer Decision Point I shall result in \nthe loss of the Interconnection Customer’s or MHVDC Connection Customer’s \nDefinitive Planning Phase Queue Position.  Withdrawal after Interconnection Customer \nDecision Point I, but prior to or during Interconnection Customer Decision Point II shall \nresult in the loss of the Interconnection Customer’s or MHVDC Connection Customer’s \nDefinitive Planning Phase Queue Position and forfeiture of the Definitive Planning Phase \nentry milestone (M2) payment.  Withdrawal after Interconnection Customer Decision \nPoint II shall result in the loss of Interconnection Customer’s or MHVDC Connection"},{"page":171,"startToken":46832,"endToken":47168,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nCustomer’s Definitive Planning Phase Queue Position and forfeiture of the M2, M3 and \nM4 milestone payments, except as otherwise provided in Section 7.6.2 and 7.8. \n \nIf an Interconnection Customer or MHVDC Connection Customer disputes the \nwithdrawal and loss of its applicable queue position, then during Dispute Resolution, the \nInterconnection Customer’s or MHVDC Connection Customer’s Interconnection Request \nis eliminated from the queue until such time that the outcome of Dispute Resolution \nwould restore its applicable queue position.   \n \nAn Interconnection Customer or MHVDC Connection Customer that withdraws or is \ndeemed to have withdrawn its Interconnection Request shall pay to Transmission \nProvider all costs that Transmission Provider prudently (i) incurs prior to the \nTransmission Provider’s receipt of notice described above and (ii) will incur as a result of \nthe withdrawal.  Interconnection Customer or MHVDC Connection Customer must pay \nall monies due to Transmission Provider before it is allowed to obtain any \nInterconnection Study data or results.  \n \nTransmission Provider shall (i) update the OASIS list of Interconnection Requests and \n(ii) refund to Interconnection Customer or MHVDC Connection Customer any portion of \nthe Interconnection Customer’s or MHVDC Connection Customer’s study deposit that \nexceeds the costs that Transmission Provider has incurred or will incur as a result of the \nwithdrawal as described in Section 13.3, including interest earned on the Interconnection \nCustomer’s or MHVDC Connection Customer’s study deposit and Definitive Planning \nPhase entry milestone payment while held in Transmission Provider’s interest-bearing, \nmoney market account, or if such account does not exist, then the interest calculated in \naccordance with 18 C.F.R. Section 35.19a(a)(2)(iii).  In the event of such withdrawal, \nTransmission Provider, subject to the confidentiality provisions of Section 13.1, shall \nprovide, at Interconnection Customer’s or MHVDC Connection Customer’s request, all \ninformation that Transmission Provider developed for any completed study conducted up \nto the date of withdrawal of the Interconnection Request."},{"page":172,"startToken":47168,"endToken":47493,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \n3.7 \nAdditional requirements for Generating Facility Replacement Requests. \n \n3.7.1 Requirements for Replacement Generating Facility Requests. \ni)  \nExcept as provided in Section 3.7.1(i)(a) of this Attachment X, any Replacement \nGenerating Facility must connect to the Transmission System at the same \nelectrical Point of Interconnection (i.e. same voltage level at the interconnecting \nsubstation) as the Existing Generating Facility. \na. \nAn Interconnection Customer shall perform, and Transmission Provider \nshall validate an evaluation study utilizing the latest available DPP phase \nmodel to ensure the Replacement Generating Facility connecting to a \ndifferent Point of Interconnection will: (1) connect to the same voltage \nlevel unless the same voltage level is not available by the COD; (2) not \ncause new constraints, as demonstrated by a contingency analysis \nperformed in accordance with BPM-015; (3) and change the Power \nTransfer Distribution Factor less than 5% on any branch unless it is a zero \nimpedance element or a line on the shortest path without queued \nInterconnection Requests from the existing Point of Interconnection to the \nnew Point of Interconnection. \n \nii)  \nThe request for Generating Facility Replacement must be submitted to the \nTransmission Provider by the Interconnection Customer for its Existing \nGenerating Facility at least one (1) year prior to the date that the Existing \nGenerating Facility will cease operation unless the Existing Generating Facility is \nin suspension or approved for suspension pursuant to Section 38.2.7 of the Tariff \nor in Forced Outage, and at least one (1) year prior to the Commercial Operation \nDate for the Replacement Generating Facility.  An Interconnection Customer \nutilizing an extension to the Commercial Operation Date or In-Service Date as set \nforth in Section 4.4.4 of the GIP must submit the request for Generating Facility \nReplacement at least one (1) year prior to the extended Commercial Operation"},{"page":173,"startToken":47493,"endToken":47823,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nDate.  A unit with a surplus GIA may propose to replace its host Existing \nGenerating Facility should the Surplus Host Unit retire and does not submit a \ntimely replacement request.  The unit with a surplus GIA shall submit its \nreplacement request one (1) year prior to the proposed Commercial Operation \nDate of the Replacement Generating Facility.  For the Existing Generating \nFacility approved for suspension or in forced outage, the request for Generating \nFacility Replacement must be submitted prior to 25th cumulative month of \nsuspension or forced outage within 5 years period.  The request shall include the \nplanned or actual date of cessation of operation for the Existing Generating \nFacility and the expected Commercial Operation Date for the Replacement \nGenerating Facility.  The expected Commercial Operation Date of the \nReplacement Generating Facility must be at least one (1) Calendar Day after the \ndate the Existing Generating Facility ceases operations. \n \niii)  \nThe Interconnection Customer shall request only ER Interconnection Service for \nthe Replacement Generating Facility if the Existing Generating Facility has only \nER Interconnection Service. The request for NR Interconnection Service for the \nReplacement Generating Facility, when the Existing Generating Facility has only \nER Interconnection Service, shall be submitted as a separate Interconnection \nRequest and shall proceed through the Definitive Planning Phase cycle in the \nsame manner as an Interconnection Request for a new Generating Facility. The \nInterconnection Customer may request either ER Interconnection Service or NR \nInterconnection Service for the Replacement Generating Facility if the Existing \nGenerating Facility has NR Interconnection Service. Requests for ER or NR \nInterconnection Service that exceed the amount of Interconnection Service for the \nExisting Generating Facility shall be processed as a new Interconnection Request \nfor the amount of such excess pursuant to Section 3.7.1.iv of this Attachment X to \nthe Tariff. \n \niv)  \nIf the Replacement Generating Facility requires Interconnection Service (MW) in"},{"page":174,"startToken":47823,"endToken":48177,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nexcess of that of the Existing Generating Facility that is being replaced, \nInterconnection Customer shall initiate a separate request for Interconnection \nService in an amount (MW) equal to the excess. Such Interconnection Request \nshall be assigned a new Queue Position, and proceed through the Definitive \nPlanning Phase cycle in the same manner as an Interconnection Request for a new \nGenerating Facility. \n \nv)  \nIf the request for Generating Facility Replacement requests less Interconnection \nService (MW) than that of the Existing Generating Facility that is being replaced, \nthe owner shall be required to submit an Attachment Y Notice for the amount \n(MW) of such decrease in generating capacity to the Transmission Provider prior \nto the execution of the GIA of the Replacement Generating Facility or the election \nby the Interconnection Customer to proceed unexecuted.  If the Interconnection \nCustomer indicates in its Interconnection Request that the Reliability Assessment \nStudy shall include analysis of a retirement scenario, the timing of the associated \nAttachment Y will supersede the requirements of Section 38.2.7 of the Tariff, as \nthe Reliability Assessment Study completed as part of generator replacement \nprocess will determine the system impacts for the loss of the generation. \n \nvi)  \nExcept as provided in Section 3.7.1(vi)(a) of this Attachment X, no request for \nGenerating Facility Replacement may be made until twelve (12) months have \nelapsed from: (1) the date of any assignment of the Generator Interconnection \nAgreement applicable to the Existing Generating Facility, or (2) the date of sale or \nother transfer of such Existing Generating Facility. When an Existing Generating \nFacility is owned by more than one party and such coownership has existed for at \nleast twelve (12) months prior to the date that the request for Generating Facility \nReplacement has been made, the restrictions described in this paragraph on \ntransfers shall not preclude such co-owners from determining their respective \nownership percentages in the Replacement Generating Facility, provided that the \nownership interests in the Replacement Generating Facility is disclosed in the"},{"page":175,"startToken":48177,"endToken":48498,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nrequest of the Interconnection Customer that owns or controls the Existing \nGenerating Facility pursuant to an existing Generator Interconnection Agreement \nfor Generating Facility Replacement. Upon submission of a request for \nGenerating Facility Replacement, the Interconnection Customer shall not sell or \notherwise transfer the Existing Generating Facility, the Replacement Generating \nFacility, nor assign the applicable Generator Interconnection Agreement except as \nprovided in Section 3.7.1(vi)(a) of this Attachment X until such time as the \nTransmission Provider completes evaluation of the request for Generating Facility \nreplacement unless the Interconnection Customer first withdraws such request for \nGenerating Facility Replacement in writing. In the event that the Transmission \nProvider notifies Interconnection Customer that the request for Generating \nFacility Replacement has been granted, the prohibition on sales, transfers, or \nassignments not authorized by this Attachment X shall be extended in accordance \nwith Section 3.7.5 of this Attachment X. For purposes of this Section 3.7.1 (vi), \nprohibited assignments include assignments to affiliates pursuant to Article 19.1 \nof the pro forma Generator Interconnection Agreement or any analogous \nprovision in the applicable GIA. \na. An Interconnection Customer may: (1) sell or otherwise transfer its \nExisting Generating Facility, (2) assign its Generator Interconnection \nAgreement; or (3) sell or otherwise transfer a Replacement Generating \nFacility to an entity or entities meeting the requirements of Section \n3.7.1(vi)(a)(1) below without violating this Section 3.7.1(vi) if all of \nthe following conditions are satisfied prior to such sale, assignment or \ntransfer becoming effective: \n1. The Interconnection Customer that owns or controls the \nExisting Generating Facility pursuant to an existing Generator \nInterconnection Agreement demonstrates to the Transmission \nProvider that it both: \ni. \nHolds, directly or indirectly, not less than a 25% \nownership interest in each entity receiving the"},{"page":176,"startToken":48498,"endToken":48775,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\napplicable assignment or transfer as demonstrated \nthrough documentation of: (1) shares or a partnership \ninterests in the transferee/assignee; (2) a right to receive \nat least 25% of net proceeds from the sale of the \ntransferred or assigned generating facility; or (3) \nanother form of interest in the transferee/assignee that is \nrecognized by the Commission as equivalent to an \nownership interest; \nii. \nHas the documented right to direct the performance of \nsuch entity with respect to any obligation under MISO’s \nTariff  and Generator Interconnection Agreement \napplicable to the transferred Generating Facility; and \n2. The Interconnection Customer that owns or controls the \nExisting Generating Facility pursuant to an existing Generator \nInterconnection Agreement and the entity that received the \nassignment or transfer commit in documentation to be supplied \nto the Transmission Provider prior to the effective date of any \nsale, assignment or transfer: (i) that the Interconnection \nCustomer shall retain the ownership and control required by \nSection 3.7.1(vi)(a)(1) of this Attachment X until the \nReplacement Generating Facility achieves commercial \noperation in accordance with Section 3.7.5 of this Attachment \nX, unless the request for Generating Facility Replacement is \ndenied or withdrawn; (ii) that the entity receiving the \nassignment or transfer under this section 3.7.1(vi) of this \nAttachment X agrees not to further sell, transfer or assign its \ninterests in the Existing Generating Facility, Replacement \nGenerating Facility, or Generator Interconnection Agreement \nexcept in accordance with this Attachment X; and (iii) to \nprovide the Transmission Provider upon request with"},{"page":177,"startToken":48775,"endToken":49062,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ndocumentation demonstrating continued compliance with the \nrequirements of Section 3.7.1(vi) of this Attachment X at any \ntime prior to the date that the applicable Replacement \nGenerating Facility achieves commercial operation; and \n3.    The Interconnection Customer receives the consent of the \nTransmission Provider, which consent shall be granted upon \nthe Transmission Provider determining that the proposed \ntransfer(s) or assignment(s) comply with the requirements of \nSection 3.7.1(vi)(a) of these Generator Interconnection \nProcedures. \n \n \nA transfer, sale, or assignment of the Existing Generating Facility, Replacement \nGenerating Facility, or applicable GIA that violates this Section 3.7.1 (vi) or Section \n3.7.1(vi)(a) of Attachment X shall void the request for Generating Facility Replacement. \n \n3.7.1.1 Requirements for modification of Replacement Generating Facility Requests. \nThe request to modify the Replacement Generating Facility shall be submitted any time \nprior to the commencement of the evaluation process for Generating Facility \nReplacement requests. \n \n1) \nIf the revised planned date of cessation of operation for the Existing Generating \nFacility is prior to the planned date of cessation of operation specified in original \nrequest, a new request for Replacement Generating Facility must be submitted at \nleast one (1) year prior to the date that the Existing Generating Facility is planned \nto cease operation.  \n \n2) \nIf the revised planned date of cessation of operation for the Existing Generating \nFacility is after the planned date of cessation of operation specified in original \nrequest, a notification for Replacement Generating Facility must be submitted to \nthe MISO Resource Utilization team (resourceretirement@misoenergy.org) at least"},{"page":178,"startToken":49062,"endToken":49391,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nthirty (30) Calendar Days prior to the original date that the Existing Generating \nFacility is planned to cease operation.  The revised planned date of cessation must \nbe at least one (1) Calendar Day before the Commercial Operation Date of the \nReplacement Generating Facility, including any extension provided and utilized \nunder Section 4.4.4 of the GIP. \n \n3) \nIf the revised expected Commercial Operation Date for the Replacement \nGenerating Facility is after the expected Commercial Operation Date for the \nReplacement Generating Facility in the original request, a new request for \nReplacement Generating Facility must be submitted at least one (1) year prior to \nthe date that the Existing Generating Facility is planned to cease operation, unless \nthe Existing Generating Facility is in suspension pursuant to Section 38.2.7 of the \nTariff or in Forced Outage. \n \n3.7.2 Evaluation Process for Generating Facility Replacement Requests. \nThe Transmission Provider will evaluate Generating Facility Replacement requests in the \norder in which they are submitted.  The evaluation will consist of two studies: i) a \nReplacement Impact Study as set forth in Section 3.7.2.1 of the GIP, and ii) a Reliability \nAssessment Study as set forth in Section 3.7.2.2 of the GIP.  \n \nTransmission Provider shall use Reasonable Efforts to complete the Replacement Impact \nStudy and Reliability Assessment Study and share results with the Interconnection \nCustomer within one hundred eighty (180) Calendar Days of the request. \n \n3.7.2.1 Generating Facility Replacement—Replacement Impact Study. \nThe Replacement Impact Study will include analyses to determine if the Replacement \nGenerating Facility has a material adverse impact on the Transmission System when \ncompared to Existing Generating Facility. The Replacement Impact Study may include \nsteady-state (thermal/voltage), reactive power, short circuit/fault duty, and stability \nanalyses, as necessary, to ensure that required reliability conditions are studied. If the"},{"page":179,"startToken":49391,"endToken":49753,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nReplacement Impact Study identifies any materially adverse impact from operating the \nReplacement Generating Facility when compared to the Existing Generating Facility, \nsuch impacts shall be deemed a Qualified Change, and in order to move forward, the \nInterconnection Customer must submit all information and milestone payments necessary \nfor a valid Interconnection Request for a new Generating Facility pursuant to Section 3.3 \nof this GIP, be assigned queue priority as of the date such information and milestones are \nprovided, and proceed through the Definitive Planning Phase cycle as an Interconnection \nRequest for a new Generating Facility.  In such event, the Interconnection Customer shall \nbe subject to the timing and requirements of Section 38.2.7 of the Tariff for any \nretirement of the Existing Generating Facility. \n \n3.7.2.2 Generating Facility Replacement—Reliability Assessment Study \nThe Reliability Assessment Study for the time period between the date that the Existing \nGenerating Facility ceases commercial operations and the Commercial Operation Date \nincluding any extension provided under Section 4.4.4 of the GIP of the Replacement \nGenerating Facility shall evaluate the performance of the Transmission System to \ndetermine if thermal and/or voltage violations of applicable the Electric Reliability \nOrganization Standards and Transmission Owner planning criteria are caused by \nremoving the Existing Generating Facility from service prior to the Commercial \nOperation Date of the Replacement Generating Facility. This study shall compare the \nconditions on the Transmission System that would exist if the Existing Generating \nFacility is taken offline to the conditions on the Transmission System as they exist when \nthe Existing Generating Facility is online. The scope of Reliability Assessment Study \nmay include stability analysis as necessary. The Existing Generating Facility shall be \nresponsible for mitigating any reliability violation identified in the Reliability Assessment \nStudy and may not cease operations until all mitigations are implemented or are in \nservice. Mitigation for this interim period may, as applicable, include: (i) \nredispatch/reconfiguration through operator instruction; and (ii) remedial action scheme \nor any other operating steps depending upon the type of reliability violation identified."},{"page":180,"startToken":49753,"endToken":50072,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nThe Interconnection Customer may request in its Interconnection Request that the \nReliability Assessment Study include an analysis equivalent to an Attachment Y study, as \ndefined in Section 38.2.7 of the Tariff.  The Transmission Provider shall include such \nanalysis in the Reliability Assessment Study when requested.  After completion of the \nReliability Assessment Study with all reliability violations mitigated for the Existing \nGenerating Facility, the Interconnection Customer may choose to submit an Attachment \nY request to obtain suspension approval based on Reliability Assessment Study results \nbefore the GIA for the Replacement Generating Facility is executed or the \nInterconnection Customer elects to proceed unexecuted or sixty (60) days after the \nrequest for Generating Facility Replacement request is withdrawn.   \n \n3.7.3 Generating Facility Replacement - Notice to Proceed \nInterconnection Customer requesting Generating Facility Replacement shall inform \nTransmission Provider within thirty (30) Calendar Days after having received results of \nthe Replacement Impact Study and Reliability Assessment Study of its election to \nproceed and Transmission Provider will initiate an Interconnection Facilities Study or \ntender a draft GIA.  Interconnection Customer that fails to provide an election to proceed \nwithin thirty (30) Calendar Days will result in withdrawal of the Interconnection Request \npursuant to Section 3.6 of this GIP. \n \n3.7.4 Scope of Interconnection Facilities Study \nInterconnection Facilities Study focusing on the Interconnection Facilities for the \nReplacement Generating Facility will start, if the Transmission Provider determines such \na study is necessary, upon Interconnection Customer’s notice to proceed to the \nTransmission Provider after completion of the Replacement Impact Study and the \nReliability Assessment Study.  This Interconnection Facilities Study will identify \nestimates for cost and the time required to construct the Interconnection Facilities.  \nTransmission Provider shall use Reasonable Efforts to complete this portion of the \nInterconnection Facilities Study within ninety (90) Calendar Days."},{"page":181,"startToken":50072,"endToken":50415,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n3.7.5 GIA for Generating Facility Replacement. \n \nTransmission Provider shall tender a draft pro forma GIA or GIAs or, if deemed \nappropriate, an amended GIA or GIAs that conforms to the pro forma GIA in effect at the \ntime, within thirty (30) Calendar Days after the Interconnection Customer communicates \nits election to proceed with Generator Replacement if an Interconnection Facilities Study \nis not required or within thirty (30) Calendar Days after final Facility Study reports are \nprovided to the Interconnection Customer. An Interconnection Customer that transferred \nor assigned a Replacement Generating Facility to one or more entities consistent with the \nrequirements of 3.7.1(vi)(a) may elect for each such entity to receive a separate GIA for \nits Replacement Generating Facility. The draft pro forma GIA shall include updated \nappendices describing the timing of Generating Facility Replacement and a condition that \nthe GIA or GIAs cannot be assigned and the Replacement Generating Facility cannot be \ntransferred to any other Party, including an affiliate of the Interconnection Customer \nother than as allowed by Section 3.7.1(vi)(a) of this Attachment X, until such date as the \napplicable Replacement Generating Facility achieves commercial operation. A transfer, \nsale, or assignment of the Existing Generating Facility, Replacement Generating Facility, \nor applicable GIA that violates this Section 3.7.5 shall be void and constitute a material \nbreach of the GIA. \n \nIf the MW of a Generating Facility Replacement request is less than the MW of the \nExisting Generating Facility that is being replaced, the Interconnection Customer cannot \nmake any additional Generating Facility Replacement requests after the first GIA for the \nGenerating Facility Replacement is executed or the Interconnection Customer elects to \nproceed unexecuted. \n \n3.8 \nIdentification of Contingent Facilities. \nMISO identifies Contingent Facilities using the following three methods: \ni.  \nReview all transmission facilities included in Interconnection System Impact \nStudies performed for an Interconnection Request that are: (1) listed in Appendix"},{"page":182,"startToken":50415,"endToken":50743,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nA of the Transmission Provider’s Transmission Expansion Plan (MTEP) that are \nnot yet in service, unless the Transmission Provider determines through the \nexercise of engineering judgment and after consultation with the applicable \nTransmission Owner(s), that such project does not address an existing overload \nand will not impact the injection of the Interconnection Request, such as age \nrelated line renewal projects that are not Baseline Reliability Project; or (2) \nidentified as Network Upgrades through the System Impact Studies for higher \nqueued Interconnection Requests that are not yet in service. Contingent Facilities \nshall be identified from this list as those facilities that meet the following criteria: \na.  \nPower Transfer Distribution Factor or Outage Transfer Distribution Factor \n≥ 5% and;  \nb.  \nMW impact (Power Transfer Distribution Factor or Outage Transfer \nDistribution Factor multiplied by generator output of the Interconnection \nRequest) ≥ 5 MW, and; \nc.  \nMW impact (Power Transfer Distribution Factor or Outage Transfer \nDistribution Factor multiplied by generator output of the Interconnection \nRequest) ≥ 1% of the Facility Rating. \nii. \nAll Network Upgrades identified in the Final System Impact Study for a given \nInterconnection Request pursuant to Section 7.3.3.3 of this GIP. \niii.  \nCoordination with applicable Affected System parties to determine what \nContingent Facilities have been identified through Affected System studies based \non their respective criteria. \n \nThe Contingent Facilities identified for a given Interconnection Request are the total of \nall facilities identified through each of the foregoing three methods as well as all JTIQ \nUpgrades included in a JTIQ Portfolio that meet one of these foregoing methods, for \nwhich the Interconnection Customer has been designated for inclusion in the JTIQ \nParticipation Group.  Transmission Provider shall provide an initial list of Contingent \nFacilities at the start of the Interconnection Customer Decision Point II, which list shall \ninclude facilities identified in the Revised System Impact Study performed pursuant to"},{"page":183,"startToken":50743,"endToken":50989,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nSection 7.3.2.3, and the final list of Contingent Facilities shall be documented in \nAppendix A of the Generator Interconnection Agreement for such Interconnection \nRequest.  The estimated Interconnection Facility and/or Network Upgrade costs and \nestimated in-service completion time of each identified Contingent Facility shall be \nprovided in Appendix A of the Generator Interconnection Agreement for such \nInterconnection Request when this information is readily available and not commercially \nsensitive. \n \n3.9  \nExpedited Resource Addition Study. \n \n3.9.1  Requirements for Expedited Resource Addition Study. \nA request for processing through the Expedited Resource Addition Study made by \nan Interconnection Customer must meet the requirements listed in Section 3.3.1 \nabove, plus the following requirements: \n1. \nThe Interconnection Request shall be accompanied by a written \nverification from the RERRA (or its documented representative) where the \nload to be served by the Generating Facility is located, subject to the \nprocedures or methods the RERRA requires, that either: \n \ni. the new, incremental load addition claimed by the Interconnection \nCustomer is valid and not otherwise included in a resource plan or \nother process under the RERRA’s purview. \na. \nThe RERRA (or its documented representative) may \nprovide such written verification in conjunction with \nanother state or municipal agency or official (e.g. \neconomic development authority or governor’s office) to \nverify the new, incremental load addition above. \nor"},{"page":184,"startToken":50989,"endToken":51249,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nii. the Generating Facility proposed by the Interconnection Customer will \naddress a resource adequacy deficiency as determined by the RERRA, \nState, Load Serving Entity, or Interconnection Customer.  The \ndetermination can be supported by: \na. A state energy forecast, or other forward-looking forecast; \nb. Commencement of a state proceeding; \nc. Review of a RERRA, LSE, or other state resource plan or \ndocument, which may include, but is not limited to: integrated \nresource plans, procurement plans, or other plan or study types;  \nd. Response to a Request for Proposals (RFP); or \ne. Other process, or delegation of authority, as determined by the \nRERRA or RERRA regulations (including in retail choice \nstates). \n \n \nor \niii. If an Interconnection Customer’s new Generating Facility will address \na resource adequacy deficiency and will either: \n(1) serve retail choice load located in a state that limits the amount of \nload that can select retail choice to a percentage of the electric utility’s \naverage weather-adjusted retail sales;  \nor  \n(2) serve load in a retail choice state and will be located in a retail \nchoice state other than one that limits the amount of load that can \nselect retail choice to a percentage of the electric utility’s average \nweather adjusted retail sales, \nthen the Interconnection Customer will indicate the specific load on the \nInterconnection Request in Section 4.s of Appendix 1 and provide the \nevidence of determination in (ii) above, but will not be required to include"},{"page":185,"startToken":51249,"endToken":51541,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\na written verification from a RERRA as described in section 3.9.1(i) or \n(ii).  The Transmission Provider shall notify the respective RERRA that an \nInterconnection Request for a new Generating Facility has been submitted \nrequesting processing through the Expedited Resource Addition Study \nprocess and transmit a copy of the Interconnection Request to the \nrespective RERRA.  The RERRA shall have 10 Business Days from the \ndate of the Transmission Provider’s notification and the simultaneous \ntransmittal of the copy of the Interconnection Request to notify the \nTransmission Provider that the Interconnection Request should not be \nconsidered in the ERAS process. If no such notice is received at the end of \n10 Business Days or if the RERRA notifies the Transmission Provider of \nits non-opposition prior to the end of the 10 Business Days, the \nInterconnection Request shall be studied through the Expedited Resource \nAddition Study process provided it meets the requirements listed in \nSection 3.3.1 and Section 3.9.2. \n \nA RERRA’s written verification is not intended to constitute or provide evidence of any \nfinal determination of need or suitability of the project for any purpose by the issuing \nentity beyond requesting that the Transmission Provider apply the ERAS process for such \nproject.  \n \nand \n2.  \nAn executed agreement evidencing that the projects submitted for ERAS \nprocessing is intended to be used by the entity with the claimed resource \nadequacy and/or reliability need.  Such agreement shall take one of the \nfollowing forms: \na. \nA Load Serving Entity acknowledgement to self-supply; \nb. A Power Purchase Agreement (PPA) or similar off-take agreement \nbetween the Interconnection Customer submitting the project for"},{"page":186,"startToken":51541,"endToken":51847,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nERAS consideration and the entity with the load to be served \n(including, but not limited to, an Alternative Retail Electric Supplier or \nits Load Serving Entity); \nc. An agreement that calls for the Interconnection Customer to develop \nthe Generating Facility described in the Interconnection Request and \nsubsequently transfer ownership or control of such Generating Facility \n(Build-Own-Transfer Agreement) to the entity with the load to be \nserved (including, but not limited to, an Alternative Retail Electric \nSupplier or its Load Serving Entity); or \nd. Other agreement between the entity submitting the Interconnection \nRequest, including the RERRA verification letter as appropriate, and \nthe entity with the load to be served (including, but not limited to, an \nAlternative Retail Electric Supplier or its Load Serving Entity), stating \nthat the ERAS project will be used to meet an identified resource \nadequacy deficiency.  \n \nNo changes shall be made to the ERAS Interconnection Request after submission. \n \n3.9.2 Evaluation Process for Expedited Resource Addition Study. \nThe Transmission Provider will evaluate Expedited Resource Addition Study \nrequests in the order in which they are submitted using the time stamp from \nsubmission.  The Transmission Provider will limit the maximum number of the \nERAS Interconnection Requests studied in the ERAS process to no more than 68 \nprojects total until the sunset date noted in Section 3.9.9.  The Transmission \nProvider has carved out a maximum of 8 Interconnection Requests of the total 68 \nInterconnection Requests that may be submitted in accordance with 3.9.1.1(iii) to \nserve retail choice load and 10 Interconnection Requests of the total 68 \nInterconnection Requests that may be submitted by Independent Power Producers \n(IPPs) with agreements with entities other than Load Serving Entities to ERAS"},{"page":187,"startToken":51847,"endToken":52176,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nuntil the sunset date noted in Section 3.9.9.  The remaining 50 Interconnection \nRequests of the total 68 Interconnection Requests may be submitted by IPPs or \nLoad Serving Entities (LSEs) to serve non-retail choice load.   \nInterconnection Requests submitted by IPPs with agreements with entities other \nthan LSEs to ERAS will be counted first towards the 10 Interconnection Requests \ncap of the total 68 Interconnection Requests before the 50 Interconnection \nRequests to serve non-retail choice load.  After the 10 Interconnection Requests \nsubmitted by IPPs with agreements with entities other than LSEs are accepted by \nthe Transmission Provider, any subsequent Interconnection Request submitted by \nIPPs will count toward the remaining 50 Interconnection Requests to serve non-\nretail choice load. \nThe Transmission Provider will limit the maximum size of each ERAS Quarterly \nStudy Period to no more than 15 Interconnection Requests.  If more than 15 \nInterconnection Requests are submitted for one ERAS Quarterly Study Period, \nthose surpassing the limit will be studied in a subsequent ERAS study cycle in the \norder in which they were submitted. If an ERAS Interconnection Request is \nwithin a similar geographical area or impacts the same constraint as another \nERAS Interconnection Request within the same ERAS Quarterly Study Period, as \ndefined in the Generator Interconnection Business Process Manuals, then the later \nsubmitted request(s) will be studied in a subsequent ERAS study cycle.  \n \nAn Interconnection Request that does not meet the requirements of ERAS per \nSection 3.9.1 will be notified by the Transmission Provider and automatically \nmoved to the standard Definitive Planning Phase queue unless the customer \nchooses to opt out by notifying Transmission Provider.  If deemed ineligible for \nthe ERAS process, the project will forfeit its Non-Refundable Deposit D1. \n \nAn Interconnection Customer submitting an Interconnection Request to a standard \nDefinitive Planning Phase queue may also submit a request for ERAS for"},{"page":188,"startToken":52176,"endToken":52514,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nevaluation. If the request meets the requirements for ERAS processing set forth in \nSection 3.9.1, the Interconnection Request seeking processing through the \nstandard Definitive Planning Phase queue must be withdrawn from the Definitive \nPlanning Phase queue prior to ERAS kickoff.  Upon withdrawing from the \nDefinitive Planning Phase queue, the project will forfeit its Non-Refundable \nDeposit D1 and will be subject to penalties per Sections 7.6.2.1.1 and 7.8. \n \nAn Interconnection Request included in an active Definitive Planning Phase that \nhas not reached Decision Point II may withdraw from the Definitive Planning \nPhase and move their Interconnection Request to the ERAS if they meet the \nrequirements for ERAS processing.  The project will be subject to penalties per \nSections 7.6.2.1.1. and 7.8 and must meet the ERAS requirements in Section \n3.9.1.  Verification of Site Control will be specified in the Generator \nInterconnection Business Practice Manual to authenticate applicability. An \nInterconnection request that has been withdrawn from the Definitive Planning \nPhase after completion of Decision Point II may be moved to ERAS after a period \nof one year from the withdrawal date. \n \n3.9.3 The Study. \nThe Interconnection Study for ERAS will follow the same manner of NR \nInterconnection Study as noted in Sections 3.2.1.2 and 3.2.2.2 needed to integrate \nthe Generating Facility in the same manner as for any Generating Facility being \ndesignated as a Network Resource.  Transmission Provider will use Reasonable \nEfforts to study ERAS Interconnection Requests from all Interconnection \nCustomers regardless of Generating Facility within sixty (60) Calendar Days after \nthe kickoff date for such study.  The study will be performed for each \nInterconnection Request individually in a serial fashion based on their submission \ndate per ERAS Quarterly Study Period.  The study will result in a Final System \nImpact Study and any associated Interconnection Facilities Studies."},{"page":189,"startToken":52514,"endToken":52837,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nTransmission Provider shall include in the final study any Affected System Study \nresults and information regarding Network Upgrades from Affected Systems \nprovided the Affected System Study Reports are available. If Affected Systems \nanalysis is not available for inclusion in the final study, the Transmission Provider \nshall provide such analysis separately when received from the applicable Affected \nSystem. \n \n3.9.4 Notice to Proceed to EGIA. \nInterconnection Customer requesting to be included in ERAS shall inform \nTransmission Provider of its election to proceed within five (5) Calendar Days \nafter receiving the draft results of the Expedited Resource Additions Study. \nInterconnection Customer that fails to provide an election to proceed within five \n(5) Calendar Days will result in withdrawal of the Interconnection Request \npursuant to Section 3.6 of this GIP.  EGIA execution shall occur no later than 30 \nCalendar days after receiving Interconnection Customer’s election to proceed. \n \n3.9.5 GIA for Expedited Resource Addition Study Projects (EGIA). \nTransmission Provider shall tender a draft pro forma EGIA, that conforms to the \npro forma GIA in effect at the time, as modified for ERAS, within five (5) \nBusiness Days after the Customer provides notice to proceed to EGIA \nnegotiations.  In the event that SPP’s JTIQ Service Agreement has not been \nprovided to Interconnection Customer prior to tender of a draft EGIA, the draft \nEGIA shall include a milestone in Appendix B obligating Interconnection \nCustomer to execute or request the unexecuted filing of SPP’s JTIQ Service \nAgreement not later than 15 Calendar Days after such agreement has been \ntendered to the Interconnection Customer.  Upon tender of the EGIA, the ERAS \nInterconnection Request shall be subject to the timing and procedures set forth in \nSections 11.1 through 11. 4 of these GIP. \n \nTransmission Provider shall include in the final EGIA any Affected System Study"},{"page":190,"startToken":52837,"endToken":53101,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nresults and information regarding Network Upgrades from Affected Systems \nprovided the Affected System Study Reports are available.  If Affected System \nanalysis is not available for inclusion in the final EGIA, the Transmission \nProvider shall provide such analysis separately when received from the \napplicable Affected System.  An Interconnection Request included in a JTIQ \nParticipation Group shall adhere to all JTIQ procedures, and execute JTIQ \nService Agreements as applicable. \n \n3.9.6 Expedited Resource Addition Study Refunds. \n3.9.6.1 Refunds of Expedited Resource Addition Study Deposits D2. \nTransmission Provider shall charge and Interconnection Customer shall \npay the actual costs of the Expedited Resource Addition Study. Any \ndifference between the study deposit and the actual cost of the applicable \nInterconnection Study shall be paid by or refunded to the Interconnection \nCustomer as applicable. \n \n3.9.6.2 Refunds of Expedited Resource Addition Study Entrance Milestone \n(M2). \nInterconnection Customers are eligible to receive one hundred percent \n(100%) refund of the Expedited Resource Addition Study entry milestone \n(M2) upon withdrawal prior to execution of the EGIA. Interconnection \nCustomers that terminate the EGIA after execution are eligible to receive a \nrefund of the remaining M2 milestone payment. \n \n3.9.6.3 Applicability of Expedited Resource Addition Milestone Payment \n(M2) to Expedited Generator Interconnection Agreement Initial \nPayment. \nIn the event the Interconnection Customer has elected to make its \nmilestones in the form of cash, Transmission Provider will transfer the \nExpedited Resource Addition Study milestone to the appropriate"},{"page":191,"startToken":53101,"endToken":53392,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nTransmission Owner to satisfy the initial payment requirement of the \nExpedited Generator Interconnection Agreement, TCA or other applicable \nservice agreement within forty-five (45) Calendar Days of the effective \ndate of the Expedited Generator Interconnection Agreement, TCA or other \napplicable service agreement.  The Transmission Provider shall refund \nmilestone cash payments exceeding the initial payment requirement to the \nInterconnection Customer upon Interconnection Customer’s request with \nTransmission Owner’s consent, within forty-five (45) Calendar Days of \nthe effective date of the Generator Interconnection Agreement.  In the \nevent the milestone payments are less than the initial payment \nrequirement, the Interconnection Customer shall be responsible for the \nremaining payment to the Transmission Owner.   \n \nIn the event that the Interconnection Customer withdraws and terminates \nits EGIA after execution of the EGIA by all parties or after EGIA is filed \nunexecuted the Interconnection Customer will be liable for the Network \nUpgrades documented in the EGIA and corresponding FCAs or MPFCAs, \nincluding those Network Upgrades arising from the Affected System \nStudy process.  \n \n3.9.7 Transfer of Ownership of Expedited Resource Addition Study request. \nAn Interconnection Customer participating in the Expedited Resource Addition \nStudy may transfer its Interconnection Request to another entity only after \nexecution of the EGIA or filing the EGIA unexecuted. The new entity must \nmaintain the eligibility requirements per Sections 3.3.1 and 3.9.1. \n \n3.9.8 Modifications of Expedited Resource Addition Study request. \nAfter entering the Expedited Resource Addition Study as defined in Section 3.9.3, \nno changes to the In-Service Date or Commercial Operation Date of the \nGenerating Facility is permitted via section 4.4.4. An ERAS Interconnection"},{"page":192,"startToken":53392,"endToken":53725,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nRequest that is deferred to the next available ERAS Quarterly Study Period will \nbe allowed to extend its In-Service Date or Commercial Operation Date to be no \nmore than three calendar years from the kickoff of the ERAS Quarterly Study \nPeriod in which its application is studied.  At the completion of the Expedited \nResource Addition Study, the Commercial Operation Date and In-Service Date \nshall be set forth in the EGIA.   \n \n3.9.9 Sunset of Expedited Resource Addition Study process. \nFollowing the effective date of the Tariff revisions accepted in Commission \nDocket No. ER25-____, the Transmission Provider will terminate the ERAS \nprocess at the earlier of the completion of sixty-eight ERAS Interconnection \nRequest studies or August 31, 2027. In the event the Transmission Provider \ndetermines the sunset date should be extended, the Transmission Provider shall \nsubmit an additional filing to the Commission pursuant to Section 205 of the \nFederal Power Act seeking such later sunset date. Upon termination of ERAS, the \nTransmission Provider will no longer accept new ERAS Interconnection \nRequests.  Any ERAS Interconnection Requests accepted but cannot be studied \ndue to the sunset of the ERAS process will automatically move to the standard \nDefinitive Planning Phase queue unless the customer chooses to withdraw.  If \ndeemed ineligible for the ERAS process, the project will forfeit its Non-\nRefundable Deposit D1. \n \n3.10  Penalties for Failure to Meet Study Deadlines. \n(1) Transmission Provider or Transmission Owner(s), as applicable, shall be subject to a \npenalty if it fails to complete a Group Study, Interconnection Facilities Study, Affected \nSystem Study, or Affected System Network Upgrade facilities study or a restudy of any \nof the foregoing by the applicable deadline as set forth in the GIP, applicable Joint \nOperating Agreement, Joint Planning Agreement, or any other agreements filed with the \nCommission.   \n(2) For purposes of determining compliance with this Section and the calculation of"},{"page":193,"startToken":53725,"endToken":54140,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\npenalties, the applicable study period is the time to complete the studies identified in \nSection 3.9(1), not including model review, Interconnection Customer review of draft \nstudy reports, and Decision Point as provided in Sections 7.1 through 7.3 of this GIP.  \nExcluding the Interconnection Facilities Study, the study period for all applicable studies \nshall begin the day after the applicable study’s model review period ends, as set forth in \nSection 7 of this GIP.  The study period shall conclude when the draft study report for the \napplicable study is posted or otherwise transmitted to Interconnection Customers.  For \nInterconnection Facilities Study, the applicable study period shall be ninety (90) Calendar \nDays, starting when Transmission Provider submits to the applicable Transmission \nOwner(s) a statement of work and purchase order and ending when the draft study report \nis transmitted to Interconnection Customers pursuant to Sections 7.3.2.5 and 7.3.3.4.   \n(3) Transmission Provider or applicable Transmission Owner(s) shall pay the penalty for \neach late Group Study, Group Restudy, or Interconnection Facilities Study on a pro rata \nbasis per Interconnection Request to all Interconnection Customer(s) included in the \nrelevant study that did not withdraw, or were not deemed withdrawn, from Transmission \nProvider’s interconnection queue before the conclusion of the applicable study in \nproportion to each Interconnection Customer’s final study costs.   \n(4) Transmission Provider or applicable Transmission Owner(s) shall pay the penalty for \na late Affected System Study or Affected System Network Upgrade facilities study on a \npro rata basis per interconnection request to all Affected System Interconnection \nCustomer(s) included in the relevant Affected System Study, or Affected System \nNetwork Upgrade facilities study that did not withdraw, or were not deemed withdrawn, \nfrom the host transmission provider’s interconnection queue before the missed study \ndeadline in proportion to each Interconnection Customer’s final study costs.   \n(5) For delayed studies performed by a Transmission Owner, or its subcontractor or \ndelegee, the Transmission Provider shall invoice the applicable Transmission Owner(s) \nwho performed the delayed study for the amount of the penalty calculated in accordance \nwith Section 3.9(6) and (7). within fifteen (15) Business Days after the date that the final \nstudy report for the delayed study is posted to OASIS or MISO’s public website.   \nThe invoiced Transmission Owner(s) shall remit the invoiced amount to the Transmission"},{"page":194,"startToken":54140,"endToken":54581,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nProvider not later than forty-five (45) Calendar Days after the date of such invoice. \nPayment of such funds to the Transmission Provider shall not constitute an admission of \nliability for the delay or prejudice the ability of the applicable Transmission Owner(s) or \nTransmission Provider to seek relief from such penalties from the Commission or recover \npenalty amounts from others as provided in Section 3.9(8) of these GIP.  The \nTransmission Provider shall hold all penalty amounts collected pursuant to this \nsubsection during the pendency of any appeal to the Commission or reassignment \nproceeding for such penalties authorized by Section 3.9(8) of these GIP or until the \ndeadline for initiating such a proceeding has expired in the event such a proceeding has \nnot been initiated.  Thereafter, the Transmission Provider shall distribute to the applicable \nInterconnection Customer(s) or refund to the paying Transmission Owner(s) all collected \nfunds as required by this Section 3.9 or otherwise ordered by the Commission.  \n(6) Any study delay penalty shall be distributed by forty-five (45) Calendar Days  after \nthe later of: (a) the date that the final Interconnection Facilities Studies report has been \nposted at the end of Phase III for the applicable study group that experienced a study \ndelay, (b) the conclusion of a proceeding regarding such study delay as provided in \nSection 3.9(9) of these GIP, or (c) the date MISO receives the full penalty payment(s) \nfrom the party(ies) responsible for the delay. \n(7) For penalties assessed in accordance with this Section, the penalty amount will be \nequal to: $1,000 per Business Day for delays of Group Studies beyond the applicable \ndeadline set forth in this GIP; $2,000 per Business Day for delays of Group Re-Studies \nbeyond the applicable deadline set forth in this GIP; $2,000 per Business Day for delays \nlate Affected System Study or Affected System Network Upgrade facilities study beyond \nthe applicable deadline as set forth in the GIP, applicable Joint Operating Agreement, \nJoint Planning Agreement, or other agreement filed with the Commission as provided in \nSection 8 of this GIP; and $2,500 per Business Day for delays of the Interconnection \nFacilities Studies beyond the applicable deadline set forth in this GIP.   \n(8) The total amount of a penalty assessed under this Section shall not exceed: (a) one \nhundred percent (100%) of Study Deposit 2 (D2)  received for all of the Interconnection \nRequests in the Cluster for Group Studies and Group Restudies; (b) one hundred percent"},{"page":195,"startToken":54581,"endToken":54995,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n(100%) of the Study Deposit 2 (D2) received for the single Interconnection Request in \nthe study for Facilities Studies; and (c) one hundred percent (100%) of the study cost(s) \nthat Transmission Provider collects for conducting the Affected System Study. \n(9) Transmission Provider or Transmission Owner(s), as applicable, may appeal to the \nCommission any penalties imposed under this Section.  Any such appeal must be filed no \nlater than forty-five (45) Calendar Days after the posting of the final DPP Phase III Final \nSystem Impact Study results to OASIS or MISO’s public website for the study group that \nexperienced a delayed study.  While an appeal to the Commission is pending, \nTransmission Provider or applicable Transmission Owner(s) shall remain liable for the \npenalty, but need not distribute the penalty until forty-five (45) Calendar Days after (1) \nthe deadline for filing a rehearing request has ended, if no requests for rehearing of the \nappeal have been filed, or (2) the Commission’s final determination.  The Commission \nmay excuse Transmission Provider or applicable Transmission Owner(s) from penalties \nunder this Section for good cause.  Transmission Provider or Transmission Owner(s) \nassessed a penalty under this Section may submit a filing to the Commission under \nSection 205 of the Federal Power Act to recover costs of any study delay penalty \nimposed from a party or parties that contributed to the delay.    \n(10) No penalty will be assessed under this Section where a study is delayed by ten (10) \nBusiness Days or less.  If the study is delayed by more than ten (10) Business Days, the \npenalty amount will be calculated from the first Business Day the Transmission Provider \nor applicable Transmission Owner(s) missed the applicable study deadline. \n(11) The deadline for a relevant study may be extended thirty (30) Business Days from \nthe original, applicable study deadline if: (a) Transmission Provider or Transmission \nOwner(s), as applicable, needs to extend the deadline for a particular study subject to \npenalties under this Section and (b) all Interconnection Customers or Affected System \nInterconnection Customers included in the relevant study mutually agree to such an \nextension.  No penalty shall be assessed to Transmission Provider or applicable \nTransmission Owner(s) missing the original study deadline if the study deadline is \nextended pursuant to this subsection. \n(12) No penalties shall be assessed until the third Group Study cycle after the"},{"page":196,"startToken":54995,"endToken":55343,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nCommission-approved effective date of Transmission Provider’s filing made in \ncompliance with the Final Rule in Docket No. RM22-14-000. \n(13) Transmission Provider must maintain on its OASIS or its public website summary \nstatistics related to penalties assessed under this Section, updated quarterly.  For each \ncalendar quarter, Transmission Provider must calculate and post (1) the total amount of \npenalties assessed under this Section during the previous reporting quarter and (2) the \nhighest penalty assessed under this Section paid to a single Interconnection Customer or \nAffected System Interconnection Customer during the previous reporting quarter.  \nTransmission Provider must post on its OASIS or its website these penalty amounts for \neach calendar quarter within thirty (30) Calendar Days of the end of the calendar quarter.  \nTransmission Provider must maintain the quarterly measures posted on its OASIS or its \nwebsite for three (3) calendar years with the first required posting to be the third Group \nStudy cycle with an application deadline after July 28, 2025. \n \n3.11  Additional Requirements for Interconnection Requests Seeking ZG Interconnection \nService \nA request for ZG Interconnection Service made by an Interconnection Customer must \nmeet the requirements listed in section 3.3.1 above, plus the following requirements: \n \ni. \nAn Interconnection Request for seeking ZG Interconnection Service shall include a \none line diagram showing the Generating Facility and associated electrical equipment \nwith appropriate rating and impedance information and all the ZG Associated Load \nincluding all Point(s) of Withdrawal and the Point of Interconnection of the \nGenerating Facility to the Transmission System for the Interconnection Request. \nii. \nAn Interconnection Request seeking ZG Interconnection Service shall include a \ndetailed power flow model for the proposed Generating Facility that includes all ZG \nAssociated Load, Point(s) of Withdrawal and the Point of Interconnections for the \nInterconnection Request, as well as any proposed system protection facilities.  \nAny proposed Generating Facility requesting ZG Interconnection Service must have a \nPoint of Interconnection that is located at the same voltage level of the same"},{"page":197,"startToken":55343,"endToken":55721,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ninterconnection substation as the Point(s) of Withdrawal for the ZG Associated Load \nit will serve.   \niii. \nThe proposed Generating Facility requesting ZG Interconnection Service must not \nrequire the construction of Network Upgrades beyond the substation where the Point \nof Interconnection is located other than System Protection Facilities.   \niv. \nThe Interconnection Request for ZG Interconnection Service must be submitted to the \nTransmission Provider by the Interconnection Customer at least 180 days prior to the \nearlier of: (a) the Commercial Operation Date for the Generating Facility seeking ZG \nInterconnection Service or (b) for a ZG Associated Load not already in service as of \nthe date the Interconnection Service is submitted, the need-by date for such ZG \nAssociated Load.  The Interconnection Request for ZG Interconnection Service shall \ninclude the expected Commercial Operation Date for the Generating Facility and the \nneed-by date for the ZG Associated Load.  \nv. \nThe amount of ZG Interconnection Service is limited to and shall not exceed the total \nDemand of the ZG Associated Load for that Generating Facility. \nvi. \nThe Interconnection Request for ZG Interconnection Service must include the \nmodeling and other technical data described in the Generator Interconnection \nBusiness Practices Manual for the ZG Associated Load to enable the Transmission \nProvider to model such Load in ZG Interconnection Service studies. \nvii. \nThe Interconnection Request for ZG Interconnection Service shall be accompanied by \nan executed agreement evidencing that the full output of the Generating Facility for \nwhich ZG Interconnection Service is sought is intended to be used by the entity(s) \nwith the ZG Associated Load.  Such agreement shall take one of the following forms \nand state an expected term of at least five years to align with MISO’s transmission \nplanning horizon as described in Section I.D.1.b of Attachment FF to the Tariff: \na. A Load Serving Entity acknowledgement to self-supply its ZG Associated Load; \nb. A Power Purchase Agreement (PPA) or similar off-take agreement between the \nInterconnection Customer submitting the Interconnection Request for ZG \nInterconnection Service and the entity with the ZG Associated Load to be served \n(including, but not limited to, an Alternative Retail Electric Supplier or its Load"},{"page":198,"startToken":55721,"endToken":56034,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nServing Entity); \nc. An agreement that calls for the Interconnection Customer to develop the \nGenerating Facility described in the Interconnection Request and subsequently \ntransfer ownership or control of such Generating Facility (Build-Own-Transfer \nAgreement) to the entity with the ZG Associated Load to be served (including, \nbut not limited to, an Alternative Retail Electric Supplier or its Load Serving \nEntity);  \nd. Other agreement between the entity submitting the Interconnection Request, and \nthe entity with the ZG Associated Load to be served (including, but not limited to, \nan Alternative Retail Electric Supplier or its Load Serving Entity), stating that the \nGenerating Facility will be used to provide its full output to the ZG Associated \nLoad; or  \ne. An acknowledgement by the Interconnection Customer that it is the entity that \nowns the ZG Associated Load that such entity is both permitted by applicable law \nand intends to self-supply its ZG Associated Load through using onsite \ngeneration.  \nix. An Interconnection Request for ZG Interconnection Service shall not include a \nrequest for any other type of Interconnection Service (e.g., ERIS or NRIS).  This \nparagraph shall not be construed to prevent an Interconnection Customer from \nsubmitting a separate Interconnection Request for another type of Interconnection \nService for the same Generating Facility using the process specified by these \nGenerator Interconnection Procedures for such request type.  In the event that an \nInterconnection Customer obtains another form of Interconnection Service for the \nsame Generating Facility, such service shall be deemed to supersede any previously-\ngranted ZG Interconnection Service upon its effective date. \n \n3.11.1 Requirements for modification of Interconnection Service Requests seeking \nZG Interconnection Service \nNo changes shall be made to an Interconnection Request seeking ZG \nInterconnection Service after submission except that in the event that the ZG"},{"page":199,"startToken":56034,"endToken":56391,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nAssociated Load designates or changes its proposed Point(s) of Withdrawal \nsubsequent to the Interconnection Customer submitting its Interconnection \nRequest for ZG Interconnection Service such that the ZG Associated Load would \nnot have a Point of Withdrawal at the same substation and voltage level as the \nPoint of Interconnection, the Interconnection Customer shall be required to move \nits proposed Point of Interconnection to match the substation and voltage level of \nthe Point(s) of Withdrawal as described in Section 4.4 of these GIP.  In the event \nthat the POW changes after the Interconnection Customer receives an effective \nZGIA, the parties shall amend such ZGIA to align the POI with the new location \nof the POW and change the Commercial Operation Date to a date no earlier than \n180 days after the date the Transmission Provider was notified of such POW \nchange.  No delivery of Energy to the ZG Associated Load shall be allowed to \noccur prior to such revised date without the prior written consent of the \nTransmission Provider.  An Interconnection Customer seeking to make changes \nother than those authorized by this Section 3.11.1 may withdraw its ZG \nInterconnection Request and resubmit as a new application with new deposits. \n \n3.11.2 Evaluation Process for ZG Interconnection Service Interconnection Requests \nThe Transmission Provider will evaluate Interconnection Service requests seeking \nZG Interconnection Service in the order in which they are submitted.  The \nevaluation will consist of a ZG Impact Assessment as set forth in Section \n3.2.5.2.1 and a ZG Facilities Study as set forth in Section 3.2.5.2.2. \n \nThe Transmission Provider will limit the maximum size of each ZG Quarterly \nStudy Period to no more than 10 Interconnection Requests.  If more than 10 \nInterconnection Requests are submitted for one ZG Quarterly Study Period, those \nsurpassing the limit will be studied in a subsequent ZG Quarterly Study Period in \nthe order in which they were submitted. \n \nThe Transmission Provider shall use Reasonable Efforts to complete the ZG"},{"page":200,"startToken":56391,"endToken":56706,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nImpact Analysis and for all Interconnection Requests included in a ZG Quarterly \nStudy Period and share results with the applicable Interconnection Customer \nwithin ninety (90) Calendar Days of the date that the Transmission Provider \ncommences the applicable ZG Quarterly Study Period.  Transmission Provider \nshall use Reasonable Efforts to complete each portion of the ZG Facilities Study \nwithin ninety (90) Calendar Days of the date such portion commences. \n \nTransmission Provider shall include in the final study report for the ZG Impact \nAnalysis any Affected System Study results and information regarding Network \nUpgrades from Affected Systems provided the Affected System Study Reports are \navailable.  If Affected Systems analysis is not available for inclusion in the final \nstudy, the Transmission Provider shall provide such analysis separately when \nreceived from the applicable Affected System.  \n \nAn Interconnection Request included in an active Definitive Planning Phase that \nhas not reached Decision Point II may withdraw from the Definitive Planning \nPhase and move their Interconnection Request to the ZG interconnection Service \nprocess if they meet the requirements for ZG Interconnection Service.  The \nproject will be subject to penalties per Sections 7.6.2.1.1. and 7.8 and must meet \nthe requirements for an Interconnection Request for ZG Interconnection Service \nset forth in Section 3.11.  Verification of Site Control will be specified in the \nGenerator Interconnection Business Practice Manual to authenticate applicability.  \nAn Interconnection Request that has been withdrawn from the Definitive Planning \nPhase after completion of Decision Point II may be moved to the ZG \nInterconnection Service study process after a period of one year from the \nwithdrawal date. \n \n3.11.3  ZG Interconnection Service - Notice to Proceed \nInterconnection Customer requesting ZG Interconnection Service shall inform \nTransmission Provider within five (5) Business Days after having received results"},{"page":201,"startToken":56706,"endToken":57024,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nof the ZG Impact Analysis of its election to proceed and Transmission Provider \nwill complete the ZG Facilities Study and then tender a draft ZG Interconnection \nAgreement.  If the Interconnection Customer fails to provide a notice of its \nelection to proceed within five (5) Business Days after having received the results \nof the Transmission Provider’s evaluation, the Transmission Provider will deem \nthe Interconnection Request withdrawn pursuant to Section 3.6 of this GIP. \n \n3.11.4 ZGIA for ZG Generating Facility  \nTransmission Provider shall tender a draft pro forma ZGIA or ZGIAs or, if \ndeemed appropriate, an amended ZGIA or ZGIAs that conforms to the pro forma \nZGIA in effect at the time, within five (5) Business Days after the Interconnection \nCustomer communicates its election to proceed with ZG Interconnection Service, \nand complete any unfinished portion of the Facilities Study and tender the results \nto Interconnection Customer within the timeframe specified in Section 3.11.2 of \nthese GIP. \n \n \nSECTION 4. QUEUE POSITION. \n \n4.1 \nGeneral. \nTransmission Provider shall assign a Queue Position as follows: the Queue Position \nwithin the queue shall be assigned based upon the date and time of receipt of all items \nrequired pursuant to the provisions of Section 3.3 of this GIP.  All Interconnection \nRequests submitted and validated in a single Group Study shall be considered equally \nqueued.  Transmission Provider shall assign a Queue Position based upon the initial date \nand time of receipt of the valid Interconnection Request; provided that, if the sole reason \nan Interconnection Request is not valid is the lack of required information or materials \nincluded with the application form, and Interconnection Customer or MHVDC \nConnection Customer provides such information in accordance with Section 3.3.1, then \nTransmission Provider shall assign Interconnection Customer or MHVDC Connection"},{"page":202,"startToken":57024,"endToken":57387,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nCustomer a Queue Position based on the initial date and time of receipt of the \nInterconnection Request.  Moving a Point of Interconnection or Point of Connection shall \nresult in a reassignment of the Queue Position except as otherwise noted in Section 4.4.   \n \nThe Definitive Planning Phase Queue Position will be established based upon the date \nand time Interconnection Customer or MHVDC Connection Customer initially submits \nits Interconnection Request provided that Interconnection Customer subsequently \nsatisfies all of the requirements of Section 7.2 to enter the Definitive Planning Phase and \nthe Interconnection Request is accepted as valid by the Transmission Provider.  The \nDefinitive Planning Phase Queue Position will also be used for the determination of cost \nresponsibility for the facilities necessary to accommodate the Interconnection Request, \nexcept for Group Studies.  The determination of cost responsibility for common facilities \nnecessary to accommodate two or more Interconnection Requests participating in a \nGroup Study may depend on factors other than the Definitive Planning Phase Queue \nPosition.  A higher queued Interconnection Request is one that has been placed “earlier” \nin the queue in relation to another Interconnection Request that is lower queued.  All \nInterconnection Requests within the same Definitive Planning Phase cycle shall have \nequal priority (i.e. similarly queued). \n \nTransmission Provider may perform an Interconnection Study out of queue order at any \ntime to the extent warranted by Good Utility Practice based upon:  1) the electrical \nremoteness of the Generating Facility or MHVDC Transmission Line or 2) the request of \nInterconnection Customer or MHVDC Connection Customer, if Transmission Provider \nconcurs with the request and has the resources to do the study provided Interconnection \nCustomer or MHVDC Connection Customer accepts the financial risk that study \nresources may be reassigned, that its Interconnection Request is subject to review and \nrestudy in queue order, and that its GIA or TCA may be amended to reflect a \nreassignment of upgrades as Interconnection Studies of higher queued Interconnection \nRequests are completed.  Interconnection Customer or MHVDC Connection Customer \nmay request the Transmission Provider’s concurrence 1) in connection with a resource"},{"page":203,"startToken":57387,"endToken":57698,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nsolicitation process, 2) when Interconnection Customer or MHVDC Connection \nCustomer proposes to replace equipment due to catastrophic failure and such replacement \nis determined to be Qualified Change, and 3) for other reasons specific to Interconnection \nCustomer or MHVDC Connection Customer. \n \n4.1.1  Limitation on queue study cycle size \n4.1.1.1 The Transmission Provider will determine the maximum size of each \nDefinitive Planning Phase study cycle (in MW) on a study region basis.  \nThe limit will be based on fifty-percent (50%) of the subregional non-\ncoincident peak load in the summer peak study model.  Projects with \napproved exemptions as noted in Sections 4.1.2.1 through 4.1.2.3 shall \nhave priority in each Definitive Planning Phase study cycle limit.  \n \nThe Transmission Provider shall post the MW value determined for a \nstudy group in accordance with this Section on the Transmission \nProvider’s website at least ten (10) Business Days prior to the application \ndeadline of that Definitive Planning study cycle. \n \n4.1.1.2 The Interconnection Request shall be included in the Definitive Planning \nPhase study cycle based on the earliest date and time of submission of \nInterconnection Requests until the maximum MW cap for the applicable \nstudy region is met.  Five (5) Business Days after the applicable maximum \nMW limit has been met, the Transmission Provider shall post the initial \nlist of Interconnection Requests included in the study group for the \nupcoming study cycle on Transmission Provider’s website.   \n \n4.1.1.3 No later than thirty (30) Calendar Days prior to the scheduled DPP Phase \n1 kickoff date for a Definitive Planning Phase study cycle, the \nTransmission Provider shall replace any Interconnection Requests that \nhave been withdrawn from such Definitive Planning Phase study cycle"},{"page":204,"startToken":57698,"endToken":58025,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nafter any applicable cure period with Interconnection Requests previously \nsubmitted but determined to exceed the maximum Definitive Planning \nPhase study cycle limit for that study region determined  pursuant to \nsection 4.1.1.1 of this GIP.  The Transmission Provider shall select \nInterconnection Requests to replace withdrawn Interconnection Requests \nin the same study region based on the earliest date and time stamp of such \nInterconnection Requests until the maximum MW cap is met.  The \nTransmission Provider shall notify such Interconnection Customers that \ntheir Interconnection Requests will be included in the study group no later \nthan thirty (30) Calendar Days prior to the scheduled DPP Phase 1 kickoff \ndate for a Definitive Planning Phase study cycle. \n \n4.1.1.4 Projects that have submitted a complete application and required deposits \nand milestone payments that were not included in a given DPP study cycle \nwill maintain their position, as long as the application remains valid, to \nenter the next available study cycle. \n \n4.1.1.5 Upon conclusion of the third DPP study cycle following the effective date \nof the Tariff revisions accepted in Commission Docket No. ER25-____, \nthe Transmission Provider will conduct a review of the effectiveness of \nthe limitation on queue study cycle size with stakeholders and determine \nwhether to terminate or modify the queue size limitation.  In the event the \nTransmission Provider determines not to file modifications or a \ntermination of the queue size limitation, the Transmission Provider shall \nsubmit an informational report to the Commission describing the results of \nthis review upon completion of the stakeholder process.  \n \n4.1.2  A valid Interconnection Request submitted for a DPP study cycle to which the \nprovisions of Section 4.1.1 of this GIP apply, shall be included in such study \ncycle up to, but not to exceed, the limit, if the Transmission Provider receives"},{"page":205,"startToken":58025,"endToken":58293,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ndocumentation included with Interconnection Request demonstrating that one of \nthe following exemptions applies to such Interconnection Request:  \n \n4.1.2.1 The Interconnection Request seeks to convert ERIS service previously \ngranted to an Existing Generating Facility to NRIS for the same Existing \nGenerating Facility without requesting any additional increase in the \nservice levels. \n \n4.1.2.2 The Interconnection Request seeks to add incremental new service to a \nReplacement Generating Facility that has an effective GIA.  \n \n4.1.2.3 The Interconnection Request is for a Generating Facility that has \ncompleted the requirements of this GIP, including the requirements of \nSection 7.9.1, to request a Provisional Generator Interconnection \nAgreement (PGIA).  In the event that an Interconnection Customer or \nMHVDC Connection Customer withdraws its requested PGIA after the \nthirty (30) Calendar Day timeline as noted in Section 4.1.1.3, then the \nInterconnection Request associated with that requested PGIA shall be \nwithdrawn.  The Interconnection Request shall also forfeit milestones in \naccordance with Section 7.9.3. \n \nTransmission Provider may include the types of documentation required to \ndemonstrate that one of the foregoing exemptions applies in the Generator \nInterconnection Business Practices Manual.  \n \n4.2 \nGroup Study Organization of Interconnection Studies. \nInterconnection System Impact Studies shall, and Interconnection Facilities Studies may, \nbe performed in a Group Study format, whenever applicable, in the Definitive Planning \nPhase, except when a particular Interconnection Request is sufficiently electrically \nremote from others that it cannot reasonably be grouped with other Interconnection"},{"page":206,"startToken":58293,"endToken":58624,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nRequests or where the Interconnection Request is not for a new Generating Facility or \nadditional Interconnection Service.  Interconnection Requests for both ER \nInterconnection Service and NR Interconnection Service may be part of a Group Study at \nthe option of Transmission Provider.  An Interconnection Request’s inclusion in a Group \nStudy will not relieve Transmission Provider from meeting the timelines provided in the \nGIP. \n \nGrouping shall be implemented on the basis of electrical proximity.  Transmission \nProvider may elect to perform Group Studies:  (i) in connection with a resource \nsolicitation process with the concurrence of Transmission Provider; (ii) when a \ncoordinated study with an Affected System Operator will be performed that involve \nInterconnection Requests in the generator interconnection queue of Transmission \nProvider and of the Affected System Operator; (iii) to identify Common Use Upgrades; \nor (iv) at the request of a group of affected Interconnection Customers or MHVDC \nConnection Customers.  In all instances in which Transmission Provider elects to use \nsubgroups in the Group Study process, Transmission Provider must publish the criteria \nused to define and determine subgroups on its OASIS or public website. \n \nIf item (i) above applies and Transmission Owner concurs, the solicitor must (a) be \nauthorized by Interconnection Customers participating in the solicitation to act as the \nagent for all the Interconnection Requests submitted by Interconnection \nCustomers, (b) maintain valid Interconnection Requests, (c) submit all Interconnection \nRequests at the same time, (d) submit a reasonable number of study portfolios (i.e., a \nmixture of projects meeting the requirements of the solicitation that are studied in \nparallel), and (e) select one portfolio prior to the start of the Interconnection Facilities \nStudy.  \n \nInterconnection Requests included in a Group Study related to a resource solicitation \nprocess are subject to study according to their Definitive Planning Phase Queue Position \nin the process.  Interconnection Requests for projects that are not included in a Group"},{"page":207,"startToken":58624,"endToken":58972,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nStudy related to a resource solicitation process are subject to study according to their \nDefinitive Planning Phase Queue Position outside the process in accordance with the \nprovision of the GIP, and such studies may not be delayed as a result of the resource \nsolicitation process.  An Interconnection Customer may request that its Interconnection \nRequest be included in a Group Study related to a resource solicitation process without \nhaving to abandon the existing Definitive Planning Phase Queue Position for such \nInterconnection Request.  Once the solicitor rejects a project in the resource solicitation \nprocess, the Interconnection Request associated with the rejected project loses the \nDefinitive Planning Phase Queue Position it held as part of the resource solicitation \nprocess.  An Interconnection Customer that participates in a Group Study related to a \nresource solicitation process may at any time for the same project submit a separate \nInterconnection Request that is not included in the Group Study, provided, however, that \nInterconnection Customer shall be responsible for all Interconnection Study costs \nassociated with its non-solicitation-related Interconnection Request in addition to any \ncosts associated with Interconnection Customer’s bid into the resource solicitation.  \nWhen the solicitor selects a project in the resource solicitation process, Interconnection \nCustomer may no longer maintain more than one Definitive Planning Phase Queue \nPosition for the selected project.  Interconnection System Impact Studies performed as \nGroup Studies shall be conducted in such a manner to ensure the efficient implementation \nof the applicable regional transmission expansion plan in light of the Transmission \nSystem’s capabilities at the time of each study. \n \n \n4.2.1  \nCost Allocation for Interconnection Facilities and Network Upgrades. \n(1) For Network Upgrades identified in Group Studies, Transmission Provider \nshall calculate each Interconnection Customer’s share of the costs as follows: \n(a) Substation Network Upgrades, including all switching stations, shall be \nallocated first per capita to Interconnection Facilities interconnecting to \nthe substation at the same voltage level, and then per capita to each \nGenerating Facility sharing the Interconnection Facility interconnecting at"},{"page":208,"startToken":58972,"endToken":59301,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nthe same substation. \n(b) Network Upgrades other than Substation Network Upgrades, as \ndescribed in section 4.2.1.(1).(a) shall be allocated based on the \nproportional impact of each individual Generating Facility in the Group \nStudy on the need for a specific Network Upgrade. This proportional \nallocation methodology will apply, but is not limited to, the following \ncategories: (i) thermal - Will be cost allocated per the pro rata share of \nMW impact of DPP projects on the constraints being alleviated by the \nupgrade, as further described in the Generator Interconnection Business \nPractices Manual, BPM 015; or (2) non-thermal - Will be cost allocated \nper the pro rata share of MW impact of DPP projects on the constraints \nbeing alleviated by the upgrade, as further described in the Generator \nInterconnection Business Practices Manual, BPM 015. \n(c) An Interconnection Customer that funds Network Upgrades shall be \nentitled to transmission credits to the extent provided in Article 11.4 of the \nGIA. \n(2) The costs of any needed Interconnection Facilities identified in the Group \nStudy will be directly assigned to the Interconnection Customer(s) using such \nfacilities.  Where Interconnection Customers in the Group agree to share \nInterconnection Facilities, the cost of such Interconnection Facilities shall be \nallocated based on the number of Generating Facilities sharing use of such \nInterconnection Facilities on an equal basis (i.e., on a per Generating Facility \nbasis), unless Parties mutually agree to a different cost sharing arrangement. \n(3) The shared costs of Group Studies shall be allocated among the \nInterconnection Customers in the applicable Study Group: 50% of the costs shall \nbe allocated to all Interconnection Customers in the Study Group on a per capita \nbasis, and 50% of the costs shall be allocated to all Interconnection Customers in \nthe Study Group on a pro rata basis by MW. \n \n4.3 \nTransferability of Queue Position."},{"page":209,"startToken":59301,"endToken":59630,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nAn Interconnection Customer or MHVDC Connection Customer may transfer either of \nits queue positions to another entity only if such entity acquires the specific Generating \nFacility or MHVDC Transmission Line identified in the Interconnection Request and the \nPoint of Interconnection or Point of Connection does not change. \n \n4.4 \nModifications. \nInterconnection Customer or MHVDC Connection Customer shall submit to \nTransmission Provider modifications to any information provided in the Interconnection \nRequest in the manner specified by the Generator Interconnection Business Practices \nManual (BPM-015).  Interconnection Customer or MHVDC Connection Customer shall \nretain its Queue Position if the modifications proposed by Interconnection Customer or \nMHVDC Connection Customer are in accordance with Sections 4.4.1 or 4.4.4.  \nNotwithstanding any modifications to information provided in the Interconnection \nRequest, the applicable timing requirements of Section 7.2 to return study agreements \nand obligation to provide study deposits will not change. \n \nNotwithstanding the above, during the course and prior to the completion of the \nInterconnection Studies, Interconnection Customer or MHVDC Connection Customer, \nTransmission Owner or Transmission Provider may identify changes to the planned \ninterconnection that may improve the costs and benefits (including reliability) of the \ninterconnection, and the ability of the proposed change to accommodate the \nInterconnection Request.  If the Interconnection Customer is requesting to share \nInterconnection Customer Interconnection Facilities as part of the proposed change, the \nInterconnection Customer shall submit a consent agreement that meets the requirements \nof Section 3.3.1.4 along with the identification of changes to the planned interconnection.  \nTo the extent the identified changes are acceptable to Transmission Provider, \nTransmission Owner and Interconnection Customer or MHVDC Connection Customer, \nsuch acceptance not to be unreasonably withheld; Transmission Provider shall modify the \nPoint of Interconnection or Point of Connection and/or configuration in accordance with \nsuch changes and proceed with any required Interconnection Studies.  Changes to the"},{"page":210,"startToken":59630,"endToken":60035,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nPoint of Interconnection or Point of Connection requested by Interconnection Customer \nor MHVDC Connection Customer after the kick off of Definitive Planning Phase I, \nexcept as described in this paragraph, will result in the Interconnection Request having to \nbe revalidated according to the procedures in Section 3.3.1, and a new Definitive \nPlanning Phase Queue Position assigned based on the date and time of submission of \nsuch modification in accordance with the procedures in Section 4.1.   \nFor Interconnection Requests seeking ZG Interconnection Service, in the event that the \nZG Associated Load specifies a location for its Point(s) of Withdrawal that is different \nfrom the Point(s) of Withdrawal identified in the Interconnection Request such that the \nLoad would no longer have a Point of Withdrawal located at the same voltage level at  \nthe same substation as the Point of Interconnection, Interconnection Customer shall \nnotify the Transmission Provider of such change prior to it taking effect and revise the \nPoint of Interconnection of the Generating Facility to be identical to one of the Points of \nWithdrawal.  The request shall describe the planned change and include all data and \nanalysis that Interconnection Customer wants the Transmission Provider to consider in \ndetermining whether the change results in material adverse impacts.  Such a requested \nchange will result in the Interconnection Request having to be revalidated according to \nthe procedures in Section 3.3.1 and restudied to determine whether such change has a \nmaterial adverse impact on the Transmission System, Affected Systems, or on the cost or \ntiming of any other Interconnection Request.  If such restudy indicates one or more \nmaterial adverse impacts, Interconnection Customer will be assigned a new Queue \nposition based on the date and time of submission of such modification in accordance \nwith the procedures in Section 4.1.  If such change occurs after the applicable ZGIA has \nbecome effective, the parties to such ZGIA shall be required to amend the ZGIA to \nreflect the results of such restudy and associated costs within sixty (60) Calendar Days \nafter the date that the Transmission Provider completes such restudy, or elect to terminate \nsuch ZGIA.  \n \n4.4.1 During the Definitive Planning Phase and prior to the issuance of draft GIA, the \nmodifications permitted shall include: (a) a change in the technical parameters"},{"page":211,"startToken":60035,"endToken":60361,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nassociated with the Generating Facility or MHVDC Connection Customer \ntechnology other than a Permissible Technological Advancement; (b) a change to \nthe Point of Interconnection or Point of Connection permitted under Section 4.4; \nand (c) a Permissible Technological Advancement for the Generating Facility or \nMHVDC Connection Customer.  For such permitted modification proposed by \nInterconnection Customer or MHVDC Connection Customer pursuant to 4.4.1(a) \nor 4.4.1(b), Interconnection Customer or MHVDC Connection Customer shall \nsubmit a detailed analysis demonstrating why they believe the change is not a \nMaterial Modification.  Transmission Provider must review such analysis and will \ndetermine, in its discretion, if the proposed modification is a Material \nModification.  In the absence of such analysis, the modification shall be deemed a \nMaterial Modification.  Section 4.4.1.1 specifies a separate technological change \nprocedure including the requisite information and process that will be followed to \nassess whether the Interconnection Customer’s proposed technological \nadvancement under Section 4.4.1(c) is a Material Modification.  Section 1 \ncontains a definition of Permissible Technological Advancement. \n \n4.4.1.1 Technological Change Procedure. \nFor permitted modification proposed by Interconnection Customer or MHVDC \nConnection Customer, Interconnection Customer or MHVDC Connection \nCustomer shall submit a technological advancement request demonstrating that the \nproposed change is a Permissible Technological Advancement or submitting a \ndetailed analysis to demonstrate that the proposed change is not a Material \nModification. Such request shall include a description of the proposed change \ntogether with updated modeling data (power flow and stability), updated technical \ndata as outlined in Attachment A of Appendix 1 of this GIP and a study deposit of \n$10,000.00. The detailed analysis to demonstrate that the proposed change is not a \nMaterial Modification shall include steady-state (thermal/voltage), reactive power, \nshort circuit/fault duty, and stability analyses unless the Transmission Provider"},{"page":212,"startToken":60361,"endToken":60652,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ndeems one or more of these not necessary based on the nature of the change \nrequested.  For a Generating Facility that includes at least one electric storage \nresource, and for which Transmission Provider approves operating assumptions \npursuant to Section 3.1, Transmission Provider shall perform the detailed analysis \nusing operating assumptions pursuant to Section 3.1.  The following criteria will \nbe used to determine whether the proposed change is a Material Modification: \na. \nAny change in expected output of the Generating Facility that \nis higher than what was studied in the interconnection process \nunless a control equipment is employed to limit the injection \nat the POI to the level of Interconnection Service originally \nrequested; \nb. \nAn increase in short circuit current that degrades transmission \nsystem reliability; \nc \nAngular stability performance and dynamic response that \ndegrades transmission system reliability; \nd. \nViolation of steady-state thermal or voltage limits caused by \nthe planned change utilizing the same criteria consistent with \nthe Interconnection System Impact Study. \nWithin 30 calendar days of receipt of a technological advancement request \ncontaining the information and security deposit required by Section 4.4.1.1, the \nTransmission Provider shall review such request and supporting documentation to \ndetermine if the proposed change is a Permissible Technological Advancement or \notherwise not a Material Modification and communicate the results together with \na written explanation to the Interconnection Customer of the Transmission \nProvider’s determination.  In the event that the Transmission Provider determines \nthat the proposed change is a Material Modification, the Interconnection \nCustomer or MHVDC Connection Customer shall have the option of: (i) \nwithdrawing such technological advancement request and retaining its current"},{"page":213,"startToken":60652,"endToken":60981,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nqueue position; or (ii) resubmitting its proposed Generating Facility as a new \nInterconnection Request.  \n \n4.4.2 After entering the Definitive Planning Phase as defined in Section 7.2, any \nmodifications to the type of Interconnection Service selected by Interconnection \nCustomer in the Interconnection Request, other than a change from NR \nInterconnection Service to ER Interconnection Service pursuant to Section 3.2 of \nthis GIP, shall be deemed a Material Modification. \n \n4.4.3 After entering the Definitive Planning Phase as defined in Section 7.2, any \nmodification to the size of the Interconnection Request, other than as allowed in \nSection 4.4.5, Section 7.3.1.4, or Section 7.3.2.4 of this GIP, shall be deemed a \nMaterial Modification. \n \n4.4.4 After entering the Definitive Planning Phase as defined in Section 7.2, any \nextension by Interconnection Customer or MHVDC Connection Customer to the \noriginal In-Service Date or Commercial Operation Date of the Generating Facility \nor MHVDC Transmission Line in the original Interconnection Request shall be \ndeemed a Material Modification except that the Transmission Provider will not \nunreasonably withhold approval of an Interconnection Customer’s or MHVDC \nConnection Customer’s proposed change in the original In-Service Date or \nCommercial Operation Date of the Generating Facility or MHVDC Transmission \nLine if that change is the result of either (a) a change in milestones by another \nparty to the GIA or TCA, (b) a change in a higher queued Interconnection \nRequest, (c) delays in the completion of the Definitive Planning Phase Studies, or \n(d) Interconnection Customer demonstrates that engineering, permitting and \nconstruction of the Generating Facility will take longer than the process window \nfor the Transmission Provider’s Definitive Planning Phase period. Where such \nexceptions apply, extensions to the Commercial Operation Date or In-Service \nDate shall not exceed three years beyond the original Commercial Operation Date"},{"page":214,"startToken":60981,"endToken":61326,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nor In-Service Date in the Interconnection Request.  A change to either of these \ndates that exceeds three years from the date in the original Interconnection \nRequest is a Material Modification.  At the completion of the Definitive Planning \nPhase, the specified Commercial Operation Date and In-Service Date shall be set \nforth in Appendix B of a GIA.  Consistent with Article 2.3.1 of the GIA, once that \nGIA is executed or filed unexecuted, if the Generating Facility fails to reach \nCommercial Operation by the specified Commercial Operation Date set forth in \nthe GIA, such specified Commercial Operation Date as set forth in the GIA may \nbe extended by Interconnection Customer for a period up to three (3) consecutive \nyears, after which Transmission Provider shall terminate the GIA if the \nGenerating Facility has still failed to reach Commercial Operation.  \nNotwithstanding the foregoing, in the limited circumstance that Transmission \nOwner Interconnection Facilities, Network Upgrades, or System Protection \nFacilities necessary to enable Trial Operation of a Generating Facility has an in-\nservice date that is farther out than the Commercial Operation Date permitted \nunder this Section 4.4.4 or, has an in-service date that does not allow for a one-\nhundred eighty (180) Calendar Day Trial Operation period, Transmission \nProvider shall only terminate the GIA for failure to achieve Commercial \nOperation by a Commercial Operation Date one-hundred eighty (180) Calendar \nDays after the in-service date of the Transmission Owner Interconnection \nFacilities, Network Upgrades, or System Protection Facilities necessary for Trial \nOperation. \n \n4.4.4.1 Transmission Owner In-Service Date extension. \nPrior to end of GIA negotiation and in the limited circumstance that a \nTransmission Owner determines it cannot complete Transmission Owner \nInterconnection Facilities, Network Upgrades, or System Protection \nFacilities specified in the GIA using Reasonable Efforts by the In-Service \nDate permitted under this Section 4.4.4, the specified In-Service Date may \nbe extended at the Transmission Owner’s request for a period up to two"},{"page":215,"startToken":61326,"endToken":61598,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n(2) consecutive years and specified in the GIA. This provision does not \nalter Interconnection Customer’s Commercial Operation Date \nrequirements of this Section 4.4.4 or other provisions set forth in \nAppendix 6 of these GIP regarding Commercial Operation Date or In-\nService Date. The Interconnection Customer is expected to construct \nfacilities in parallel with the Transmission Owner’s construction activities.   \n \n4.4.5 After entering the Definitive Planning Phase, any modification to the fuel source \ndesignated in the Interconnection Request, other than a modification to reduce the \nnumber of fuel source(s) of an Interconnection Request with two or more fuel \nsources before the kick-off of the Definitive Planning Phase I, shall be deemed a \nMaterial Modification. \n \n \nSECTION 5. PROCEDURES FOR INTERCONNECTION REQUESTS SUBMITTED \nPRIOR TO EFFECTIVE DATE OF GENERATOR INTERCONNECTION \nPROCEDURES.   \n \n5.1 \nQueue Position for Pending Requests. \n \n5.1.1 All Interconnection Requests that have entered a Definitive Planning Phase and \nthe Definitive Planning Phase System Impact Study has been completed prior to \nJanuary 4, 2017 will complete the Definitive Planning Phase pursuant to the \napproved GIP in effect on January 3, 2017.  The August 2015 Definitive Planning \nPhase cycle shall be completed pursuant to the approved GIP in effect on January \n3, 2017. \n \n5.1.2 All Interconnection Requests that have entered a Definitive Planning Phase and \nthe System Impact Study has not been started, or started and not completed, as of \nJanuary 4, 2017 will be required to conform to Section 7 of this GIP excluding"},{"page":216,"startToken":61598,"endToken":61980,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nSection 7.2 “Eligibility for the Definitive Planning Phase” and the Site Control \nprovisions found in Section 7.3.2.4 so long as the Interconnection Customer has \npreviously complied with the then existing Section 8.2 “Eligibility for the \nDefinitive Planning Phase.”  All study deposits will be applied to studies \nperformed under this transition plan and M2 milestone amounts previously paid \nwill satisfy the M2 milestone requirement of Section 7.2. These projects will then \nfollow all other sections of these Generator Interconnection Procedures in effect \nas of January 4, 2017. \n \n5.1.3 All Interconnection Requests that have been received but have not had an M2 \nmilestone calculated as of January 4, 2017, and have not met the requirements of \nSection 5.1.4, will be required to conform to Section 7 of these GIPs and will then \nfollow all other sections of these Generator Interconnection Procedures in effect \nas of January 4, 2017. \n \n5.1.4 All Interconnection Requests that are in the System Planning and Analysis Phase \nof the GIPs in effect prior to January 4, 2017 may pay their M2 milestone \npayment prior to January 4, 2017 and shall be treated pursuant to section 5.1.2.  \nInterconnection Requests that are in the System Planning and Analysis Phase \nprior to the effective date of these GIPs that have not paid an M2 milestone \npayment prior to January 4, 2017 shall be treated pursuant to section 5.1.3. \nInterconnection Requests that are in the System Planning and Analysis Phase may \nremain in the System Planning and Analysis Phase until 45 Calendar Days prior \nto the start of the first cycle under these GIPs which begins August 1, 2017.  \nMISO shall deem withdrawn any Interconnection Requests that are in the System \nPlanning and Analysis Phase that have not made their M2 milestone payment at \nleast 45 Calendar Days prior to the start of the first cycle under these GIPs.  \nNotwithstanding the foregoing, any request for HVDC facilities listed as being in \nthe System Planning and Analysis Phase as of June 16, 2017 shall be deemed \ntransferred into the Pre-Queue Phase.  Furthermore, any MHVDC projects in the"},{"page":217,"startToken":61980,"endToken":62289,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nPre-Queue Phase as of the effective date of the MHCP shall be deemed \ntransferred to the MHCP, as set forth in Section 4 of the MHCP.  \n \n5.2 \nTransition Period. \nAn Interconnection Customer of a new transmission owning member of Transmission \nProvider shall transition to the revised GIP within a reasonable period of time not to \nexceed ninety (90) Calendar Days from the date when this GIP becomes applicable to \nthat transmission owning member.  \n \n5.3 \nNew Transmission Provider. \nIf Transmission Provider transfers control of its Transmission System to a successor \nTransmission Provider during the period when an Interconnection Request is pending, the \noriginal Transmission Provider shall transfer to the successor Transmission Provider any \namount of the deposit or payment with interest thereon that exceeds the cost that it \nincurred to evaluate the request for interconnection.  Any difference between such net \namount and the deposit or payment required by the GIP shall be paid by or refunded to \nInterconnection Customer, as appropriate.  The original Transmission Provider shall \ncoordinate with the successor Transmission Provider to complete any Interconnection \nStudy, as appropriate, that the original Transmission Provider has begun but has not \ncompleted.  If Transmission Provider has tendered a draft GIA to Interconnection \nCustomer but Interconnection Customer has not either executed the GIA or requested the \nfiling of an unexecuted GIA with FERC, unless otherwise provided, Interconnection \nCustomer must complete negotiations with the successor Transmission Provider. \n \n5.4 \nTransition to Revised Scope of DPP Phase I Studies. \nWith the exception of this provision, the Tariff revisions accepted in Docket Nos. ER18-\n2049-000 and -001 shall not apply to any queue cycle(s) for which the Definitive \nPlanning Phase Preliminary System Impact Study has started prior to September 19, \n2018."},{"page":218,"startToken":62289,"endToken":62610,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n5.5 \nTransitional Notice Requirements for Generating Facility Replacement. \nAll requests for Replacement Generating Facility that are submitted to the Transmission \nProvider within 365 Calendar Days after May 16, 2019 shall have a date of cessation of \noperation for the Existing Generating Facility that is not earlier than May 16, 2021. \n \n5.6 \nTransition to Revised Milestone Requirements Accepted in Docket No. ER20-41. \n \nAll Interconnection Requests for which the application deadline to enter the Definitive \nPlanning Phase was prior to April 29, 2019 shall be required to adhere to milestone \nrequirements in GIP in effect prior to December 4, 2019. \n \nAll Interconnection Requests for which the application deadline to enter the Definitive \nPlanning Phase was on April 29, 2019 shall be required to adhere to the revised milestone \nrequirements accepted in Docket No. ER20-41, but shall not be subject to the M2 refund \nprovisions in Section 7.6.2.1 of this GIP.  All Interconnection Requests for which the \napplication deadline to enter the Definitive Planning Phase was on April 29, 2019 shall \nbe subject to M2 refund provisions in effect prior to December 4, 2019. \n \nAll Interconnection Requests for which the application deadline to enter the Definitive \nPlanning Phase is after April 29, 2019 shall be required to adhere to the revised milestone \nrequirements accepted in Docket No. ER20-41. \n \n5.7 \nTransition to Revised Site Control Requirements Accepted in Docket No. ER20-41. \n \nAll Interconnection Requests for which the application deadline to enter the Definitive \nPlanning Phase was prior to April 29, 2019 shall be required to adhere to Site Control \nrequirements in GIP in effect prior to December 4, 2019. \n \nAll Interconnection Requests for which the application deadline to enter the Definitive \nPlanning Phase was on April 29, 2019 shall be required to provide proof of Site Control"},{"page":219,"startToken":62610,"endToken":62958,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nfor the Generation Facility by the end of Interconnection Customer Decision Point II in \naccordance with the timing requirements established in Section 7.2.2.1.  Such \nInterconnection Requests shall not be required to provide proof of Site Control for the \nGenerating Facility ninety (90) Calendar Days prior to the start of DPP Phase I in \naccordance with the timing requirements established in Section 7.2.1.  For such requests, \nthe proof of Site Control for all applicable Interconnection Customer’s Interconnection \nFacilities, and, if applicable (i.e., when the Interconnection Customer is providing the site \nfor such facilities), the Transmission Owner’s Interconnection Facilities and Network \nUpgrades at the POI shall be due in accordance with the terms of Sections 7.2.2.1 and \n7.2.2.2. \n \nAll Interconnection Requests for which the application deadline to enter the Definitive \nPlanning Phase is after April 29, 2019 will be subject to the Site Control requirements as \nset forth in Section 7.2. \n \n5.8 \nTransition to Self-Fund Deadline Accepted in Docket No. ER20-2632. \n \nFor all Network Upgrades and System Protection Facilities that were identified in a \nRevised System Impact Study that completed prior to November 5, 2020 and for which \nthe Final System Impact Study was not completed as of November 5, 2020, the \nTransmission Owner shall make an election as to whether the Transmission Owner \nintends to self-fund each specific Network Upgrade and System Protection Facility \nidentified in the Revised System Impact Study. Transmission Owner shall make its \nelection prior to the completion of the Final System Impact Study. \n \nFor all Network Upgrades and System Protection Facilities that were identified in a Final \nSystem Impact Study that completed prior to November 5, 2020 and for which the \nnegotiation period for the GIA was not completed as of November 5, 2020, the \nTransmission Owner may make an election as to whether the Transmission Owner \nintends to self-fund each specific Network Upgrade and System Protection Facility prior"},{"page":220,"startToken":62958,"endToken":63256,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nto the completion of the GIA negotiation period. \n \n5.9  \nTransition to revised DPP schedule in Docket No. ER22-661. \n \nInterconnection Requests for which Transmission Provider started the DPP Phase III \nFinal System Impact Study before March 15, 2022 will be subject to the Tariff \nrequirements in effect prior to March 15, 2022.  Interconnection Requests for which the \nDPP Phase III Final System Impact Study has not started as of March 15, 2022 will be \nsubject to the revised Tariff accepted in Docket No. ER22-661.  \n \n5.10 \nTransition to DPP revisions in Docket No. ER24-___. \n \nAll Interconnection Requests for which the application deadline to enter the Definitive \nPlanning Phase is on or after January 22, 2024 will be subject to the revised Tariff \nrequirements accepted in Docket Nos. ER24-____ and ER24-____.  All Interconnection \nRequests for which the application deadline to enter the Definitive Planning Phase is \nprior to January 22, 2024 will not be subject to the revised Tariff requirements accepted \nin Docket Nos. ER24-____ and ER24-____. \n \n5.11 \nTransition to DPP revisions in Docket No. ER24-2046. \n \nAll Interconnection Requests for which the application deadline to enter the Definitive \nPlanning Phase is on or after June 1, 2025 will be subject to the revised Tariff \nrequirements accepted in Docket No. ER24-2046 .  Except for the requirements in \nSection 7.3.2.3 and Section 11.2.1, all Interconnection Requests for which the application \ndeadline to enter the Definitive Planning Phase is prior to June 1, 2025 will not be subject \nto the revised Tariff requirements accepted in Docket No. ER24-2046. \n \n5.12 \nTransition to JTIQ Process. \nInterconnection Requests for which the application deadline to enter the Definitive"},{"page":221,"startToken":63256,"endToken":63522,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nPlanning Phase is after the date that the Transmission Provider and SPP’s Boards have \napproved a JTIQ Portfolio shall be subject to the JTIQ process set forth in Section 9.4.2 \nof Rate Schedule 6 (MISO-SPP JOA) and the JTIQ provisions of these GIP.   \n \n5.13 \nTransition to DPP revisions in Docket No. ER25-___. \n \nAll Interconnection Requests for which the application deadline to enter the Definitive \nPlanning Phase is on or after January 31, 2025, will be subject to the revised Tariff \nrequirements accepted in Docket No. ER25-____.  All Interconnection Requests for \nwhich the application deadline to enter the Definitive Planning Phase is prior to January \n31, 2025, will not be subject to the revised Tariff requirements accepted in Docket No. \nER25-____. \n \n5.14  Transition to ERAS Process. \n \nAll requests for the Expedited Resource Addition Study that are submitted to the \nTransmission Provider after August 6, 2025 will be subject to the revised Tariff \nrequirements accepted in Docket No. ER25-___. \n \n \nSECTION 6. PRE-QUEUE PHASE. \n \n6.1 \nPre-Queue Customer Education \nTransmission Provider will be available for consultation with Interconnection \nCustomer to discuss potential Interconnection Requests for Generating Facilities \nor study and processing of HVDC facilities.  Such discussions may include, but \nare not limited to:  (i) general facility loadings; (ii) general instability issues; (iii) \ngeneral short circuit issues; (iv) general voltage issues including voltage and \nfrequency ride-through capabilities for the Generating Facility; (v) general power \nquality issues including voltage flicker, harmonics; (vi) general reliability issues"},{"page":222,"startToken":63522,"endToken":63750,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nas may be reasonably required to accomplish the purpose of the meeting; (vii) \nestimated timing of Interconnection Request proceeding to the Definitive \nPlanning Phase; (viii) estimated in-service date for the request; and (ix) any \nprocess related questions.   \n \n6.1.1  Publicly Posted Interconnection Information. \nTransmission Provider shall maintain and make publicly available:   \n \n(1) an interactive visual representation of the estimated incremental \ninjection capacity (in megawatts) available at each point of \ninterconnection in Transmission Provider’s footprint under N-1 \nconditions, and   \n \n(2) a table of metrics concerning the estimated impact of a potential \nGenerating Facility on Transmission Provider’s Transmission System \nbased on a user-specified addition of a particular number of megawatts at \na particular voltage level at a particular point of interconnection.   \n \nAt a minimum, for each transmission facility impacted by the user-\nspecified megawatt addition, the following information will be provided in \nthe table:   \n \n(1) the distribution factor;  \n(2) the megawatt impact (based on the megawatt values of the \nproposed Generating Facility and the distribution factor);  \n(3) the percentage impact on each impacted transmission facility (based on \nthe megawatt values of the proposed Generating Facility and the facility \nrating);  \n(4) the percentage of power flow on each impacted transmission facility \nbefore the injection of the proposed project;"},{"page":223,"startToken":63750,"endToken":64014,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n(5) the percentage power flow on each impacted transmission facility after \nthe injection of the proposed Generating Facility.   \n \nThese metrics must be calculated based on the power flow model of the \nTransmission System with the transfer simulated from each point of \ninterconnection to the whole Transmission Provider’s footprint (to approximate \nNetwork Resource Interconnection Service), and with the incremental capacity at \neach point of interconnection decremented by the existing and queued Generating \nFacilities (based on the existing or requested interconnection service limit of the \ngeneration).   \n \nThese metrics must be updated within thirty (30) Calendar Days after the \ncompletion of each Preliminary or Final System Impact Study, only for the most \nrecent Definitive Planning Phase cycle and excluding earlier cycles.   \n \nThis information must be publicly posted, without a password or a fee.  \n \nThe website will define all underlying assumptions, including the name of the \nmost recent  System Impact Study or Interconnection Study restudy used in the \nBase Case. \n \n6.2 \nInterim Treatment of HVDC Facilities in Pre-Queue Phase:  All requests for \nHVDC facilities deemed transferred into the Pre-Queue Phase pursuant to Section \n5.1.4 of this GIP or which otherwise are permitted to enter the Pre-Queue Phase \nshall not be eligible to proceed to the Definitive Planning Phase until such time as \nadditional procedures for processing such facilities are implemented. \n \n6.3 \nSmall Generating Facility Pre-Application Report. \n \n6.3.1 In addition to the information described in section 6.1, which may be"},{"page":224,"startToken":64014,"endToken":64290,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nprovided in response to an informal request, an Interconnection Customer \nproposing to interconnect its Small Generating Facility may submit a \nformal written request form along with a non-refundable fee of $300 for a \npre-application report on a proposed project at a specific site.  The \nTransmission Provider shall provide the pre-application data described in \nsection 6.3.2 to the Interconnection Customer within twenty (20) Business \nDays of receipt of the completed request form and payment of the $300 \nfee.  Should the Transmission Provider notify the Interconnection \nCustomer that more than twenty (20) Business Days are necessary to \nprovide the pre-application data described in section 6.3.2 below because \nthe information is not readily available to the Transmission Provider, the \nInterconnection Customer shall notify the Transmission Provider that it \ndesires more complete information and waives the twenty (20) Business \nDay timeline. The pre-application report produced by the Transmission \nProvider is non-binding, does not confer any rights, and the \nInterconnection Customer must still successfully apply to interconnect to \nthe Transmission Provider’s system.  The written pre-application report \nrequest form shall include the information in sections 6.3.1.1 through \n6.3.1.8 below to clearly and sufficiently identify the location of the \nproposed Point of Interconnection. \n \n6.3.1.1 Project contact information, including name, address, phone \nnumber, and email address. \n \n6.3.1.2 Project location (street address with nearby cross streets and \ntown) \n \n6.3.1.3 Meter number, pole number, or other equivalent information \nidentifying proposed Point of Interconnection, if available."},{"page":225,"startToken":64290,"endToken":64542,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n6.3.1.4 Generator Type (e.g., solar, wind, combined heat and power, etc.) \n \n6.3.1.5 Size (alternating current kW) \n \n6.3.1.6 Single or three phase generator configuration \n \n6.3.1.7 Stand-alone generator (no onsite load, not including station \nservice – Yes or No?) \n \n6.3.1.8 Is new service requested?  Yes or No?  If there is existing service, \ninclude the customer account number, site minimum and \nmaximum current or proposed electric loads in kW (if available) \nand specify if the load is expected to change. \n \n6.3.2 Using the information provided in the pre-application report request form \nin section 6.3.1, the Transmission Provider will identify the \nsubstation/area bus, bank or circuit likely to serve the proposed Point of \nInterconnection.  This selection by the Transmission Provider does not \nnecessarily indicate, after application of the screens and/or study, that this \nwould be the circuit the project ultimately connects to.  The \nInterconnection Customer must request additional pre-application reports \nif information about multiple Points of Interconnection is requested.  \nSubject to section 6.3.3, the pre-application report will include the \nfollowing information: \n \n6.3.2.1 Total capacity (in MW) of substation/area bus, bank or circuit \nbased on normal or operating ratings likely to serve the proposed \nPoint of Interconnection. \n \n6.3.2.2 Existing aggregate generation capacity (in MW) interconnected"},{"page":226,"startToken":64542,"endToken":64782,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nto a substation/area bus, bank or circuit (i.e., amount of \ngeneration online) likely to serve the proposed Point of \nInterconnection. \n \n6.3.2.3 Aggregate queued generation capacity (in MW) for a \nsubstation/area bus, bank or circuit (i.e., amount of generation in \nthe queue) likely to serve the proposed Point of Interconnection. \n \n6.3.2.4 Available capacity (in MW) of substation/area bus or bank and \ncircuit likely to serve the proposed Point of Interconnection (i.e., \ntotal capacity less the sum of existing aggregate generation \ncapacity and aggregate queued generation capacity). \n \n6.3.2.5 Substation nominal distribution voltage and/or transmission \nnominal voltage if applicable. \n \n6.3.2.6 Nominal distribution circuit voltage at the proposed Point of \nInterconnection. \n6.3.2.7 Approximate circuit distance between the proposed Point of \nInterconnection and the substation. \n \n6.3.2.8 Relevant line section(s) actual or estimated peak load and \nminimum load data, including daytime minimum load as \ndescribed in section 14.4.4.1.1 below and absolute minimum \nload, when available. \n \n6.3.2.9 Number and rating of protective devices and number and type \n(standard, bi-directional) of voltage regulating devices between \nthe proposed Point of Interconnection and the substation/area.  \nIdentify whether the substation has a load tap changer."},{"page":227,"startToken":64782,"endToken":65067,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \n6.3.2.10 Number of phases available at the proposed Point of \nInterconnection.  If a single phase, distance from the three-phase \ncircuit. \n6.3.2.11 Limiting conductor ratings from the proposed Point of \nInterconnection to the distribution substation. \n \n6.3.2.12 Whether the Point of Interconnection is located on a spot \nnetwork, grid network, or radial supply. \n \n6.3.2.13 Based on the proposed Point of Interconnection, existing or \nknown constraints such as, but not limited to, electrical \ndependencies at that location, short circuit interrupting capacity \nissues, power quality or stability issues on the circuit, capacity \nconstraints, or secondary networks. \n \n6.3.3 The pre-application report need only include existing data.  A pre-\napplication report request does not obligate the Transmission Provider to \nconduct a study or other analysis of the proposed generator in the event \nthat data is not readily available.  If the Transmission Provider cannot \ncomplete all or some of a pre-application report due to lack of available \ndata, the Transmission Provider shall provide the Interconnection \nCustomer with a pre-application report that includes the data that is \navailable.  The provision of information on “available capacity” pursuant \nto section 6.3.2.4 does not imply that an interconnection up to this level \nmay be completed without impacts since there are many variables studied \nas part of the interconnection review process, and data provided in the pre-\napplication report may become outdated at the time of the submission of \nthe complete Interconnection Request.  Notwithstanding any of the \nprovisions of this section, the Transmission Provider shall, in good faith,"},{"page":228,"startToken":65067,"endToken":65330,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ninclude data in the pre-application report that represents the best available \ninformation at the time of reporting. \n \nSECTION 7. DEFINITIVE PLANNING PHASE. \n \n7.1 \nPurpose of the Definitive Planning Phase. \nThe Definitive Planning Phase is designed to identify Network Upgrades that will \nreliably and efficiently integrate the proposed generation, including through \nInjection Rights requested by MHVDC Connection Customer, into the \nTransmission Provider’s Transmission System.  The Definitive Planning Phase \nwill be composed of three distinct phases in which Interconnection System Impact \nStudies and Interconnection Facilities Studies will be performed. \n \n7.1.1 Screening Analysis Prior to Definitive Planning Phase I. \nTransmission Provider will perform an indicative non-binding screening \nanalysis to identify potential thermal and voltage constraints and publish \nthe results of that analysis for Interconnection Customers, MHVDC \nConnection Customers entering the Definitive Planning Phase and \nAffected System Operator(s) at least fifteen (15) Calendar Days prior to \nthe kick-off of the Definitive Planning Phase I.  The Transmission \nProvider shall indicate with this screening analysis whether \nInterconnection Requests in the applicable DPP study group are expected \nto be included in a JTIQ Participation Group based on available \ninformation.  If the Interconnection Customer or MHVDC Connection \nCustomer decides to withdraw its Interconnection Request before the start \nof the Definitive Planning Phase I, then the Transmission Provider will \nrefund to Interconnection Customer or the MHVDC Connection Customer \n100% of Definitive Planning Phase entry milestone (M2) and any \nremaining study deposits pursuant to Section 7.6."},{"page":229,"startToken":65330,"endToken":65609,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n7.2 \nEligibility for the Definitive Planning Phase. \nThe Interconnection Request shall enter the Definitive Planning Phase upon the \nTransmission Provider accepting the Interconnection Request as valid pursuant to \nSection 3.3.3 of this GIP after the Interconnection Customer or MHVDC \nConnection Customer has met the requirements of Section 3.3.1. The Definitive \nPlanning Phase will start on a periodic basis, where an Interconnection Customer \nor MHVDC Connection Customer may elect to enter the next scheduled \nDefinitive Planning Phase. \n \n7.2.1 Requirements for Demonstrating Site Control for Generating Facility \nand Interconnection Facilities. \nExcept as otherwise noted in Section 5.7, at the time of the submission of \nan Interconnection Request, the Interconnection Customer shall submit the \nfollowing to the Transmission Provider: \n \n(i)  \nProof of Site Control for the Generating Facility demonstrating \nthat the Interconnection Customer has obtained a right to develop \nthe site, and that such Site Control:  \n(a)  \nis exclusive to the specific project referenced in the \nInterconnection Request and the site meets the total resource-\nspecific acreage requirements established in the Generator \nInterconnection Business Practices Manual; or  \n(b)  \neither is shared by multiple projects by mutual agreement \nor includes less acreage than the standard resource-specific acreage \nrequirements established in the Generator Interconnection Business \nPractice but is nonetheless sufficient to accommodate the final \ndesign of the Generating Facility, and account for any other \nprojects that will utilize all or part of the same site Interconnection \nRequests from multiple Interconnection Customers for multiple \nGenerating Facilities that share a site must include a contract or"},{"page":230,"startToken":65609,"endToken":65895,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nother agreement that allows for shared Site Control; or \n  \n(c) \nA financial security in lieu of Site Control and supporting \ndocumentation demonstrating regulatory restrictions in accordance \nwith Section 7.2.1.2 of this GIP.  \n \n(ii)  \nReasonable evidence of Site Control, as described in the Generator \nInterconnection Business Practices Manual, for at least fifty \npercent (50%) of the mileage of the Generating Facility’s or \nFacilities’ Interconnection Facilities, or in lieu of Site Control for \nthe Generating Facility’s or Facilities’ Interconnection Facilities, \nadditional financial security in the amount of $80,000 per line mile \nof right-of-way, on a straight line basis.  Interconnection \nCustomer’s financial security provided in lieu of Site Control shall \nonly be refunded once the Interconnection Customer satisfies the \nSite Control requirements or is withdrawn from the queue.  The \nsecurity can be provided in the form of cash, irrevocable letter of \ncredit or surety bond reasonably acceptable to Transmission \nProvider.  The surety bond must be issued by an insurer reasonably \nacceptable to Transmission Provider and must specify a reasonable \nexpiration date.  The Transmission Provider may establish \nadditional requirements for what constitutes a surety bond, \nincluding but not limited to, duration satisfaction, demand \ntimeframe and issuer requirements through the Generator \nInterconnection Business Practices manual (BPM).  Reasonable \nevidence of Site Control for one hundred percent (100%) of the \nmileage of the Generating Facility’s Interconnection Facilities for \nthe Expedited Resource Addition Study request must be received \nat the time the application is submitted.  The financial security in \nlieu of Site Control for the Generating Facility’s Interconnection \nFacilities will not be accepted for an Expedited Resource Addition"},{"page":231,"startToken":65895,"endToken":66170,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nStudy request. \n \nAny advancement or postponement to the DPP Phase I kickoff date made \nafter the application deadline for such cycle shall not alter the deadline for \nsubmitting proof of Site Control. \n \nSite Control for a Generating Facility and Interconnection Facility shall be \ndemonstrated in accordance with Section 7.2.1.1 and Section 7.2.1.2 of \nthis GIP.   \n \nAll documentation establishing proof of Site Control under Sections 7.2.1 \nof this GIP shall be accompanied by a signed affidavit from an officer or \nfrom an agent of the Interconnection Customer stating either that the \nInterconnection Customer: (1) possesses Site Control in accordance with \nSection 7.2.1.1 of this GIP; or (2) is subject to regulatory restrictions that \npreclude Interconnection Customer from obtaining Site Control pursuant \nto Section 7.2.1.2 of this GIP.  Such affidavit shall adhere to the form \nspecified in Attachment E of Appendix 1 of Attachment X.   \n \nBefore the kickoff of DPP Phase I, Interconnection Customer may modify \nup to 100% of the Site Control for the Generating Facility and up to 100% \nof its Interconnection Customer Interconnection Facilities as provided for \nin its Interconnection Request if (1) the Interconnection Customer does not \nmove the POI; (2) the Transmission Owner determines a POI move is \nnecessary to accommodate the Interconnection Request; or (3) the \nInterconnection Customer can demonstrate, based on sound engineering \njudgment, that Site Control modification is necessary to optimize the \nsiting of the project. \n \n7.2.1.1 Site Control Demonstration."},{"page":232,"startToken":66170,"endToken":66429,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nIn order to demonstrate Site Control for a Generating Facility and \nInterconnection Facilities, an Interconnection Customer must submit the \nfollowing:  \n \n(i) \nTo demonstrate that an Interconnection Customer has Site Control \nin accordance with Section 7.2.1(i)(a) and 7.2.1(ii) of this GIP, a \nGeographic Information System (GIS) site plan map, data files, \nand documentation that shows the following information: (a) \nsufficient land to meet the acreage requirements set forth in the \nGenerator Interconnection Business Practices Manual; (b) \nboundary for the proposed project indicating the boundaries of the \nInterconnection Customer’s leasehold/ownership interests for the \nsite; and (c) the proposed location of each of the following: the \nCollector Substation, the Point of Interconnection, and the \nInterconnection Facilities based on the Point of Interconnection. \n \n(ii) \nTo demonstrate that an Interconnection Customer has obtained Site \nControl in accordance in accordance with Section 7.2.1(i)(b) of \nthis GIP, Interconnection Customer must submit a Geographic \nInformation System (GIS) site plan map, data files, and \ndocumentation that meets the requirements specified in Section \n7.2.1.1(i)(b) and (c) and show the following additional \ninformation:  \n \n(a) Sufficient land to accommodate the proposed Generating \nFacility based on the location and approximate land utilization \nrequirements of proposed electrical devices (i.e., turbine, solar \npanel, battery storage, inverter), local spacing and setback \nrequirements, and the proposed location of the feeder routes to the \nCollector Substation; and"},{"page":233,"startToken":66429,"endToken":66661,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \n(b) In the event that Interconnection Customer elects to share a site \nwith other projects in accordance with Section 7.2.1(i)(b) of this \nGIP, \nInterconnection \nCustomer \nshall \ninclude \nwith \nits \nInterconnection Request documentation demonstrating that the \nproject referenced in the Interconnection Request is concurrently \nfeasible with the development of any other projects that will share \nSite Control over all or a portion of the same site.  Such proof of \nconcurrent feasibility shall include:  \n \n(1) an identification of any other Interconnection Requests \nor projects that will share all or a portion of the same site; \nand  \n \n(2) identification of the proposed location and space \nutilization of all projects that will share the site together \nwith any related technical information specified in the \nGenerator Interconnection Business Practices Manual to \nenable the Transmission Provider to determine that \ndevelopment of the project referenced in the submitted \nInterconnection \nRequest \nis \nnot \ninconsistent \nwith \ndevelopment of any of the other projects that will share all \nor a portion of the same site.  \n \n(3) Interconnection Requests from multiple Interconnection \nCustomers for multiple Generating Facilities that share a \nsite must include a contract or other agreement that allows \nfor shared land use. \n \nAny GIS site plan map, and data files submitted in accordance with this"},{"page":234,"startToken":66661,"endToken":66985,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nSection 7.2.1.1 must be consistent with the modeling data submitted with \nthe Interconnection Request. \n \n7.2.1.2 Financial Security in lieu of Site Control.  \nIf the Interconnection Customer is unable to obtain Site Control for its \nproposed Generating Facility as a result of regulatory restrictions, the \nInterconnection Customer shall provide a cash deposit in lieu of Site \nControl.  In order to demonstrate regulatory restrictions, Interconnection \nCustomer must submit: (i) a signed affidavit from an officer of the \ncompany in accordance with the terms of Section 7.2.1 of this GIP \nindicating that Site Control is unobtainable due to regulatory requirements \nas such term is defined by the Transmission Provider; (ii) documentation \nsufficiently describing and explaining the source of and effects of such \nregulatory restrictions, including a description of any conditions that must \nbe met in order to satisfy the regulatory restrictions and the anticipated \ntime by which the Interconnection Customer expects to satisfy the \nregulatory restrictions.  The financial security provided in lieu of Site \nControl, as cash deposit, irrevocable letter of credit or surety bond \nreasonably acceptable to Transmission Provider, shall be $10,000 per MW \nof new Interconnection Service requested, and at least $500,000 but no \nmore than $2,000,000.  The surety bond must be issued by an insurer \nreasonably acceptable to Transmission Provider and must specify a \nreasonable expiration date.  The Transmission Provider may establish \nadditional requirements for what constitutes a surety bond, including but \nnot limited to, duration satisfaction, demand timeframe and issuer \nrequirements through the Generator Interconnection Business Practices \nmanual (BPM).  In the event that Interconnection Customer needs to \nsubmit a financial security in lieu of Site Control as a result of regulatory \nrestrictions, Interconnection Customer must provide proof of Site Control \nas soon as the Interconnection Customer satisfies the regulatory"},{"page":235,"startToken":66985,"endToken":67266,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nrequirements described in the Interconnection Customer’s affidavit and \nsupporting documents.  Interconnection Customer’s financial security \nmade in lieu of Site Control shall only be refunded once the \nInterconnection Customer satisfies the Site Control requirements in \naccordance with the terms of Sections 7.2.1(i), 7.2.1.1, and 7.2.2 of the \nGIP or is withdrawn from the queue.  \n \n7.2.1.3 Transmission Provider Review of Site Control Sufficiency.  \nThe Transmission Provider shall review the Site Control documentation \nsubmitted by Interconnection Customer and determine whether the \nInterconnection Customer has satisfied the applicable Site Control \nrequirements specified in Section 7.2.1, and 7.2.1.1 or 7.2.1.2 of this GIP, \nas applicable.  Transmission Provider shall evaluate the Site Control \ndocumentation using sound engineering judgement and in a non-\ndiscriminatory manner.  In addition, Transmission Provider shall adhere to \nany guidelines for such analysis as may be included in the Generator \nInterconnection Business Practices Manual.  \n \nIn the event that the Transmission Provider determines that the \nInterconnection Customer does not demonstrate sufficient Site Control, \nTransmission Provider shall, consistent with Section 7.2.3(ii) of this GIP, \nprovide a written explanation, including the technical reasons for such \ndetermination, to Interconnection Customer no later than sixty (60) \nCalendar Days from the Site Control submission deadline.  Any such \ndeficiencies shall be processed as set forth in Section 7.2.3(ii) of this GIP.  \n \n7.2.2  Continued Site Control for Generating Facilities; Site Control for \nInterconnection Facilities and Network Upgrades.  \n \n7.2.2.1 Timing Requirements."},{"page":236,"startToken":67266,"endToken":67543,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \n(i)  \nAfter the start and prior to the end of Interconnection Customer \nDecision Point II, Interconnection Customer shall submit proof \nthat Interconnection Customer continues to maintain Site Control \nfor the Generating Facility in accordance with terms in Section \n7.2.1.1 of this GIP.  Regarding Interconnection Customer’s \nInterconnection Facilities, in addition to the requirements specified \nin Section 7.2.1.ii of this GIP, the Interconnection Customer will \nbe required to demonstrate fifty (50%) site control for the site on \nwhich a switchyard will be located, if requested by the \nTransmission Provider. \n \n(ii)  \nPrior to conclusion of the Interconnection Customer’s GIA \nexecution period, as defined in Section 11 of this GIP, or within \n180 days of GIA Effective Date with an approved exception by the \nTransmission Provider, Interconnection Customer shall submit \nproof of the following: (a) continued Site Control for the \nGenerating Facility in accordance with terms in Section 7.2.1.1 of \nthis GIP; and (b) 100% Site Control for all Interconnection \nCustomer’s Interconnection Facilities (including demonstration of \nswitchyard site control if requested by the Transmission Provider), \nand, if applicable (i.e., when the Interconnection Customer is \nproviding the site for such facilities), the Transmission Owner’s \nInterconnection Facilities and Network Upgrades at the POI that \nthe Interconnection Customer will develop. \n \n(iii) \nTo the extent there is any change in the POI as a result of the \nInterconnection Facilities Study started in DPP Phase II and \ncompleted in DPP Phase III, the Transmission Provider shall \nprovide the Interconnection Customer additional time to procure"},{"page":237,"startToken":67543,"endToken":67837,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nland rights for the new Interconnection Customer’s Interconnection \nFacilities and, if applicable (i.e., when the Interconnection \nCustomer is providing the site for such facilities), the Transmission \nOwner’s Interconnection Facilities and Network Upgrades at the \nPOI that the Interconnection Customer will develop.  The amount \nof additional time awarded for this purpose shall be determined on \na case-by-case basis and in accordance with Section 4.4 of this \nGIP.   \n \n(iv) \nAfter the Interconnection Customer timely satisfies each of the \nrequirements of this Section 7.2.2.1 and execution of the GIA, any \nchanges made to the site layouts and interconnection facility routes \nshall not be construed as a failure to satisfy the requirements of this \nSection 7.2.2.1.  In the event that the Interconnection Customer \nmakes any modifications to the design of the site layouts or \nInterconnection Facility routes after execution of this GIA, \nInterconnection Customer shall: (1) immediately notify the Parties \nof such changes; and (2) provide to Transmission Provider \nevidence of continued Site Control for land sufficient to \naccommodate the changes in site layouts and/or Interconnection \nFacility routes in accordance with the terms of its GIA. \n \n7.2.2.2 Content Requirements -- Demonstrating Site Control for \nApplicable Interconnection Facilities and Network Upgrades.  \nIn order to demonstrate Site Control for the Interconnection Customer’s \nInterconnection Facilities and, if applicable (i.e., when the Interconnection \nCustomer is providing the site for such facilities), the Transmission \nOwner’s Interconnection Facilities and Network Upgrades at the POI, \nInterconnection Customer shall submit a site plan map by the deadline \nspecified in Section 7.2.2.1 of this GIP.  Such site plan map shall"},{"page":238,"startToken":67837,"endToken":68101,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ndemonstrate land that is sufficient to accommodate 50% of the total land \nacreage required for the Interconnection Customer’s Interconnection \nFacilities for the proposed Generating Facility (including the total linear \nmiles for the associated lead line required to electrically interconnect the \nGenerating Facility to the Transmission System) and, if applicable (i.e., \nwhen the Interconnection Customer is providing the site for such \nfacilities), 50% of the total land acreage required for the Transmission \nOwner’s Interconnection Facilities and the Network Upgrades at the POI \nfor the proposed Generating Facility.  \n \nThe Site Plan submitted in accordance with Section 7.2.2 of this GIP shall \nidentify the specific locations within the site for which Site Control is \nachieved, and those locations for which Site Control is not yet achieved. \n \nTo the extent that the Interconnection Customer intends to locate its \nInterconnection Facilities in a public right of way, Interconnection \nCustomer shall also submit proof of submission of all requisite state and \nlocal permits.   \n \nDemonstration of Site Control pursuant to this Section 7.2.2.2 shall \nconform to any technical and documentation requirements as may be \nspecified in the Generator Interconnection Business Practice Manual. \n \n7.2.3.  Effect of Deficiencies in Demonstration of Site Control  \n \nIn the event that the Interconnection Customer fails to timely satisfy any \nof the requirements of Sections 7.2.1 and 7.2.2 including subsections, as \napplicable, Interconnection Customer’s Interconnection Request shall be \ndeemed withdrawn as set forth below:"},{"page":239,"startToken":68101,"endToken":68336,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n(i)   \nIf Interconnection Customer fails to submit all of the \ndocumentation and information required by the applicable \ndeadline, Interconnection Customer’s Interconnection Request \nshall immediately be deemed withdrawn as of the date of such \ndeadline without any cure period.  Transmission Provider shall \nprovide Interconnection Customer with notice of such withdrawal. \n \n(ii)   \nIf Interconnection Customer has timely submitted all information \nrequired by an applicable deadline but the Transmission Provider \ndetermines after review that such submission does not meet the \nrequirements \nof \nthis \nGIP, \nInterconnection \nCustomer’s \nInterconnection Request shall be deemed withdrawn in accordance \nwith Section 3.6 of this GIP.  \n \n7.3 \nDuration of the Definitive Planning Phase \nThe Definitive Planning Phase will include the following three phases: \n(i) \nDefinitive Planning Phase I \n(ii) \nDefinitive Planning Phase II \n(iii) \nDefinitive Planning Phase III. \n \n7.3.1 Definitive Planning Phase I \nThe Definitive Planning Phase I will start on a defined, periodic basis.  \nThe Definitive Planning Phase I will include the following steps:  \n(i) \nAttachment X, Appendix 10 Model Review (10 Business Days) \n(ii) \nPreliminary System Impact Study (65 Calendar Days) \n(iii) \nInterconnection Customer Decision Point I (15 Business Days) \n \nIn addition, Interconnection Customer may request that the Transmission \nProvider or applicable Transmission Owner initiate the Interconnection \nFacilities Study during Definitive Planning Phase I.  If Interconnection"},{"page":240,"startToken":68336,"endToken":68577,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nCustomer, Transmission Owner and Transmission Provider agree that \nsuch Interconnection Facilities Study should be performed during \nDefinitive Planning Phase I, the Transmission Provider or Transmission \nOwner conducting the study shall begin the Interconnection Facilities \nStudy during Definitive Planning Phase I. \n \nThe Transmission Provider shall establish a date agreeable to \nInterconnection Customer and Transmission Owner for a Kick-Off \nMeeting, and such date shall be one (1) Business Day prior to the kick-off \nof the Definitive Planning Phase I of that cycle published on the MISO \npublic website, unless mutually agreed upon by MISO, the Transmission \nOwner(s) and the Interconnection Customer(s). MISO, the Interconnection \nCustomer(s), and the Transmission Owner(s) must attend the Kick-Off \nMeeting. MISO shall use Reasonable Efforts to include any other Affected \nSystems in the Kick-off Meeting. \n \nThe Transmission Provider must ensure that project information during \nthe Kick-Off meeting is anonymized and does not reveal the identity or \ncommercial information of interconnection customers with submitted \nrequests.   \n \nAll withdrawal and modification requests must be submitted within 24 \nhours of the conclusion of the kick-off meeting prior to the start of the \nDPP process. \n \nDuring the Customer Engagement Window, Transmission Provider shall \nprovide to Interconnection Customer a non-binding updated good faith \nestimate of the cost and timeframe for completing the Group Study.   \n \n7.3.1.1 Purpose"},{"page":241,"startToken":68577,"endToken":68878,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nThe Definitive Planning Phase I is designed to provide Interconnection \nCustomers or MHVDC Connection Customers with a preliminary detailed \nanalysis of their Interconnection Request’s impact on the reliability of the \nTransmission System. Prior to the completion of the Preliminary System \nImpact Study, each impacted Transmission Owner shall make a non-\nbinding indication as to whether the Transmission Owner intends to self-\nfund each specific Network Upgrade and System Protection Facility \nidentified in the Preliminary System Impact Study. A Transmission \nOwner’s non-binding self-fund election will be included in the \nPreliminary System Impact Study. Upon completion of the Preliminary \nSystem Impact Study, Transmission Provider will provide a detailed \nreliability analysis, pursuant to Section 7.3.1.5, to each Interconnection \nCustomer or MHVDC Connection Customer that has an Interconnection \nRequest in the Definitive Planning Phase I.  Upon receipt of the \nPreliminary System Impact Study, the Interconnection Customer can \neither proceed to Definitive Planning Phase II or withdraw its \nInterconnection Request pursuant to Section 7.3.1.4 of this Attachment X.  \n \n7.3.1.2 Model Building and Point of Interconnection Review  \nBefore starting the preliminary Interconnection System Impact Study, \nTransmission Provider will distribute the study models to Interconnection \nCustomer or MHVDC Connection Customer and Transmission Owner.  \nInterconnection Customer and Transmission Owner may recommend \nchanges to the study model by providing a completed Interconnection \nStudy Model Review Form, Appendix 10 to the GIP within ten (10) \nBusiness Days after receipt of the study models.  Proposed changes will be \nincorporated in the study models after mutual agreement between \nInterconnection Customer or MHVDC Connection Customer, \nTransmission Owner and Transmission Provider, such agreement not to be \nunreasonably withheld.  Transmission Provider shall thereafter begin the"},{"page":242,"startToken":68878,"endToken":69170,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nPreliminary System Impact Study.  Failure of Interconnection Customer or \nMHVDC Connection Customer to provide the completed Interconnection \nStudy Model Review Form within ten (10) Business Days will result in \nwithdrawal of the Interconnection Request pursuant to Section 3.6 of this \nGIP. \n \n7.3.1.3 Scope of the Preliminary System Impact Study  \nThe Preliminary System Impact Study shall evaluate the impact of the \nproposed Interconnection Request(s) in the Definitive Planning Phase I on \nthe reliability and safety of the Transmission System.  The Preliminary \nSystem Impact Study will consider the Base Case as well as all generating \nand MHVDC facilities (and with respect to subpart iv below, any \nidentified Network Upgrades, System Protection Facilities, Distribution \nUpgrades, Generator Upgrades, Common Use Upgrades, Shared Network \nUpgrades, or, if such upgrades have been determined, upgrades on \nAffected Systems, associated with such higher queued Interconnection \nRequests) that, on the date the Preliminary System Impact Study is \ncommenced:  (i) are interconnected to the Transmission System or \nDistribution System; (ii) are interconnected or queued to interconnect to \nAffected Systems and may have an impact on the Interconnection \nRequest; (iii) have Interconnection Request is part of the same group; and \n(iv) have executed a GIA or a pending unexecuted GIA on file at FERC or \na TCA pursuant to which Transmission Provider has granted Injection \nRights. \n \nThe Preliminary System Impact Study will consist of a power flow \nanalysis.  If Transmission Provider determines in accordance with Good \nUtility Practice that any voltage stability analysis is needed, the \nPreliminary System Impact Study may include voltage stability analysis.  \nThe Preliminary System Impact Study will also include analysis needed to"},{"page":243,"startToken":69170,"endToken":69439,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ndetermine the Generating Facility’s reactive power capability required to \nmaintain the Transmission Owner’s voltage schedule and power factor \ncriteria at the Point of Interconnection. \n \nDetermination of the full scope of the Preliminary System Impact Study in \nthe Definitive Planning Phase I will be on a non-discriminatory basis per \nthe methodologies listed in the Generator Interconnection Business \nPractices Manual.  The Transmission Provider or Transmission Owner \nperforming the Preliminary System Impact Study shall complete such \nstudy within sixty-five (65) Calendar Days.  \n \nThe Preliminary System Impact Study will state the assumptions upon \nwhich it is based, state the results of the analyses, and provide the \nrequirements or potential impediments to providing the requested \nInterconnection Service, including a preliminary indication of the cost and \nlength of time that would be necessary to correct any problems identified \nin those analyses and implement the interconnection.  The Preliminary \nSystem Impact Study will provide a preliminary list of facilities (including \nInterconnection Facilities, Connection Facilities, Network Upgrades, \nGenerator Upgrades, Common Use Upgrades, and Shared Network \nUpgrades) that are required as a result of the Interconnection Request and \na preliminary non-binding good faith estimate of cost and a non-binding \ngood faith estimated time to construct.  For purposes of determining \nnecessary interconnection facilities and network upgrades, the Preliminary \nSystem Impact Study shall consider the level of Interconnection Service \nrequested by the Interconnection Customer, unless otherwise required to \nstudy the full Generating Facility Capacity due to safety or reliability \nconcerns. \n \nAt the request of Interconnection Customer or MHVDC Connection"},{"page":244,"startToken":69439,"endToken":69716,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nCustomer, or at any time Transmission Provider determines that it will not \nmeet the required time frame for completing the Preliminary System \nImpact Study, Transmission Provider shall notify Interconnection \nCustomer or MHVDC Connection Customer regarding the following: \n(i) \nSchedule status of the Preliminary System Impact Study  \n(ii) \nEstimated completion date and an explanation of the reasons why \nadditional time is required.   \n(iii) \nRevised cost estimate of study deposits with an explanation of the \nreasons why cost estimates were revised.  Interconnection \nCustomer or MHVDC Connection Customer shall then provide \nwithin thirty (30) Calendar Days of Transmission Provider’s \nnotice, an additional deposit equal to the difference between the \ninitial and revised cost estimate. Failure of Interconnection \nCustomer or MHVDC Connection Customer to provide this \nadditional deposit will result in withdrawal of the Interconnection \nRequest pursuant to Section 3.6 of this GIP.   \n \nA draft Preliminary System Impact Study will be posted for \nInterconnection Customers for a comment window.  Transmission \nProvider will address questions and comments that are submitted during \nthe comment window regarding the report before finalizing the report and \nresults.  The comment window will last for at least five (5) Business Days, \nbut no more than ten (10) Business Days. \n \n7.3.1.4 Interconnection Customer Decision Point I \nAll Interconnection Customers or MHVDC Connection Customers with \nInterconnection Requests in the Definitive Planning Phase I will pass \nthrough Interconnection Customer Decision Point I.  The Interconnection \nCustomer Decision Point I will last for fifteen (15) Business Days \nbeginning with the receipt of the Preliminary System Impact Study"},{"page":245,"startToken":69716,"endToken":70045,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nanalysis including estimated upgrades and costs, as applicable.  \nTransmission Provider shall notify all Interconnection Customers or \nMHVDC Connection Customers at the beginning of Interconnection \nCustomer Decision Point I that the Interconnection Customer or MHVDC \nConnection Customer shall have fifteen (15) Business Days to decide \nwhether it wants to proceed to the Definitive Planning Phase II or \nwithdraw its Interconnection Request.  The Transmission Provider shall \nprovide written notice to each Interconnection Customer in a Definitive \nPlanning Phase Group Study or ERAS confirming whether they are \nincluded in a JTIQ Screening Group and whether its Interconnection \nRequest has qualified for inclusion in a JTIQ Participation Group prior to \nthe beginning of Interconnection Customer Decision Point I. If the \nTransmission Provider determines that such Interconnection Request will \nbe included in a JTIQ Participation Group, the notification shall include an \nestimate of the per-MW Generator Charge for such Interconnection \nRequests based on the latest available data on JTIQ Upgrade cost, the \nPotential MW Total projected for such JTIQ Portfolio.  During \nInterconnection Customer Decision Point I, an Interconnection Customer \nor MHVDC Connection Customer may waive its right to elect the option \nto build or may defer the decision to the deadlines specified in Sections \n7.3.2.5 & 7.3.3.5; failure to provide a written response will be deemed to \nbe a deferral.  During Interconnection Customer Decision Point I, an \nInterconnection Customer or MHVDC Connection Customer may reduce \nthe size of its Interconnection Request by as much as 100 percent through \neither (1) a decrease in plant size or (2) a decrease in Interconnection \nService level (consistent with the process described in Section 3.1) \naccomplished by applying Transmission Provider-approved injection-\nlimiting equipment.  However, because NR Interconnection Service \nincludes an equivalent amount of ER Interconnection Service, a reduction \nin NRIS level will not reduce the ERIS level unless a corresponding"},{"page":246,"startToken":70045,"endToken":70346,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nreduction in ERIS level is requested. The total amount of NRIS requested \nshall not exceed the amount of ERIS requested. The required Definitive \nPlanning Phase II Milestone calculation shall be based on the DPP Phase I \nresults. If the Interconnection Customer or MHVDC Connection Customer \ndecides to withdraw its Interconnection Request during, or any time \nbefore, the end of Interconnection Customer Decision Point I, then the \nTransmission Provider will refund Interconnection Customer 40% of \nDefinitive Planning Phase I milestone (M2) and any remaining study \ndeposits pursuant to Section 7.6.  Any withdrawal during the Definitive \nPlanning Phase I, but prior to Interconnection Customer Decision Point I, \nwill neither be processed nor deemed withdrawn until Interconnection \nCustomer Decision Point I.  If an Interconnection Customer included in \nthe JTIQ Participation Group reduces the size of Interconnection Request, \nthe Transmission Provider shall determine whether such Interconnection \nRequest continues to meet the criteria for inclusion in the JTIQ \nParticipation Group and inform such Interconnection Customer of this \ndetermination not later than the start of Decision Point II.   \n \nIf the Interconnection Customer or MHVDC Connection Customer \ndecides to proceed to the Definitive Planning Phase II, then it will be \nrequired to pay Definitive Planning Phase II milestone (M3), pursuant to \nSection 7.3.1.4.1, prior to the end of Interconnection Customer Decision \nPoint I.   \n \nIf the Transmission Provider does not receive written confirmation from \nInterconnection Customer or MHVDC Connection Customer on whether it \nwants to proceed to the Definitive Planning Phase II or withdraw its \nInterconnection Request, during the Interconnection Customer Decision \nPoint I, the Transmission Provider will deem the Interconnection Request \nas withdrawn without any cure period, provide written notice to"},{"page":247,"startToken":70346,"endToken":70634,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nInterconnection Customer or MHVDC Connection Customer of the \ndeemed withdrawal and an explanation of the reasons for such deemed \nwithdrawal, and refund Interconnection Customer’s Definitive Planning \nPhase I milestone (M2) less the amount of Automatic Withdrawal Penalty \nand any remaining study deposits pursuant to Section 3.6.  If the \nTransmission Provider does not receive Definitive Planning Phase II (M3) \nmilestone payment during the Interconnection Customer Decision Point I, \nthe Transmission Provider shall provide written notice to Interconnection \nCustomer or MHVDC Connection Customer of such failure.  Upon receipt \nof such notice, the Interconnection Customer or MHVDC Connection \nCustomer shall have three (3) Business Days to provide the Definitive \nPlanning Phase II (M3) milestone payment after which period the \nTransmission Provider will deem the Interconnection Customer or \nMHVDC Connection Customers as withdrawn without any further cure \nperiod if the Definitive Planning Phase II (M3) milestone payment has not \nbeen received.  After Interconnection Customer or MHVDC Connection \nCustomer enters the Definitive Planning Phase II, the Definitive Planning \nPhase I (M2) milestone payment becomes 100% non-refundable, pursuant \nto Section 7.8 and Section 7.6.2.1.  \n \nTransmission Provider shall notify any Affected System Operator(s) of a \npotential Affected System impact caused by an Interconnection Request \nwithin ten (10) Business Days of the completion of Decision Point I. \n \n7.3.1.4.1 Definitive Planning Phase II Milestone (M3) \nCalculation. \nThe Definitive Planning Phase II milestone (M3) will be in the \nform of either cash, irrevocable letter of credit or surety bond \nreasonably acceptable to Transmission Provider.  The surety bond \nmust be issued by an insurer reasonably acceptable to"},{"page":248,"startToken":70634,"endToken":70897,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nTransmission Provider and must specify a reasonable expiration \ndate.  The Transmission Provider may establish additional \nrequirements for what constitutes a surety bond, including but not \nlimited to, duration satisfaction, demand timeframe and issuer \nrequirements through the Generator Interconnection Business \nPractices manual (BPM-015).  Interconnection Customers and \nMHVDC Connection Customers may replace cash milestone \npayments with a letter of credit or surety bond reasonably \nacceptable to Transmission Provider and may replace letters of \ncredit or surety bonds with cash.  The Definitive Planning Phase II \nmilestone (M3) will be the greater of twenty percent (20%) of the \namount of Network Upgrades, excluding JTIQ Upgrades, \nidentified in the Preliminary System Impact Study less the amount \npreviously provided at M2 or $1,000/MW. \n \n7.3.2 Definitive Planning Phase II \nThe Definitive Planning Phase II start the next day after the fifteen (15) \nBusiness Days Interconnection Customer Decision Point I window \nexpires.  \nThe Definitive Planning Phase II will include the following steps:  \n(i) \nModel Review Period (6 Business Days) \n(ii) \nRevised System Impact Study (75 Calendar Days) \n(iii) \nInterconnection Customer Decision Point II (15 Business Days) \n \nTransmission Owner shall complete the Interconnection Facilities Study \nwithin ninety (90) Calendar Days.  The Interconnection Facilities Study \nmay be initiated during Definitive Planning Phase I, in accordance with \nSection 7.3.1 of this GIP.  To the extent the Interconnection Facilities \nStudy is performed during Definitive Planning Phase II, such study shall \nbe performed concurrently with tasks (i) – (iii)."},{"page":249,"startToken":70897,"endToken":71195,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \n7.3.2.1 Purpose \nThe Definitive Planning Phase II is designed to provide Interconnection \nCustomers and MHVDC Connection Customers a revised and a detailed \nanalysis of their Interconnection Request’s impact on the reliability of the \nTransmission System after incorporating updated generation and MHVDC \nassumptions due to potential withdrawal of Interconnection Requests \nduring Definitive Planning Phase I. Except as otherwise provided in \nSection 5.8, prior to the completion of the Revised System Impact Study, \neach impacted Transmission Owner shall indicate whether the \nTransmission Owner intends to self-fund each specific Network Upgrade \nand System Protection Facility identified in the Revised System Impact \nStudy. A Transmission Owner’s self-fund election will be included in the \nRevised System Impact Study. Except as otherwise provided in Section \n5.8, the Transmission Owner’s failure to provide its indication prior to the \ncompletion of the Revised System Impact Study shall constitute a waiver \nof the Transmission Owner’s option to elect to self-fund each Network \nUpgrade and System Protection Facility identified in the Revised System \nImpact Study. Upon completion of the Revised System Impact Study, \nTransmission Provider will provide a detailed reliability analysis, pursuant \nto Section 7.3.2.5, to each Interconnection Customer or MHVDC \nConnection Customer that has an Interconnection Request in the \nDefinitive Planning Phase II.  Upon receipt of the Revised System Impact \nStudy, the Interconnection Customer or MHVDC Connection Customer \ncan either proceed to Definitive Planning Phase III or withdraw its \nInterconnection Request pursuant to Section 7.3.2.4 of this Attachment X. \n \n7.3.2.2 Model Building  \nBefore starting the Revised System Impact Study, Transmission Provider \nwill distribute the study models to Interconnection Customer or MHVDC"},{"page":250,"startToken":71195,"endToken":71508,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nConnection Customer and Transmission Owner. The Transmission \nProvider will update the study models built during Definitive Planning \nPhase I, pursuant to Section 7.3.1.2, by removing all Interconnection \nRequests that did not proceed to the Definitive Planning Phase II.  The \nTransmission Provider will distribute the revised study models to the \nTransmission Owner and Interconnection Customer or MHVDC \nConnection Customer for final review.  Any comments or corrections \nfrom the Transmission Owner or Interconnection Customer or MHVDC \nConnection Customer to the revised study models must be submitted to \nthe Transmission Provider within six (6) Business Days after receipt of the \nrevised study models.  Should the Transmission Owner or Interconnection \nCustomer or MHVDC Connection Customer fail to provide feedback on \nthe revised study models within six (6) Business Days, Transmission \nProvider will deem the models acceptable.  Transmission Provider shall \nthereafter begin the Revised System Impact Study. \n \n7.3.2.3 Scope of the Interconnection System Impact Study \nThe Revised System Impact Study shall provide an updated, detailed \nanalysis of their Interconnection Request’s impact on the reliability of the \nTransmission System after incorporating updated generation and MHVDC \nassumptions due to potential withdrawal of Interconnection Requests \nduring Definitive Planning Phase I.  The Revised System Impact Study \nshall follow the procedures as the Preliminary System Impact Study \ndescribed in Definitive Planning Phase I Section 7.3.1.3, as well as include \na short circuit analysis and stability analysis.  Transmission Provider shall \ninclude in the Revised System Impact Study an analysis of the upgrades \non Distribution System, if applicable, and Affected Systems if available.  \nIf Affected Systems analysis is not available for inclusion in the Revised \nSystem Impact Study, the Transmission Provider shall provide such \nanalysis separately when received from the applicable Affected System.  If"},{"page":251,"startToken":71508,"endToken":71792,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nTransmission Provider determines in accordance with Good Utility \nPractice that any such analyses are needed, any stability analysis \nperformed in a Revised System Impact Study may include transient \nstability, large and small signal, sub-synchronous stability, dynamic \nvoltage stability, mid- and long-term stability, voltage flicker analyses and \nexcessive neutral current.  Transmission Provider shall utilize existing \nstudies to the extent practicable in performing the Revised System Impact \nStudy.  For purposes of determining necessary Interconnection Facilities \nNetwork Upgrades, and responsibility for JTIQ Upgrades, the Revised \nSystem Impact Study shall consider the level of Interconnection Service \nrequested by the Interconnection Customer, unless otherwise required to \nstudy the full Generating Facility Capacity due to safety or reliability \nconcerns.  The Transmission Provider or Transmission Owner performing \nthe Revised System Impact Study shall complete such study within \nseventy-five (75) Calendar Days. \n \nAt the request of Interconnection Customer or MHVDC Connection \nCustomer, or at any time Transmission Provider, or Transmission Owner \nwhere a Transmission Owner is performing the study, determines that it \nwill not meet the required time frame for completing the Revised System \nImpact Study, Transmission Provider or Transmission Owner where a \nTransmission Owner is performing the study, shall notify Interconnection \nCustomer or MHVDC Connection Customer regarding the following: \n(i) \nSchedule status of the Revised System Impact Study.  \n(ii) \nEstimated completion date and an explanation of the reasons why \nadditional time is required.   \n(iii) \nRevised cost estimate of study deposits with an explanation of the \nreasons why cost estimates were revised.  Interconnection \nCustomer or MHVDC Connection Customer shall then provide \nwithin thirty (30) Calendar Days of Transmission Provider or"},{"page":252,"startToken":71792,"endToken":72078,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nTransmission Owner’s notice, an additional deposit equal to the \ndifference between the initial and revised cost estimate. Failure of \nInterconnection Customer or MHVDC Connection Customer to \nprovide this additional deposit will result in withdrawal of the \nInterconnection Request pursuant to Section 3.6 of this GIP. \n \nA draft Revised System Impact Study will be posted for Interconnection \nCustomers for a comment window.  Transmission Provider will address \nquestions and comments that are submitted during the comment window \nregarding the report before finalizing the report and results.  The comment \nwindow will last for at least five (5) Business Days, but no more than ten \n(10) Business Days. \n \n7.3.2.3.1 Additional Analysis Applicable to Interconnection \nRequests in a JTIQ Screening Group. \nIn addition to the analyses specified in Section 7.3.2.3 of this GIP, \nInterconnection Requests that: (1) are included in a JTIQ \nScreening Group (including ERAS projects not otherwise subject \nto Transmission Provider’s three-phase DPP) and not located in the \nMISO South Region as such region is defined by as the Generator \nInterconnection Business Practices Manual (BPM-015), and (2) are \npart of the JTIQ Participation Group and located in the MISO \nSouth Region: shall be subject to the following additional analysis. \na. Expanded Scope Analysis: The Transmission Provider \nshall analyze the potential impacts of Interconnection \nRequest on SPP’s transmission system  that are i) located \nwithin five (5) substations for facilities with a nominal \noperating voltage under 200kV, two (2) substations for \nfacilities with a nominal operating voltage between 200 and \n300 kV, and one (1) substation for facilities with a nominal"},{"page":253,"startToken":72078,"endToken":72347,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\noperating voltage greater than 300 kV, from any substation \nthat is part of the Transmission System; and ii) have greater \nthan or equal to ten percent (10%) distribution factor on \none or more facilities that are part of SPP’s transmission \nsystem. An Interconnection Request that qualifies for and is \nsubject to this Expanded Scope Analysis shall not be \nrequired to undergo analysis by SPP of impacts to its \ntransmission system beyond those identified in the \nExpanded Scope Analysis or the Supplemental Affected \nSystem Analysis as described in Section 7.3.2.3.1(b) of this \nGIP. \n \nIf the Transmission Provider’s Expanded Scope Analysis \nidentifies an Interconnection Request as having impacts to \nSPP’s transmission system that meets or exceed the \nforegoing distribution factor thresholds, the applicable \nInterconnection Customer(s) shall enter into an appropriate \nagreement with SPP or the applicable transmission owner \nto address such impacts in accordance with SPP’s rules and \nprocedures.  \nb. Supplemental Affected System Analysis: If the \nTransmission Provider determines that the Potential MW \nTotal, including the current Group Study, exceeds the Target \nMW value for the applicable JTIQ Portfolio, SPP shall \nperform a study to determine if any Supplemental Upgrades \nare required to address impacts to its transmission system \nfrom one or more Interconnection Customers and provide the \nresults of this analysis to the Transmission Provider prior to \nthe beginning of Decision Point II. Calculation of the \nPotential MW Total and the Supplemental Affected System \nAnalysis shall be performed in accordance with Section"},{"page":254,"startToken":72347,"endToken":72590,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n9.4.2(e)(iii) of Rate Schedule 6 (MISO-SPP JOA). \n \nIf the Supplemental Affected System Analysis indicates \nthat Supplemental Affected System Upgrades are required \nfor an Interconnection Request, then:  \n(1) the applicable Interconnection Customer(s) shall \nenter into an appropriate agreement with SPP, or the \napplicable SPP transmission owner, to address such \nimpacts in accordance with SPP’s rules and procedures; \nand \n(2) Transmission Provider shall compare the costs of \nsuch Supplemental Affected System Upgrades to the \nThreshold Charge in the manner described in Section \n9.4.2.(e)(iii)(a)(ii)(a)-(c) of Rate Schedule 6 (MISO-\nSPP JOA).  \n(3) The Transmission Provider, in coordination with \nSPP, shall establish a cost criterion in dollars per \nmegawatt ($/MW) pursuant to Section \n9.4.2.(e)(iii)(a)(ii)(a)-(c) of Rate Schedule 6 (MISO-\nSPP JOA). Where the costs assigned to an \nInterconnection Request for upgrades identified through \nthe Supplemental Affected System Analysis, excluding \ncosts identified through the Expanded Scope Analysis, \nexceed the cost criterion, the Interconnection Request \nshall be exempt from charges for the JTIQ Upgrades.  \nOtherwise, the Interconnection Request shall be \nobligated to pay a portion of the JTIQ Upgrade. \n \n7.3.2.4 Interconnection Customer Decision Point II \nAll Interconnection Customers and MHVDC Connection Customers with \nInterconnection Requests in the Definitive Planning Phase II will pass"},{"page":255,"startToken":72590,"endToken":72910,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nthrough Interconnection Customer Decision Point II.  The Interconnection \nCustomer Decision Point II will last for fifteen (15) Business Days \nbeginning with the receipt of the Revised System Impact Study analysis, \nincluding Expanded Scope Analysis where applicable.  Transmission \nProvider shall provide to Interconnection Customers any Affected System \nanalysis, including estimated upgrades and costs as applicable received \nfrom the applicable Affected System as of the date that the Transmission \nProvider is required to complete its Revised System Impact Study \nanalysis.  In the event that Affected Systems analysis has not been \nreceived by the Transmission Provider by this time, the Transmission \nProvider shall provide such analysis to Interconnection Customers \npromptly upon receipt but shall not delay the Interconnection Customer \nDecision Point or Phase III studies.  Transmission Provider shall notify all \nInterconnection Customers and MHVDC Connection Customers at the \nbeginning of Interconnection Customer Decision Point II that the \nInterconnection Customer or MHVDC Connection Customer shall have \nfifteen (15) Business Days to decide whether it wants to proceed to the \nDefinitive Planning Phase III or withdraw its Interconnection Request.  \nDuring Interconnection Customer Decision Point II, an Interconnection \nCustomer or MHVDC Connection Customer may reduce the size of its \nInterconnection Request for ERIS by as much as an additional ten percent \n(10%) compared to what was studied in DPP Phase II, through either (1) a \ndecrease in plant size or (2) a decrease in Interconnection Service level \n(consistent with the process described in Section 3.1) accomplished by \napplying Transmission Provider-approved injection-limiting equipment. \nAdditionally, an Interconnection Customer may request to reduce the \namount of NRIS by as much as 100% independent of any requested \nreduction in ERIS.  However, because NR Interconnection Service \nincludes an equivalent amount of ER Interconnection Service, a reduction \nin NRIS level will not reduce the ERIS level unless a corresponding"},{"page":256,"startToken":72910,"endToken":73197,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nreduction in ERIS level is requested.  The total amount of NRIS requested \nshall not exceed the amount of ERIS requested. The required M4 \nmilestone calculation shall be based on the DPP Phase II results.  If an \nInterconnection Customer included in the JTIQ Participation Group \nreduces the size of Interconnection Request, the Transmission Provider \nshall determine whether such Interconnection Request continues to meet \nthe criteria for inclusion in the JTIQ Participation Group and inform such \nInterconnection Customer of this determination through the Revised \nSystem Impact Study report. \n \nIf the Interconnection Customer or MHVDC Connection Customer \ndecides to withdraw its Interconnection Request during, or any time \nbefore, the end of Interconnection Customer Decision Point II, then the \nTransmission Provider will refund Interconnection Customer’s Definitive \nPlanning Phase II milestone (M3) and any remaining study deposits \npursuant to Section 7.8.  Any withdrawal during the Definitive Planning \nPhase II, but prior to Interconnection Customer Decision Point II, will \nneither be processed nor deemed withdrawn until Interconnection \nCustomer Decision Point II.  \n \nIf the Interconnection Customer or MHVDC Connection Customer \ndecides to proceed to the Definitive Planning Phase III, then it will be \nrequired to pay Definitive Planning Phase III milestone (M4), pursuant to \nSection 7.3.2.4.1, as well as provide evidence of continued Site Control \nfor the proposed Generating Facility prior to the end of Interconnection \nCustomer Decision Point II pursuant to Section 7.2.2. \n \nIf the Transmission Provider does not receive written confirmation from \nInterconnection Customer or MHVDC Connection Customer on whether it \nwants to proceed to the Definitive Planning Phase III or withdraw its"},{"page":257,"startToken":73197,"endToken":73470,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nInterconnection Request, during the Interconnection Customer Decision \nPoint II, the Transmission Provider will deem the Interconnection Request \nas withdrawn without any cure period, provide written notice to \nInterconnection Customer or MHVDC Connection Customer of the \ndeemed withdrawal and an explanation of the reasons for such deemed \nwithdrawal, and refund Interconnection Customer’s Definitive Planning \nPhase II milestone (M3) and any remaining study deposits pursuant to \nSection 7.6.  If the Transmission Provider does not receive Definitive \nPlanning Phase III (M4) milestone payment during the Interconnection \nCustomer Decision Point II, the Transmission Provider shall provide \nwritten notice to Interconnection Customer or MHVDC Connection \nCustomer of such failure.  Upon receipt of such notice, the Interconnection \nCustomer or MHVDC Connection Customer shall have three (3) Business \nDays to provide the Definitive Planning Phase III (M4) milestone payment \nafter which period the Transmission Provider will deem the \nInterconnection Customer or MHVDC Connection Customers as \nwithdrawn without any further cure period if the Definitive Planning \nPhase III milestone (M4) payment has not been received.  After \nInterconnection Customer or MHVDC Connection Customer enters the \nDefinitive Planning Phase III, the Definitive Planning Phase III (M4) \nmilestone payment becomes 100% non-refundable, pursuant to Section \n7.8. \n \nTransmission Provider shall notify Affected System Operator(s) of a \npotential Affected System impact caused by an Interconnection Request \nwithin ten (10) Business Days of the completion of Decision Point II.  \n \n7.3.2.4.1 Definitive Planning Phase III Milestone (M4) \nCalculation. \nThe Definitive Planning Phase III milestone (M4) will be in the"},{"page":258,"startToken":73470,"endToken":73746,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nform of either cash, irrevocable letter of credit or surety bond \nreasonably acceptable to Transmission Provider.  The surety bond \nmust be issued by an insurer reasonably acceptable to \nTransmission Provider and must specify a reasonable expiration \ndate.  The Transmission Provider may establish additional \nrequirements for what constitutes a surety bond, including but not \nlimited to, duration satisfaction, demand timeframe and issuer \nrequirements through the Generator Interconnection Business \nPractices manual (BPM-015).  Interconnection Customers and \nMHVDC Connection Customers may replace cash milestone \npayments with a letter of credit or surety bonds and may replace \nletters of credit or surety bond with cash.  The Definitive Planning \nPhase III milestone (M4) will be thirty percent (30%) of the \namount of Network Upgrades identified in the Revised System \nImpact Study, not including costs associated with JTIQ Upgrades, \nless any payments made as M2 and M3, but in no event shall the \nM4 be less than zero dollars. \n \n7.3.2.4.2 True-down of Milestone Payments. \nWithin ten (10) Business Days from the start of Definitive \nPlanning Phase III, Transmission Provider shall notify the \nInterconnection Customer if the total posted M3 and M4 milestone \npayments (i.e., the sum of the M3 and M4 payments) for the \nInterconnection Request exceed thirty percent (30%) of the total \nNetwork Upgrade cost assigned to such Interconnection Request in \nthe Revised System Impact Study, excluding the JTIQ Generator \nCharge. Transmission Provider shall refund such excess amounts \nto the Interconnection Customer as soon as practicable.   \n \n7.3.2.5 Scope of Interconnection Facilities Study."},{"page":259,"startToken":73746,"endToken":74096,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nThe first portion of the Interconnection Facilities Study focusing on the \nInterconnection Facilities or the Connection Facilities for the project will \nstart no later than the first day of Definitive Planning Phase II in \naccordance with Section 7.3.2 of this GIP.  This portion of the \nInterconnection Facilities Study will identify estimates for cost and the \ntime required to construct the Interconnection Facilities or the Connection \nFacilities, including cost estimates that the Transmission Owner will \nimpose if the Interconnection Customer elects to build (e.g. oversight or \nmanagement costs).  Within 10 Business Days of the Interconnection \nCustomer’s receipt of the draft Interconnection Facilities Study, unless the \nInterconnection Customer has waived its option to build under Section \n7.3.1.4, the Interconnection Customer shall either elect the option to build \nor waive the option to build.  If the Interconnection Customer elects the \noption to build, at the same time it makes that election, it must also supply \ncompleted cost estimates for Exhibits A7 and A8 as described in Business \nPractices Manual 15 for the Interconnection Facilities and Stand-Alone \nNetwork Upgrades that it has elected to build.  Failure to provide a written \nresponse or a failure to provide the required cost estimates will be deemed \nto be a waiver of the Interconnection Customer’s option to build.  Nothing \nin this Section shall be interpreted to prohibit an Interconnection Customer \nfrom, with Transmission Owner’s consent, from waiving its option to \nbuild at a later time prior to GIA execution, but an Interconnection \nCustomer is not entitled to reverse its waiver.  The Transmission Owner to \nwhose facilities Interconnection Requests propose to connect or whose \nfacilities are impacted by an Interconnection Request shall complete this \nportion of the Interconnection Facilities Study within ninety (90) Calendar \nDays.  The Transmission Provider or applicable Transmission Owner shall \nperform the detailed analysis.  The Interconnection Facilities Study will \nalso identify any potential control equipment for (1) requests for \nInterconnection Service that are lower than the Generating Facility"},{"page":260,"startToken":74096,"endToken":74359,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nCapacity, and/or (2) requests to study a Generating Facility that includes at \nleast one electric storage resource using operating assumptions according \nto the Transmission Provider’s fuel dispatch methodology in the manner \nspecified by the Generator Interconnection Business Practices Manual \n(BPM-015). \n \n7.3.3 Definitive Planning Phase III \nThe Definitive Planning Phase III will start the day after the expiration of the \nfifteen (15) Business Day Interconnection Customer Decision Point II. \n \nThe Definitive Planning Phase III will include the following steps:  \n(i) \nModel Review (6 Business Days) \n(ii) \nFinal System Impact Study (50 Calendar Days) \n(iii) \nInterconnection Facilities Study for Network Upgrades (90 Calendar \nDays) \n \n7.3.3.1 Purpose \nThe Definitive Planning Phase III is designed to provide Interconnection \nCustomers and MHVDC Connection Customers a final, detailed analysis \nof their Interconnection Request’s impact on the reliability of the \nTransmission System after incorporating updated generation and MHVDC \nassumptions due to potential withdrawal of Interconnection Requests \nduring Definitive Planning Phase II. For each specific Network Upgrade \nand System Protection Facility that the Transmission Owner did not elect \nto self-fund as a part of the Revised System Impact Study, the \nTransmission Owner shall not be permitted to further revise its election \nafter the completion of the Revised System Impact Study. For each \nspecific Network Upgrade and System Protection Facility that the \nTransmission Owner elected to self-fund as a part of the Revised System \nImpact Study, each impacted Transmission Owner shall confirm or revise"},{"page":261,"startToken":74359,"endToken":74673,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nits self-fund election prior to the completion of the Final System Impact \nStudy. In the event that a new Network Upgrade or System Protection \nFacility is identified in the Final System Impact Study that had not \npreviously been identified in the Revised System Impact Study, each \nimpacted Transmission Owner shall make a binding indication as to \nwhether the Transmission Owner intends to self-fund the new Network \nUpgrade and System Protection Facility prior to the completion of the \nFinal System Impact Study. A Transmission Owner’s self-fund election \nwill be included in the Final System Impact Study. Except as otherwise \nprovided in Section 5.8, a Transmission Owner’s failure to provide its \nself-fund election prior to the completion of the Final System Impact \nStudy shall constitute a waiver of the Transmission Owner’s option to \nself-fund each Network Upgrade and System Protection Facility identified \nin the Final System Impact Study. Upon completion of the Final System \nImpact Study, the Transmission Owner(s) to whose facilities the \nInterconnection Customer or MHVDC Connection Customer proposes to \ninterconnect will perform Facilities Study pursuant to Section 7.3.3.5.  \nUpon completion of the Interconnection Facilities Study, Transmission \nProvider will tender a draft pro forma Generator Interconnection \nAgreement to the Interconnection Customer and Transmission Owner.   \n \n7.3.3.2 Model Building \nBefore starting the Final System Impact Study, Transmission Provider will \ndistribute the study models to Interconnection Customer or MHVDC \nConnection Customer and Transmission Owner. The Transmission \nProvider will update the study models built during Definitive Planning \nPhase II, pursuant to Section 7.3.2.2, by removing all Interconnection \nRequests that did not proceed to the Definitive Planning Phase III.  The \nTransmission Provider will distribute the revised study models to the \nTransmission Owner and Interconnection Customer or MHVDC"},{"page":262,"startToken":74673,"endToken":74984,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nConnection Customer for final review.  Any comments or corrections \nfrom the Transmission Owner or Interconnection Customer or MHVDC \nConnection Customer to the revised study models must be submitted to \nthe Transmission Provider within six (6) Business Days after receipt of the \nrevised study models.  Should the Transmission Owner or Interconnection \nCustomer or MHVDC Connection Customer fail to provide feedback on \nthe revised study models within six (6) Business Days, Transmission \nProvider will deem the models acceptable.  Transmission Provider shall \nthereafter begin the Final System Impact Study.   \n \n7.3.3.3 Scope of the Final System Impact Study \nThe Final System Impact Study shall provide a final, detailed analysis of \ntheir Interconnection Request’s impact on the reliability of the \nTransmission System after incorporating updated generation assumptions \ndue to potential withdrawal of Interconnection Requests during Definitive \nPlanning Phase II.  The Final System Impact Study shall follow the \nprocedures as the Revised System Impact Study described in Definitive \nPlanning Phase II Section 7.3.2.3 and additional JTIQ analysis described \nin Section 7.3.2.3.1, where applicable.  Transmission Provider, or \nTransmission Owner if a Transmission Owner is conducting the study, \nshall include in the Final System Impact Study any Affected System \nresults and information regarding network upgrades provided in the \nAffected System’s study report, if available from the applicable Affected \nSystem. If the Affected System’s study report is not available for inclusion \nin the Final System Impact Study, the Transmission Provider shall provide \nsuch analysis separately when received from the applicable Affected \nSystem.  For purposes of determining necessary Interconnection Facilities \nand Network Upgrades, the Final System Impact Study shall consider the \nlevel of Interconnection Service requested by the Interconnection \nCustomer, unless otherwise required to study the full Generating Facility"},{"page":263,"startToken":74984,"endToken":75247,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nCapacity due to safety or reliability concerns.  Transmission Provider shall \nutilize existing studies to the extent practicable in performing the Final \nSystem Impact Study. \n \nIf requested by the Interconnection Customer, the Transmission Provider \nor Transmission Owner performing the Preliminary, Revised, and Final \nSystem Impact Study shall evaluate, as part of the applicable System \nImpact Study, the use of static synchronous compensators, static VAR \ncompensators, advanced power flow control devices, transmission \nswitching, synchronous condensers, voltage source converters, advanced \nconductors, and tower lifting. The requesting Interconnection Customer \nshall timely provide Transmission Provider with the requisite model \ninformation to allow Transmission Provider to evaluate the requested \ntechnology.  The Transmission Provider or applicable Transmission \nOwner shall evaluate each requested alternative transmission technology \nand determine whether the above technologies should be used, consistent \nwith Good Utility Practice, Applicable Reliability Standards, and \nApplicable Laws and Regulations, as an alternative to traditional network \nupgrades.  Transmission Provider shall include an explanation of the \nresults of the Transmission Provider’s evaluation for each technology in \nthe applicable System Impact Study report. The Transmission Provider or \nTransmission Owner’s evaluation will be completed pursuant to the \nprovisions set forth in the Generator Interconnection Business Practices \nManual. \nThe Final System Impact Study will start the day after the completion of \nthe Model Review in the Definitive Planning Phase III. Transmission \nProvider, or Transmission Owner if a Transmission Owner is performing \nthe study, shall complete the Final System Impact Study within fifty (50) \nCalendar Days."},{"page":264,"startToken":75247,"endToken":75527,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nAt the request of Interconnection Customer or MHVDC Connection \nCustomer, or at any time Transmission Provider determines that it will not \nmeet the required time frame for completing the Final System Impact \nStudy, Transmission Provider shall notify Interconnection Customer or \nMHVDC Connection Customer regarding the following: \n(i) \nSchedule status of the Final System Impact Study.   \n(ii) \nEstimated completion date and an explanation of the reasons why \nadditional time is required.   \n(iii) \nRevised cost estimate of study deposits with an explanation of the \nreasons why cost estimates were revised.  Interconnection \nCustomer or MHVDC Connection Customer shall then provide \nwithin thirty (30) Calendar Days of Transmission Provider’s \nnotice, an additional deposit equal to the difference between the \ninitial and revised cost estimate. Failure of Interconnection \nCustomer or MHVDC Connection Customer to provide this \nadditional deposit will result in withdrawal of the Interconnection \nRequest pursuant to Section 3.6 of this GIP.   \n \nA draft Final System Impact Study will be posted for Interconnection \nCustomers for a comment window.  Transmission Provider will address \nquestions and comments that are submitted during the comment window \nregarding the report before finalizing the report and results. The comment \nwindow will last for at least five (5) Business Days, but no more than ten \n(10) Business Days. \n \n7.3.3.4 Scope of Interconnection Facilities Study. \nThe Transmission Owner to whose facilities Interconnection Requests \npropose to connect or whose facilities are impacted by an Interconnection \nRequest may begin the second portion of the Interconnection Facilities \nStudy for that Network Upgrade prior to the completion of the Final"},{"page":265,"startToken":75527,"endToken":75827,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nSystem Impact Study. The Interconnection Customer(s) responsible for a \nNetwork Upgrade may request that the second portion of the \nInterconnection Facilities Study begin after the completion of \nInterconnection Customer Decision Point II and prior to the completion of \nthe Final System Impact Study. The Transmission Owner to whose \nfacilities Interconnection Requests propose to connect or whose facilities \nare impacted by an Interconnection Request Transmission Owner shall \nstart the second portion of the Interconnection Facilities Study no later \nthan the day following the posting of the Final System Impact Study report \nand, if applicable, the Affected System’s final study report, provided that \nTransmission Provider has submitted to the applicable Transmission \nOwner(s) an executed statement of work and purchase order.  This phase \nwill identify estimates for the cost and time required to build necessary \nNetwork Upgrades that are identified in the Final System Impact Study.  \nThe Transmission Owner conducting the study shall complete this portion \nof the Interconnection Facilities Study within ninety (90) Calendar Days \nfrom the start date of the Interconnection Facilities Study. \n \nThe Interconnection Facilities Study, in its entirety, shall specify and \nestimate the cost of the required equipment, engineering, procurement and \nconstruction work needed to implement the Network Upgrades and \nInterconnection Facilities or Connection Facilities identified in the Final \nSystem Impact Study in accordance with Good Utility Practice to \nphysically and electrically connect the Interconnection Facilities or the \nConnection Facilities to the Transmission or Distribution System, as \napplicable, as well as that equipment, to the extent known and available in \naccordance with Section 3.5 of these GIP, required by Affected Systems to \naccommodate the interconnection of the Generating Facility or the \nMHVDC Transmission Line."},{"page":266,"startToken":75827,"endToken":76081,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nThe Interconnection Facilities Study shall also identify the electrical \nswitching configuration of the connection equipment, including, without \nlimitation: the transformer, switchgear, meters, and other station \nequipment; the nature and estimated cost of any Transmission Owner’s \nInterconnection Facilities or Connection Facilities and Network Upgrades, \nDistribution Upgrades, Generator Upgrades, Common Use Upgrades, and \nto the extent known and available in accordance with Section 3.5 of the \nGIP, upgrades on Affected Systems necessary to accomplish the \ninterconnection; and an estimate of the time required to complete the \nconstruction and installation of such facilities.  The Interconnection \nFacilities Study will also identify any potential control equipment for \nrequests for Interconnection Service that are lower than the Generating \nFacility Capacity. \n \nThe Interconnection Customer shall enter into a facilities construction \nagreement with any neighboring transmission provider for network \nupgrades identified in the Affected System analysis. \n \n7.3.3.5 Interconnection Facilities Study Procedures. \nTransmission Provider shall coordinate the Interconnection Facilities \nStudy with any Affected System pursuant to Section 3.5 of this GIP.  \nTransmission Provider and applicable Transmission Owner shall utilize \nexisting studies to the extent practicable in performing the Interconnection \nFacilities Study.  The Interconnection Facilities Study for an \nInterconnection Request shall be typically performed as a Group Study \nwith respect to Common Use Upgrades and/or Interconnection Facilities \nor Connection Facilities common to more than one Interconnection \nRequest.   \n \nAt the request of Interconnection Customer or MHVDC Connection"},{"page":267,"startToken":76081,"endToken":76383,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nCustomer or at any time that the Transmission Provider or applicable \nTransmission Owner determines that it will not meet the required time \nframe for completing the Interconnection Facilities Study, Transmission \nProvider shall notify Interconnection Customer or MHVDC Connection \nCustomer as to the schedule status of the Interconnection Facilities Study.  \nIf the applicable Transmission Owner is unable to complete the \nInterconnection Facilities Study within the time required, such \nTransmission Owner shall notify Interconnection Customer and provide an \nestimated completion date and an explanation of the reasons why \nadditional time is required.  If the applicable Transmission Owner is \nunable to complete the Interconnection Facilities Study with the study \ndeposit provided by Interconnection Customer or MHVDC Connection \nCustomer, Transmission Provider shall notify Interconnection Customer or \nMHVDC Connection Customer and provide a revised cost estimate with \nan explanation of the reasons why.  Interconnection Customer or MHVDC \nConnection Customer shall then provide within fifteen (15) Calendar Days \nof Transmission Provider’s notice, an additional deposit equal to the \ndifference between the initial and revised cost estimate.  Failure of \nInterconnection Customer or MHVDC Connection Customer to provide \nthis additional deposit will result in withdrawal of the Interconnection \nRequest pursuant to Section 3.6 of this GIP.  \n \nTransmission Owner shall provide to Transmission Provider a draft \nInterconnection Facilities report at the conclusion of the Interconnection \nFacilities Study.  A draft Interconnection Facilities Study will be posted by \nTransmission Provider for Interconnection Customers for a comment \nwindow.  Transmission Provider and Transmission Owner will address \nquestions and comments that are submitted during the comment window \nregarding the report before finalizing the report and results.  The comment \nwindow will last for at least five (5) Business Days, but no more than ten"},{"page":268,"startToken":76383,"endToken":76703,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n(10) Business Days. \n \nInterconnection Customer or MHVDC Connection Customer and \nTransmission Owner may, within fifteen (15) Calendar Days after receipt \nof the draft Interconnection Facilities report and supporting \ndocumentation, provide written comments to Transmission Provider, \nwhich Transmission Provider shall include in the final Interconnection \nFacilities report.  If the draft Interconnection Facilities report contains a \nStand-Alone Network Upgrade, unless the Interconnection Customer has \nwaived its option to build under Section 7.3.1.4, the cost estimate shall \ninclude the cost that the Transmission Owner will impose if the \nInterconnection Customer elects to build (e.g. oversight or management \ncosts).  Unless the Interconnection Customer has waived its option to build \nunder Section 7.3.1.4, the Interconnection Customer shall either elect the \noption to build or waive the option to build Stand-Alone Network \nUpgrades identified in the second portion of the Interconnection Facilities \nStudy within 15 calendar days of receiving the draft Interconnection \nFacilities report.  If the Interconnection Customer elects the option to \nbuild, at the same time it makes that election, it must also supply \ncompleted cost estimates for Exhibits A7 and A8 as described in the \nBusiness Practices Manual 15 for the Stand-Alone Network Upgrades that \nit has elected to build.  Failure to provide a written response or a failure to \nprovide the required cost estimates will be deemed to be a waiver of the \nInterconnection Customer’s option to build.  Nothing in this Section shall \nbe interpreted to prohibit an Interconnection Customer, with Transmission \nOwner’s consent, from waiving its option to build at a later time prior to \nGIA execution, but an Interconnection Customer is not entitled to reverse \nits waiver.  If Interconnection Customer elects to build, Transmission \nProvider shall include that election in the final Interconnection Facilities \nreport.  Transmission Provider shall issue the final Interconnection"},{"page":269,"startToken":76703,"endToken":76972,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nFacilities report and supporting documentation within ten (10) Calendar \nDays of receiving the Interconnection Customer’s or the MHVDC \nConnection Customer’s comments or promptly upon receiving \nInterconnection Customer’s or the MHVDC Connection Customer’s \nstatement that it will not provide comments.  Transmission Provider may \nreasonably extend such fifteen-day period upon notice to Interconnection \nCustomer or MHVDC Connection Customer if the Interconnection \nCustomer’s or the MHVDC Connection Customer’s comments require \nTransmission Provider or the applicable Transmission Owner to perform \nadditional analyses or make other significant revisions prior to the \nissuance of the final Interconnection Facilities Report.  Upon request, \nTransmission Provider or the applicable Transmission Owner shall \nprovide Interconnection Customer or MHVDC Connection Customer \nsupporting documentation, work papers, and databases or data developed \nin the preparation of the Interconnection Facilities Study, subject to \nconfidentiality arrangements consistent with Section 13.1.  \nInterconnection Customer or MHVDC Connection Customer shall \nmaintain as confidential any information that is provided by Transmission \nProvider or the applicable Transmission Owner and identified as Critical \nEnergy Infrastructure Information (CEII), as that term is defined in \n18 C.F.R. Section 388.113(c).  Such confidentiality will be maintained in \naccordance with Section 13.1. \n \n7.4 \nMeeting with Transmission Provider. \nWithin ten (10) Business Days of providing draft GIA or TCA appendices and, as \napplicable, associated draft appendices for the related FCA(s) and/or MPFCA(s) \nand supporting documentation to Interconnection Customer, Transmission Owner \nand Interconnection Customer may meet to discuss the results of the \nInterconnection Facilities Study."},{"page":270,"startToken":76972,"endToken":77274,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n7.5 \nInterconnection Study Restudy. \nIf a restudy of any Interconnection Study is required because an Interconnection \nRequest withdraws or is deemed to have withdrawn prior to all GIAs, TCAs, \nFCAs, and/or MPFCAs, as applicable, for each respective Definitive Planning \nPhase cycle have been executed or filed unexecuted with the Federal Energy \nRegulatory Commission, Transmission Provider shall provide notice of restudy as \nnecessary.  The Transmission Provider’s notice shall include a summary of a \npreliminary analysis supporting the need for an Interconnection Study restudy, an \nexplanation of why an Interconnection Study restudy is required and a good faith \nestimate of the cost to perform the Interconnection Study restudy.  The \nInterconnection Study restudy shall be performed subject to the GIP and Business \nPractices Manuals in effect at the time notice is provided by Transmission \nProvider.  Interconnection Customer or MHVDC Connection Customer shall \nnotify Transmission Provider within five (5) Business Days whether \nInterconnection Customer or MHVDC Connection Customer wishes to proceed \nwith the Interconnection Study restudy or withdraw its Interconnection Request.  \nTransmission Provider shall deem Interconnection Customer’s or MHVDC \nConnection Customer’s failure to notify Transmission Provider to proceed to \nperform the Interconnection Study restudy as Interconnection Customer’s or \nMHVDC Connection Customer’s withdrawal of its Interconnection Request in \naccordance with Section 3.6 of this GIP.  Transmission Provider or the applicable \nTransmission Owner shall complete such Interconnection Study restudy no later \nthan sixty (60) Calendar Days from the date of notice.  Transmission Provider \nmay elect to perform any Interconnection Study restudy of Network Upgrades \ncommon to more than one Interconnection Request as a Group Study.   \n \n7.6 \nRefunds \n \n7.6.1 Refunds of Study Deposits \nTransmission Provider shall charge and Interconnection Customer or"},{"page":271,"startToken":77274,"endToken":77546,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nMHVDC Connection Customer shall pay the actual costs of the \nInterconnection Studies.  Any difference between the study deposit and \nthe actual cost of the applicable Interconnection Study shall be paid by or \nrefunded to, except as otherwise provided herein, the Interconnection \nCustomer. Any invoices for Interconnection Studies shall include a \ndetailed and itemized accounting of the cost of each Interconnection \nStudy.  Interconnection Customer or MHVDC Connection Customer shall \npay any such undisputed costs within thirty (30) Calendar Days of receipt \nof an invoice.  Transmission Provider shall not be obligated to perform or \ncontinue to perform any studies unless Interconnection Customer or \nMHVDC Connection Customer has paid all undisputed amounts in \ncompliance herewith.   \n \nAll charges associated with performing Interconnection Studies, during all \nthree phases of the Definitive Planning Phase, are the responsibility of \nInterconnection Customers or MHVDC Connection Customers with active \nInterconnection Requests during each respective Definitive Planning \nPhase.   \n \nIf the Interconnection Customer or MHVDC Connection Customer \nwithdraws its Interconnection Request any time before the end of \nInterconnection Customer Decision Point I, the Transmission Provider \nwill refund to the Interconnection Customer or MHVDC Connection \nCustomer any unused portion of the study deposits.  Any Interconnection \nCustomer or MHVDC Connection Customer that withdraws its \nInterconnection Request, or is deemed to be withdrawn, during Definitive \nPlanning Phase I but before Interconnection Customer Decision Point I is \nresponsible for its pro rata portion of the group Interconnection Study \ncosts for Definitive Planning Phase I.  Any Interconnection Customer or \nMHVDC Connection Customer that withdraws its Interconnection"},{"page":272,"startToken":77546,"endToken":77837,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nRequest, or is deemed to be withdrawn, prior to the expiration of \nInterconnection Customer Decision Point I will not be responsible to fund \nany Interconnection Studies that take place during or after the start of the \nDefinitive Planning Phase II of the GIP.  \n \nIf the Interconnection Customer or MHVDC Connection Customer \nwithdraws its Interconnection Request any time after Interconnection \nCustomer Decision Point I, but before the expiration of the \nInterconnection Customer Decision Point II, then the Transmission \nProvider will refund to the Interconnection Customer or MHVDC \nConnection Customer any unused portion of the study deposits.  Any \nInterconnection Customer or MHVDC Connection Customer that \nwithdraws its Interconnection Request, or is deemed to be withdrawn, \nduring Definitive Planning Phase II but before Interconnection Customer \nDecision Point II is responsible for its pro rata portion of the group \nInterconnection Study costs for Definitive Planning Phase II.  Any \nInterconnection Customer or MHVDC Connection Customer that \nwithdraws its Interconnection Request prior to the expiration of \nInterconnection Customer Decision Point II will not be responsible to fund \nany Interconnection Studies that take place during or after the start of \nDefinitive Planning Phase III of the GIP. \n \nIf the Interconnection Customer or MHVDC Connection Customer \nwithdraws its Interconnection Request any time during Definitive \nPlanning Phase III of the GIP, and if the Transmission Provider \ndetermines that an Interconnection Study restudy is required, then the \nwithdrawing Interconnection Customer or MHVDC Connection Customer \nwill be responsible to fund all such restudies in Definitive Planning Phase \nIII of the GIP, up to the amount of that Interconnection Customer’s total \nstudy deposit.  However, if the Transmission Provider determines that no"},{"page":273,"startToken":77837,"endToken":78150,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nInterconnection Study restudy is required due to the withdrawal of \nInterconnection Customer’s or MHVDC Connection Customer’s \nInterconnection Request, then the withdrawing Interconnection Customer \nor MHVDC Connection Customer will not be responsible to fund any \nfurther Interconnection Studies during Definitive Planning Phase III of the \nGIP and the Transmission Provider shall refund to the Interconnection \nCustomer or MHVDC Connection Customer any unused portion of the \nstudy deposit paid to enter the Definitive Planning Phase. \n \n7.6.2 Refunds of Definitive Planning Phase Milestones (M2, M3, M4) \n \n7.6.2.1 Refunds of Definitive Planning Phase entry milestone (M2) \nInterconnection Customers and MHVDC Connection Customers are \neligible to receive one hundred percent (100%) refund of the Definitive \nPlanning Phase entry milestone (M2) only when the Interconnection \nRequest is withdrawn or deemed withdrawn prior to the start of Definitive \nPlanning Phase I or when Transmission Provider has completed review of \nSite Control sufficiency pursuant to Section 7.2.1.3 of the GIP and the \nInterconnection Request is deemed withdrawn due to Site Control \ndeficiencies.  Interconnection Customers and MHVDC Connection \nCustomers are eligible to receive refund of forty percent (40%) of the \nDefinitive Planning Phase entry milestone (M2) only when the \nInterconnection Request is withdrawn or deemed withdrawn during \nDefinitive Planning Phase I or at any time before or at the end of \nInterconnection Customer Decision Point I.  The remaining 60% of the \nDefinitive Planning Phase entry milestone (M2) becomes non-refundable \npursuant to Section 7.6.2.1.1 and 7.8 of the GIP.  If the Interconnection \nRequest is withdrawn any time after the Interconnection Customer \nDecision Point I, then the entire Definitive Planning Phase entry milestone \n(M2) becomes non-refundable pursuant to Section 7.6.2.1.1 and 7.8 of the"},{"page":274,"startToken":78150,"endToken":78380,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nGIP. \n \n7.6.2.1.1 Calculation of the Automatic Withdrawal Penalty \nInterconnection Customer shall be subject to an Automatic \nWithdrawal Penalty if it withdraws its Interconnection Request, or \nthe Interconnection request is deemed withdrawn pursuant to \nsection 7.2.1.3 or section 3.6 of the GIP.  Interconnection \nCustomer shall not be subject to an Automatic Withdrawal Penalty \nif it withdraws its Interconnection Request, or the Interconnection \nRequest is deemed withdrawn prior to commencement of \nDefinitive Planning Phase I. \n \n(a) If Interconnection Request is withdrawn or deemed withdrawn \nduring Definitive Planning Phase I or at any time before or at \nthe end of Interconnection Customer Decision Point I, the \nInterconnection Customer shall be charged ten percent (10%) \nof the Definitive Planning Phase entry milestone (M2). \n \n(b) If the Interconnection Request is withdrawn or deemed \nwithdrawn after Interconnection Customer Decision Point I and \nbefore or at the end of Interconnection Customer Decision \nPoint II, the Interconnection Customer shall be charged thirty-\nfive percent (35%) of the Definitive Planning Phase entry \nmilestone (M2). \n \n(c) If the Interconnection Request is withdrawn or deemed \nwithdrawn after Interconnection Customer Decision Point II \nand before the end of the Definitive Planning Phase III, the \nInterconnection Customer shall be charged seventy five percent"},{"page":275,"startToken":78380,"endToken":78635,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n(75%) of the Definitive Planning Phase entry milestone (M2). \n \n(d) If the Interconnection Request is withdrawn or deemed \nwithdrawn after start of the Generator Interconnection \nAgreement (GIA) negotiations (within 5 days of posting of the \nFinal System Impact Study report) the Interconnection \nCustomer shall be charged one hundred percent (100%) of the \nDefinitive Planning Phase entry milestone (M2). \n \n7.6.2.2 Refund of Definitive Planning Phase II milestone (M3) \nInterconnection Customers and MHVDC Connection Customers are \neligible to receive one hundred percent (100%) refund of the Definitive \nPlanning Phase II milestone (M3) only when the Interconnection Request \nis withdrawn or deemed withdrawn after Interconnection Customer \nDecision Point I and before or at the end of Interconnection Customer \nDecision Point II.  If the Interconnection Request is withdrawn any time \nafter the end of Interconnection Customer Decision Point II, then the \nDefinitive Planning Phase II milestone (M3) becomes non-refundable \npursuant to Section 7.8 of the GIP. \n \n7.6.2.3 Refund of Definitive Planning Phase II milestone (M4) \nIf the Interconnection Customer or MHVDC Connection Customer \ndecides to withdraw its Interconnection Request any time after entering \nthe Definitive Planning Phase III, then the Definitive Planning Phase III \nmilestone (M4) becomes non-refundable pursuant to Section 7.8 of the \nGIP. \n \n7.6.2.4 Withdrawal and refund due to increase in Network Upgrade \ncosts \nMilestone payments will be refunded in the event the Interconnection"},{"page":276,"startToken":78635,"endToken":78919,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nCustomer or MHVDC Connection Customer withdraws because the total \nNetwork Upgrade cost estimates in the Revised System Impact Study \nincreased by more than fifty percent (50%) and more than $10,000 per \nMW over the Preliminary System Impact Study as a result of \nTransmission Provider, or Transmission Owner error that is identified \nprior to the finalization of the revised System Impact Study report.  To \nobtain a refund, Interconnection Customer must withdraw at the end of \nInterconnection Customer Decision Point II. \n \nMilestone payments will be refunded in the event the Interconnection \nCustomer or MHVDC Connection Customer withdraws because the total \nNetwork Upgrade cost estimates in the Final System Impact Study \nincreased by more than thirty-five percent (35%) and more than $10,000 \nper MW over the Revised System Impact Study as a result of \nTransmission Provider, Affected System (to the extent available) or \nTransmission Owner error that is identified prior to the finalization of the \nFinal System Impact Study report.  To obtain a refund, Interconnection \nCustomer must withdraw within five Business Days of posting the results \nof the Final System Impact Study. \n \nMilestone payments less Automatic Withdrawal Penalty amount will also \nbe refunded in the event the Interconnection Customer or MHVDC \nConnection Customer withdraws and the total Network Upgrade cost \nestimates in the Interconnection Facilities Study increased by more than \nthirty-five percent (35%) and more than $10,000 per MW over the \nNetwork Upgrade cost estimates in the Final System Impact Study.  To \nobtain a refund, Interconnection Customer must withdraw within five \nBusiness Days of posting the results of the Interconnection Facilities \nStudy."},{"page":277,"startToken":78919,"endToken":79219,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nMilestone payments less Automatic Withdrawal Penalty amount will also \nbe refunded in the event the Interconnection Customer or MHVDC \nConnection Customer withdraws within the later of five (5) Business Days \nof the results of the study or at the end of an Interconnection Customer \nDecision Point, if applicable, of results indicating designated increases in \nestimated upgrade costs across the following intervals: \n1. DPP Phase I to DPP Phase II \na. An increase in MISO Network Upgrade costs from Phase I to \nPhase II of  at least 50%, and more than $10,000 per MW from \nthe Preliminary SIS to the Revised SIS. \n2. DPP Phase II to DPP Phase III \na. An increase in the combined Network Upgrade and Affected \nSystem costs from Phase II to the start of GIA negotiation of \nthirty-five percent (35%) and more than $15,000 per MW from \nthe Revised SIS (including and Affected Systems results \nreceived during DPP Phase II) to any Final SIS and Affected \nSystems results received prior to the start of GIA negotiations. \n \n7.7 \nApplicability of Definitive Planning Phase Milestone Payments (M2, M3, and \nM4) to Generator Interconnection Agreement Initial Payment, Transmission \nConnection Agreement Initial Payment, or construction agreement security \n \nIn the event the Interconnection Customer has elected to make its milestones in \nthe form of cash, Transmission Provider will transfer the Definitive Planning \nPhase milestones to the appropriate Transmission Owner to satisfy the initial \npayment requirement of the Generator Interconnection Agreement, TCA or other \napplicable service agreement within forty-five (45) Calendar Days of the effective \ndate of the Generator Interconnection Agreement, TCA or other applicable \nservice agreement.   \n \nProvided that the Interconnection Customer has not requested withdrawal, is"},{"page":278,"startToken":79219,"endToken":79510,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ndeemed withdrawn, or is pending termination of its applicable service agreement, \nthe Transmission Provider shall refund Milestone cash payments exceeding the \ninitial payment requirement to the Interconnection Customer, MHVDC \nConnection Customer or the applicable Transmission Owner upon \nInterconnection Customer’s or MHVDC Connection Customer’s request with \nTransmission Owner’s consent, within forty-five (45) Calendar Days of the later \neffective date of the Generator Interconnection Agreement, TCA, other applicable \nservice agreements or construction agreements.  In the event the milestone \npayments are less than the initial payment requirement, the Interconnection \nCustomer or MHVDC Connection Customer shall be responsible for the \nremaining payment to the Transmission Owner.  \n \nIn the event milestone payments were provided pursuant to an irrevocable letter of \ncredit or surety bond such letter of credit or surety bond shall be released upon \nsatisfaction of the later initial payment requirement in the Generator \nInterconnection Agreement, TCA, other applicable service agreements or \nconstruction agreements, and with Transmission Owner’s consent, provided that \nthe Interconnection Customer has not requested withdrawal, is deemed \nwithdrawn, or is pending termination of its applicable service agreement. \n \n7.8 \nUse of Definitive Planning Phase Entry At Risk Milestone Payments (M2, M3 \nand M4) or Payments of Withdrawn Projects \n \nUpon completion of the Definitive Planning Phase III and after any subsequent \nrestudy performed after Definitive Planning Phase III, Transmission Provider will \ndetermine the financial impact of withdrawn projects on each remaining \nInterconnection Request in the same cycle.  This financial impact will be \ndetermined using the following two-step method. \n \nStep 1: Transmission Provider first determines the cost of upgrades that are \nshifted from withdrawn projects to remaining projects that were co-participants in"},{"page":279,"startToken":79510,"endToken":79782,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nCommon Use Upgrades or Shared Network Upgrades. \n \nFor projects that withdrew before the completion of Interconnection Customer \nDecision Point I with at-risk milestones, the Transmission provider will \ndetermine the costs that were shifted from withdrawn projects to remaining \nprojects that were co-participants in Common Use Upgrades or Shared \nNetwork Upgrades. In order to determine whether a withdrawal caused overall \nfinancial impact to those remaining Interconnection Requests, the \nTransmission Provider shall compare the planning level cost allocation \nbetween the Preliminary System Impact Study and the Final System Impact \nStudy. \n \nFor projects that withdrew after the completion of Interconnection Customer \nDecision Point I but before the completion of Interconnection Customer \nDecision Point II with at-risk milestones, the Transmission Provider will \ndetermine the costs that were shifted from withdrawn projects to remaining \nprojects that were co-participants in Common Use Upgrades or Shared \nNetwork Upgrades. In order to determine whether a withdrawal caused overall \nfinancial impact to those remaining Interconnection Requests, the \nTransmission Provider shall compare the planning level cost allocation \nbetween the Revised System Impact Study and the Final System Impact \nStudy. \n \nFor projects that withdrew after the completion of Interconnection Customer \nDecision Point II with at-risk milestones or payments, the Transmission \nProvider will determine the costs that were shifted from withdrawn projects to \nremaining projects that were co-participants in Common Use Upgrades or \nShared Network Upgrades. In order to determine whether a withdrawal caused \noverall financial impact to those remaining Interconnection Requests, the \nTransmission Provider shall compare the planning level cost allocation"},{"page":280,"startToken":79782,"endToken":80056,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nbetween the last study the withdrawing project was included in  and the \nsubsequent study. \n \nFor each of the step 1 comparisons, if the comparative planning level cost analysis \nindicates that a project withdrawal causes an increase in financial impact to any \nremaining co-participants, a financial impact analysis will be performed to \ndetermine if the overall costs to the remaining co-participants subsequently \nincreased, those remaining co-participants will be credited using the milestones, \nand/or payment(s) made under a GIA, FCA, or MPFCA that were forfeited by the \nwithdrawn Interconnection Customers or MHVDC Connection Customers in the \nsame cycle. \n \nStep 2:  Transmission Provider will calculate the financial impact to each \nremaining Interconnection Request that is obligated to fund Network Upgrades \nother than Common Use Upgrades or Shared Network Upgrades.   \n \nFor projects that withdrew before the completion of Interconnection Customer \nDecision Point I with at-risk milestones, the Transmission provider will \ndetermine the costs that were shifted from withdrawn projects to remaining \nprojects that fund Network Upgrades other than Common Use Upgrades or \nShared Network Upgrades. In order to determine whether a withdrawal caused \noverall financial impact to those remaining Interconnection Requests, the \nTransmission Provider shall compare the planning level cost allocation \nbetween the Preliminary System Impact Study and the Final System Impact \nStudy. \n \nFor projects that withdrew after the completion of Interconnection Customer \nDecision Point I but before the completion of Interconnection Customer \nDecision Point II with at-risk milestones, the Transmission Provider will \ndetermine the costs that were shifted from withdrawn projects to remaining"},{"page":281,"startToken":80056,"endToken":80395,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nprojects that fund Network Upgrades other than Common Use Upgrades or \nShared Network Upgrades. In order to determine whether a withdrawal caused \noverall financial impact to those remaining Interconnection Requests, the \nTransmission Provider shall compare the planning level cost allocation \nbetween the Revised System Impact Study and the Final System Impact \nStudy. \n \nFor projects that withdrew after the completion of Interconnection Customer \nDecision Point II with at-risk milestones or payments, the Transmission Provider \nwill determine the costs that were shifted from withdrawn projects to remaining \nprojects that fund Network Upgrades other than Common Use Upgrades or \nShared Network Upgrades. In order to determine whether a withdrawal caused \noverall financial impact to those remaining Interconnection Requests, the \nTransmission Provider shall compare the planning level cost allocation between \nthe Final System Impact Study and the subsequent restudy. For each of the Step 2 \ncomparisons, if any portion of the comparative analyses indicates that the \nwithdrawal of a project causes an increase in the total cost of Network Upgrades, \nother than Common Use Upgrades or Shared Network Upgrades, for any of the \nremaining Interconnection Requests, the Transmission Provider will use the \nDefinitive Planning Phase at-risk milestones (M2, M3 and M4), collected from \nthe withdrawn Interconnection Requests in the current Definitive Planning Phase \ncycle and/or payment(s) made under a GIA, FCA, or MPFCA, to offset the cost \ndifference for those remaining Interconnection Requests in the same cycle.  If any \nportion of the comparative analyses indicated that the withdrawal of a project \ncauses a decrease in the total cost of Network Upgrades, other than Common Use \nUpgrades or Shared Network Upgrades, for any of the remaining Interconnection \nRequests, those remaining Interconnection Customers and MHVDC Connection \nCustomers shall not receive any reimbursement from the collected Definitive \nPlanning Phase milestones and/or payment(s) made under a GIA, FCA, or \nMPFCA.  If any portion of the comparative analyses indicates that the withdrawal"},{"page":282,"startToken":80395,"endToken":80713,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nof a project causes the total cost of Network Upgrades, other than Common Use \nUpgrades or Shared Network Upgrades, for any of the remaining Interconnection \nRequests to remain the same, those remaining Interconnection Customers and \nMHVDC Connection Customers shall not receive any reimbursement from the \ncollected Definitive Planning Phase milestones and/or payment(s) made under a \nGIA, FCA, or MPFCA.  \n \nThe total allocation to any remaining Interconnection Requests will not exceed \nthe total Definitive Planning Phase milestones collected from the Interconnection \nCustomers and MHVDC Connection Customers that withdrew their \nInterconnection Requests from the same Definitive Planning Phase cycle and/or \nthe allowable amount from the payment(s) made under a GIA, FCA, or MPFCA.  \nIn instances where the total cost of Network Upgrades has increased for multiple \nInterconnection Requests, but the collected Definitive Planning Phase milestones \nand/or the allowable amount from the payment(s) made under a GIA, FCA, or \nMPFCA are insufficient to cover the increase in total cost of Network Upgrades \nfor all affected Interconnection Requests, the Transmission Provider will allocate \nthe collected Definitive Planning Phase milestones equally as a percentage of \nincreased Network Upgrade costs. \n \nIf any collected Definitive Planning Phase milestones and/or payment(s) made \nunder a GIA, FCA, or MPFCA remain after allocating to remaining affected \nInterconnection Requests, the Transmission Provider will refund the remaining \ncollected Definitive Planning Phase at-risk milestones to each Interconnection \nCustomer and MHVDC Connection Customer in proportion to that customer’s \nforfeited milestone payments as a pro rata share of the total collected Definitive \nPlanning Phase milestones and/or payments made under a GIA, FCA, or MPFCA. \n \nThe amount of the payment(s) made under a GIA, FCA, or MPFCA that can be \nused to compensate for financial impact under this Section cannot exceed the"},{"page":283,"startToken":80713,"endToken":80982,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\namount of the Interconnection Customer’s or MHVDC Connection Customer’s \nDefinitive Planning Phase milestones. \n \n7.8.1 Use of the Automatic Withdrawal Penalty Payments \n \nFor each DPP study group, Transmission Provider shall hold all Automatic \nWithdrawal Penalty funds until all Interconnection Customers in that study \ngroup have either: (1) withdrawn or been deemed withdrawn; (2) executed a \nGIA; or (3) requested a GIA to be filed unexecuted.  Any Automatic \nWithdrawal Penalty funds collected from each DPP study group shall be \nallocated towards studies cost and Network Upgrade costs for Interconnection \nCustomers in the same study group that have executed the GIA or requested \nthe GIA to be filed unexecuted.   \n \nAutomatic Withdrawal Penalty funds shall be distributed to the \nInterconnection Customers in the same DPP study group that executed their \nGIA or requested to have their GIA filed unexecuted following the last \nEffective Date of any GIA for an Interconnection Request in the study group.  \nThe amount of Automatic Withdrawal Penalty funds distributed to an \nInterconnection Customer shall not exceed the total study costs and Network \nUpgrade costs. \n \nTransmission Provider shall post the balance of Automatic Withdrawal \nPenalty funds held by Transmission Provider but not yet dispersed on its \nOASIS site and update this posting on a quarterly basis. \n \n7.9 \nProvisional Generator Interconnection Agreement \nThe Transmission Provider may provide a provisional Generator Interconnection \nAgreement for limited operation at the discretion of Transmission Provider based \nupon the results of available studies that indicate that there is a level of"},{"page":284,"startToken":80982,"endToken":81290,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ninterconnection that can occur without any additional Network Upgrades.  An \nInterconnection Customer may request such Provisional Generator \nInterconnection Agreement by providing written notice to the Transmission \nProvider beginning upon Interconnection Request submission and up to and \nthrough Interconnection Customer Decision Point II (Section 7.3.2.4 of this GIP).  \nAn Interconnection Customer that qualifies for inclusion in a JTIQ Participation \nGroup shall execute or request the unexecuted filing of the JTIQ Commitment \nAgreement concurrently with their provisional GIA and, if tendered, the SPP \nJTIQ Service Agreement. If the SPP JTIQ Service Agreement has not been \ntendered to Interconnection Customer by the time such Interconnection Customer \nexecutes or rests the unexecuted filing of the provisional Generator \nInterconnection Agreement, the provisional Generator Interconnection Agreement \nshall include a milestone in Appendix B requiring the Interconnection Customer \nto execute or request the unexecuted filing of such agreement within fifteen (15 \ndays after it is tendered). \n \nIf scheduled Interconnection Customer Decision Point I, Interconnection \nCustomer Decision Point II, or the Interconnection Facilities Study for Network \nUpgrades becomes delayed by more than sixty (60) Calendar Days, \nInterconnection Customers may also request a Provisional Generator \nInterconnection Agreement from Transmission Provider.  A request for a \nProvisional Generator Interconnection Agreement at any other time shall be \ndeemed invalid by the Transmission Provider.   \n \nAll provisions of the Definitive Planning Phase (Section 7 of this GIP) apply, \nexcept as provided in Section 7.9.1.  After receiving a request for a Provisional \nGenerator Interconnection Agreement, the Transmission Provider will begin the \nfirst portion of the Interconnection Facilities Study as discussed in Section 7.3.3.4 \nand will perform a Provisional Interconnection Study.  After completing required \nstudies, the Transmission Provider will issue a draft Provisional Generator"},{"page":285,"startToken":81290,"endToken":81582,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nInterconnection Agreement pursuant to Section 11.2. \n \n7.9.1 Additional Definitive Planning Phase Requirements for Provisional \nGenerator Interconnection Agreements \nInterconnection Customers seeking a Provisional Generator \nInterconnection Agreement must submit Definitive Planning Phase II and \nDefinitive Planning Phase III Milestones (M3 and M4).  If M3 and M4 \nhave not been calculated at the time of Interconnection Customer’s request \nfor a Provisional Generator Interconnection Agreement, M3 and M4 shall \neach be initially $8,000 per MW.  The Transmission Provider shall then \ncalculate the M3 and M4 as provided in Sections 7.3.1.4.1 and 7.3.2.4.1.  \nIf the actually calculated M3 and M4 values are higher than the M3 and \nM4 previously paid, Interconnection Customer shall pay any difference \nbetween the M3 and M4 previously paid and the actually calculated values \nwithin thirty (30) Calendar Days of those amounts being calculated by the \nTransmission Provider.  Failure to pay any difference between the \ncalculated M3 and M4 and the initially paid M3 and M4 within thirty (30) \nCalendar Days shall result in automatic withdrawal of the Interconnection \nRequest.  If the actually calculated M3 and M4 values are lower than the \nM3 and M4 previously paid, Transmission Provider shall refund any \ndifference between the M3 and M4 previously paid and the actually \ncalculated values. \n \n7.9.2 Consent to Proceed Through Definitive Planning Phase Decision \nPoints \nInterconnection Customers seeking a Provisional Generator \nInterconnection Agreement automatically consent to the Transmission \nProvider moving the Interconnection Request through Definitive Planning \nPhases II and III without regard to Interconnection Customer Decision \nPoint II unless notification of withdrawal is provided to the Transmission"},{"page":286,"startToken":81582,"endToken":81865,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nProvider. \n \n7.9.3 Withdrawal \nInterconnection Customers seeking a Provisional Generator \nInterconnection Agreement are eligible to receive one hundred percent \n(100%) refund of all Definitive Planning Phase milestones (M2, M3, and \nM4) only when the Interconnection Request is withdrawn prior to the start \nof Definitive Planning Phase I and unencumbered study deposits \nremaining, except as noted in Section 4.1.2.3.  Interconnection Customers \nseeking a Provisional Generator Interconnection Agreement at the time of \nInterconnection Request submission may withdraw before the end of \nInterconnection Customer Decision Point I and Transmission Provider will \nrefund forty percent (40%) of the Definitive Planning Phase entry \nmilestone (M2), all of the Definitive Planning Phase Milestone payments \nM3 and M4, and unencumbered study deposits remaining.  Sixty percent \n(60%) of the Definitive Planning Phase entry Milestone (M2) becomes \nnon – refundable pursuant to section 7.6.2.1.1 and Section 7.8 of the GIP.  \nAfter Interconnection Customer Decision Point I, Interconnection \nCustomers seeking a Provisional Generator Interconnection Agreement \nmay withdraw from the Transmission Provider’s interconnection queue at \nany time, but all Definitive Planning Phase milestones (M2, M3, and M4) \nbecome non-refundable pursuant to section 7.6.2.1.1 and Section 7.8, and \nwill be used in accordance to Section 7.8 and Section 7.8.1.  \nInterconnection Customers seeking a Provisional Generator \nInterconnection Agreement shall not be eligible for any milestone \npayment refunds provided under Section 7.6.2.4. \n \n7.9.4 Reversion to Standard Definitive Planning Phase Process \nInterconnection Customers seeking a Provisional Generator \nInterconnection Agreement may notify Transmission Provider before and"},{"page":287,"startToken":81865,"endToken":82111,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nduring Interconnection Customer Decision Point I that the Interconnection \nCustomer wishes to revert to the standard Definitive Planning Phase \nprocess.  Transmission Provider will subsequently refund the Definitive \nPlanning Phase III (M4) milestone payment.  Interconnection Customer \nmust then continue to abide by all Definitive Planning Phase requirements. \n \nSECTION 8.  TRANSMISSION PROVIDER AS AN AFFECTED SYSTEM \n8.1 \nApplicability. \n \nThis Section 8 outlines the duties of Transmission Provider when it receives \nnotification that an Affected System Interconnection Customer’s proposed \ninterconnection to its host transmission provider may impact Transmission \nProvider’s Transmission System.  If applicable, any Joint Operating Agreements \n(“JOA”), Joint Planning Agreements (“JPA”) or any other agreements filed with \nthe Commission will govern Transmission Provider’s Affected System procedures \nwhen Transmission Provider performs an Affected System Study.  The sections \nbelow outline general procedures in absence of any such Agreement or \ndocumentation. \n \n8.2  \nResponse to Notification. \n \nUnless otherwise agreed with an existing JOA/JPA, and other agreements filed \nwith the Commission, as noted in Section 8.1, when Transmission Provider \nreceives notification that an Affected System Interconnection Customer’s \nproposed interconnection to its host transmission provider may impact \nTransmission Provider’s Transmission System, Transmission Provider will \nperform a screen to determine if a study is needed.   \n \nTransmission Provider shall respond in writing within twenty (20) Business Days \nwhether it intends to conduct an Affected System Study.  No later than fifteen"},{"page":288,"startToken":82111,"endToken":82418,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n(15) Business Days after Transmission Provider responds with its affirmative \nintent to conduct an Affected System Study, Transmission Provider shall share \nwith the host transmission provider a non-binding, good faith estimate of the cost \nand schedule to complete the Affected System Study.  If a study is determined \nnecessary, Transmission Provider and host transmission provider will enter into \nan Affected System Study Agreement in the form of Appendix 16 to this GIP.  \nTerms of this agreement will include cost, schedule and interconnection request \nlist scope to complete the Affected System Study. \n \nWithin fifteen (15) Business Days of receipt of notification of restudy, \nTransmission Provider shall send written notification to host transmission \nprovider involved in the restudy that Transmission Provider intends to delay a \nplanned or in-progress Affected System Study until after completion of the \nrestudy.  If Transmission Provider decides to delay the Affected System Study, it \nis not required to meet its obligations under Section 8 of this GIP until the time \nthat it receives notification from the host transmission provider that the restudy is \ncomplete.  If Transmission Provider decides to move forward with its Affected \nSystem Study despite the restudy, then it must meet all requirements under \nSection 8 of this GIP. \n \n8.3  \nAffected System Queue Position. \n \nTransmission Provider must assign an Affected System Queue Position to \nAffected System Interconnection Customer(s) that require(s) an Affected System \nStudy. Such Affected System Queue Position shall be determined based upon the \nqueue priority date outlined in Joint Operating Agreements, or other affected \nsystem agreement accepted by the Commission. \n \nIn the event there is no such document between the Transmission Provider and the \nhost transmission provider, the queue priority date will be determined by the date"},{"page":289,"startToken":82418,"endToken":82691,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nwhen all milestones for the Affected System Study Agreement are met.   \n \nThe queue priority date of Interconnection Requests submitted to the \nTransmission Provider shall be the date of Decision Point I completion of the \ncluster. \n \nThe Affected System Queue Position of the Affected System Interconnection \nCustomer(s) with an earlier queue priority date shall be higher-queued than any \ninterconnection requests that has a later queue priority date. \n \nConsistent with Section 8.6 of this GIP, Transmission Provider shall study the \nAffected System Interconnection Customer(s) via cluster study methodology, and \nall Affected System Interconnection Customer(s) studied in the same cluster \nunder Section 8.6 shall be equally queued. For Affected System Interconnection \nCustomer(s) that are equally queued, the Affected System Queue Position shall \nhave no bearing on the assignment of Affected System Network Upgrades \nidentified in the applicable Affected System Study. \n \nThe costs of the Affected System Network Upgrades shall be allocated among the \nAffected System Interconnection Customers in accordance with Section 8.7 of \nthis GIP. \n \n8.4  \nAffected System Study Agreement. \n \nUnless otherwise agreed with an existing JOA/JPA, and other agreements filed \nwith the Commission as noted in Section 8.1, Transmission Provider will enter \ninto an Affected System Study Agreement, in the form of Appendix 16 to this \nGIP, with the host transmission provider and the host transmission provider will \nprovide payment for study in the form of a deposit.  This agreement will include \ncost, schedule, and interconnection request list scope to complete the Affected"},{"page":290,"startToken":82691,"endToken":82977,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nSystem Study as well as payment terms such as deposit, invoicing and any further \napplicable terms.   \n \nHost transmission provider shall execute the Affected System Study Agreement, \ndeliver the executed Affected System Study Agreement to Transmission Provider, \nand provide the Affected System Study deposit within ten (10) Business Days of \nreceipt.   \n \nIf Transmission Provider notifies the host transmission provider that it will delay \nthe Affected System Study pursuant to Section 8.2 of this GIP, host transmission \nprovider is neither required to execute and return the previously tendered Affected \nSystem Study Agreement nor provide the Affected System Study deposit for the \npreviously tendered Affected System Study Agreement. \n \nIf host transmission provider does not provide all required technical data when it \ndelivers the Affected System Study Agreement, Transmission Provider shall \nnotify the deficient host transmission provider of the technical data deficiency \nwithin five (5) Business Days of the receipt of the executed Affected System \nStudy Agreement and the deficient host transmission provider shall cure the \ntechnical deficiency within ten (10) Business Days of receipt of the notice: \nprovided, however, that such deficiency does not include failure to deliver the \nexecuted Affected System Study Agreement or deposit for the Affected System \nStudy Agreement.  \n \nIf the host transmission provider fails to cure any technical data deficiency, \nexecute its Affected System Study Agreement, or provide the deposit, the host \ntransmission provider shall notify Transmission Provider of the specific Affected \nSystem Interconnection Customer(s) that caused the deficiency.  The deficient \nAffected System Interconnection Customer(s) shall lose its Affected System \nQueue Position, and the deficient Affected System Interconnection Customer(s)"},{"page":291,"startToken":82977,"endToken":83279,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nshall be removed from the Affected System Study Agreement. \n \nIf a host transmission provider fails to pay its undisputed costs related to the \nAffected System Study within thirty (30) Calendar Days of the invoice, host \ntransmission provider shall notify Transmission Provider of the specific Affected \nSystem Interconnection Customer(s) that have failed to pay its undisputed costs \nrelated to the Affected System Study.  The identified Affected System \nInterconnection Customer(s) shall lose its Affected System Queue Position, and \nTransmission Provider shall confirm with the host transmission provider of such \nfailure to pay.  \n \n8.5  \nScope of the Affected System Study. \n \nThe Affected System Study Agreement will include interconnection request list as \nscope, further scope information, study methodology, and study deliverable \ndetails for the Affected System Study as well as payment terms such as deposit, \ninvoicing and any further applicable terms.  The Affected System Study shall \nevaluate the impact that any Affected System Interconnection Customer(s) \nproposed interconnection to another transmission provider’s transmission system \nwill have on the reliability of Transmission Provider’s Transmission System.  The \nAffected System Study shall consider the Base Case as well as all Generating \nFacilities (and with respect to (iii) below, any identified network upgrades \nassociated with such higher-queued Interconnection Request) that, on the date the \nAffected System Study is commenced: (i) are directly interconnected to \nTransmission Provider’s Transmission System; (ii) are directly interconnected to \nanother transmission provider’s transmission system and may have an impact on \nAffected System Interconnection Customer’s interconnection request; (iii) have a \npending higher-queued Interconnection Request to interconnect to Transmission \nProvider’s Transmission System; and (iv) have no queue position but have \nexecuted a GIA or requested that an unexecuted GIA be filed with the"},{"page":292,"startToken":83279,"endToken":83600,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nCommission.  Transmission Provider has no obligation to study impacts of \nAffected System Interconnection Customers of which it is not notified. \n \nThe Affected System Study shall consist of a power flow and stability analysis, as \nwell as a short circuit screen.  The Affected System Study will: state the \nassumptions upon which it is based; state the results of the analyses; and provide \nthe potential impediments to Affected System Interconnection Customer’s receipt \nif the interconnection service on its host transmission provider’s transmission \nsystem, including a preliminary indication of the cost for Affected System \nNetwork Upgrades.  For purposes of determining necessary Affected System \nNetwork Upgrades, the Affected System Study shall consider the level of \ninterconnection service requested in megawatts by Affected System \nInterconnection Customer, unless otherwise required to study the full generating \nfacility capacity due to safety or reliability concerns.  The Affected System Study \nresults shall include a list of facilities that are required as a result of Affected \nSystem Interconnection Customer’s proposed interconnection to another \ntransmission provider’s transmission system, as well as a nonbinding good faith \nestimate of cost responsibility, i.e. the Affected System Network Upgrades.  The \nAffected System Study results will be provided to the host transmission provider \nin the Affected System Study Report. \n \n8.6  \nAffected System Study Procedures. \nTransmission Provider shall use cluster study methodology in conducting the \nAffected System Study and shall use existing studies to the extent practicable, \nwhen multiple Affected System Interconnection Customers that are part of a \nsingle cluster may cause the need for Affected System Network Upgrades.  \nTransmission Provider shall complete the Affected System Study and provide the \nAffected System Study Report to the host transmission provider with whom \ninterconnection has been requested within one hundred fifty (150) Calendar Days \nafter the receipt of a valid Affected System Study Agreement and deposit."},{"page":293,"startToken":83600,"endToken":83905,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \nTransmission Provider shall post regular status updates regarding all ongoing \nAffected System Study.  If Transmission Provider is unable to complete the \nAffected System Study within the requisite time period, it shall notify the host \ntransmission provider and shall provide an estimated completion date with an \nexplanation of the reasons why additional time is required.  If Transmission \nProvider does not meet the deadlines in this section, Transmission Provider shall \nbe subject to the financial penalties as described in Section 3.9 of this GIP.  Upon \nrequest, Transmission Provider shall provide supporting documentation including \npower flow, short circuit and stability models for the Affected System Study, \nsubject to confidentiality arrangements consistent with Section 13.1 of this GIP.   \n \nTransmission Provider must use Energy Resource Interconnection Service \nmodeling standard used for Interconnection Requests on its own Transmission \nSystem for Affected System Study(ies), regardless of the level of interconnection \nservice that Affected System Interconnection Customer is seeking from the host \ntransmission provider with whom it seeks to interconnect. \n \nTransmission Provider shall transmit a draft Affected System Study Report to the \nhost transmission provider for Affected System Interconnection Customers for a \ncomment window.  Transmission Provider will address questions and comments \nsubmitted during the comment window regarding the report before finalizing the \nreport and results.  The comment window will last for at least five (5) Business \nDays, but no more than ten (10) Business Days. \n \n8.7  \nCost Allocation for Affected System Network Upgrades. \nTransmission Provider shall allocate costs for Affected System Network \nUpgrades identified during the Affected System Study by interconnection request, \nusing a pro rata impact method, consistent with Section 4.2.1 of this GIP.  \nAffected System Interconnection Customers will be responsible to pay their"},{"page":294,"startToken":83905,"endToken":84203,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nportion of the Affected System Network Upgrades identified during the Affected \nSystem Study. \n \n8.8  \nRestudy. \nTransmission Provider shall determine the need for restudy of the Affected \nSystem Study as the result of withdrawals of interconnection request from host \ntransmission provider, loss of Affected System Queue Position, or withdrawal of \nTransmission Provider’s higher or equally queued clusters.  If restudy of the \nAffected System Study is required, Transmission Provider shall notify the host \ntransmission provider in writing within thirty (30) Calendar Days of discovery of \nthe need for restudy. Such restudy shall take no longer than ninety (90) Calendar \nDays from the date of notice. Any cost of restudy shall be borne by the Affected \nSystem Interconnection Customer(s) being restudied through the host \ntransmission provider.  Transmission Provider will issue a new version of the \nAffected System Study Report. \n \nTransmission Provider shall transmit a draft Affected System Study Report to the \nhost transmission provider for Affected System Interconnection Customers for a \ncomment window.  Transmission Provider will address questions and comments \nsubmitted during the comment window regarding the report before finalizing the \nreport and results.  The comment window will last for at least five (5) Business \nDays, but no more than ten (10) Business Days. \n \n8.9  \nInterconnection Facilities Study. \nIn accordance with Section 7.3.3.4 of this GIP, an Interconnection Facilities Study \nwill be performed by Transmission Owner on any Affected System Network \nUpgrades identified through the Affected System Study.  The host transmission \nprovider will fund the Affected System Network Upgrades facilities study and the \nstudy scope, timing and funding will be determined by the Affected System \nNetwork Upgrade facilities study agreement.  The Interconnection Facilities"},{"page":295,"startToken":84203,"endToken":84483,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nStudy for such Affected System Network Upgrades shall start the day after \nTransmission Provider submits to the applicable Transmission Owner(s) an \nexecuted statement of work and purchase order. \n \nUnless otherwise agreed and in a timely manner, Transmission Provider, \nTransmission Owner, and host transmission provider will enter into an Affected \nSystem Network Upgrade facilities study agreement, in the form of Appendix 17 \nto this GIP, and the host transmission provider will provide payment for study in \nthe form of a deposit.  This agreement will include cost, schedule, and Affected \nSystem Network Upgrade(s) list scope to complete the Affected System Network \nUpgrade facilities study as well as payment terms such as deposit, invoicing and \nany further applicable terms.   \n \nUpon receipt from the Transmission Owner, Transmission Provider shall transmit \nto the host transmission provider a draft Affected System Network Upgrade \nfacilities study report for Affected System Interconnection Customers for a \ncomment window.  A draft Affected System Network Upgrade facilities study \nreport may be posted by the host transmission provider for Affected System \nInterconnection Customers for a comment window.  Transmission Provider and \nTransmission Owner will address questions and comments submitted during the \ncomment window regarding the report before finalizing the report and results.  \nThe comment window will last for at least five (5) Business Days, but no more \nthan ten (10) Business Days. \n \n8.10  Tender of Facilities Construction Agreement to Affected System \nInterconnection Customer/Multi-Party Facilities Construction Agreement to \nAffected System Interconnection Customer. \n \nTransmission Provider shall tender to Affected System Interconnection \nCustomer(s) a Facilities Construction Agreement/Multi-Party Facilities"},{"page":296,"startToken":84483,"endToken":84790,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nConstruction Agreement, as applicable, in the form of Appendix 8 or 9 to this GIP \nwithin thirty (30) Calendar Days of providing the final Interconnection Facilities \nStudy report.  Affected System Interconnection Customer’s failure to execute the \nFacilities Construction Agreement or Multi-Party Facilities Construction \nAgreement, as applicable, or failure to request the agreement to be filed \nunexecuted with FERC, shall result in the loss of its Affected System Queue \nPosition.  Transmission Provider will drive the negotiation process with \nTransmission Owner(s) and Affected System Interconnection Customer(s) in \naccordance with the processes and timelines set forth in Section 11 of this GIP. \n \n \nSECTION 9. ENGINEERING & PROCUREMENT (“E&P”) AGREEMENT. \n \nPrior to executing an GIA, an Interconnection Customer may, in order to advance \nthe implementation of its interconnection, request and Transmission Provider \nshall offer Interconnection Customer, an E&P Agreement that authorizes \nTransmission Owner to begin engineering and procurement of long lead-time \nitems necessary for the establishment of the interconnection.  However, \nTransmission Provider shall not be obligated to offer an E&P Agreement if \nInterconnection Customer is in Dispute Resolution as a result of an allegation that \nInterconnection Customer has failed to meet any milestones or comply with any \nprerequisites specified in other parts of the GIP.  The E&P Agreement is an \noptional procedure and it will not alter the Interconnection Customer’s Definitive \nPlanning Phase Queue Position or In-Service Date.  The E&P Agreement shall \nprovide for Interconnection Customer to pay the cost of all activities authorized \nby Interconnection Customer and to make advance payments or provide other \nsatisfactory security for such costs. \n \nInterconnection Customer shall pay the cost of such authorized activities and any \ncancellation costs for equipment that is already ordered for its Interconnection"},{"page":297,"startToken":84790,"endToken":85076,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nRequest, which cannot be mitigated as hereafter described, whether or not such \nitems or equipment later become unnecessary.  If Interconnection Customer \nwithdraws its application for interconnection or a Party to the E&P Agreement \nterminates the E&P Agreement, to the extent the equipment ordered can be \ncanceled under reasonable terms, Interconnection Customer shall be obligated to \npay the associated cancellation costs.  To the extent that the equipment cannot be \nreasonably canceled, Transmission Owner may elect:  (i) to take title to the \nequipment, in which event Transmission Owner shall refund Interconnection \nCustomer any amounts paid by Interconnection Customer for such equipment and \nshall pay the cost of delivery of such equipment, or (ii) to transfer title to and \ndeliver such equipment to Interconnection Customer, in which event \nInterconnection Customer shall pay any unpaid balance and cost of delivery of \nsuch equipment. \n \nSECTION 10. \nOTHER INTERCONNECTION STUDIES. \n \n10.1 \nOptional Interconnection Study \n10.1.1 Optional Interconnection Study Agreement. \nOptional Interconnection Studies are for informational purposes only and \nare to be completed within an agreed upon time period using Reasonable \nEfforts.  The request for an Optional Interconnection Study can be made \non a stand-alone basis or in parallel with the processing of valid \nInterconnection Request.  The request shall describe the assumptions that \nInterconnection Customer or MHVDC Connection Customer wishes \nTransmission Provider to study within the scope described in Section \n10.1.2.  Within five (5) Business Days after receipt of a request for an \nOptional Interconnection Study, Transmission Provider shall provide to \nInterconnection Customer an Optional Interconnection Study Agreement \nin the form of Appendix 5."},{"page":298,"startToken":85076,"endToken":85338,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nThe Optional Interconnection Study Agreement shall:  (i) specify the \ntechnical data that Interconnection Customer or MHVDC Connection \nCustomer must provide for each phase of the Optional Interconnection \nStudy, and (ii) specify Interconnection Customer’s or MHVDC \nConnection Customer’s assumptions as to which Interconnection Requests \nwith earlier queue priority dates will be excluded from the Optional \nInterconnection Study case and assumptions as to the type of \nInterconnection Service for Interconnection Requests remaining in the \nOptional Interconnection Study case.  Notwithstanding the above, \nTransmission Provider shall not be required as a result of an Optional \nInterconnection Study request to conduct any additional Interconnection \nStudies with respect to any other Interconnection Request and shall \ncontinue processing the Interconnection Request in accordance with these \nGIP. \n \nInterconnection Customer or MHVDC Connection Customer shall execute \nthe Optional Interconnection Study Agreement within ten (10) Business \nDays of receipt and deliver the Optional Interconnection Study \nAgreement, the technical data and a deposit equal to sixty thousand dollars \n($60,000.00) to Transmission Provider. \n \n10.1.2 Scope of Optional Interconnection Study. \nThe Optional Interconnection Study will consist of a sensitivity analysis \nbased on the assumptions specified by Interconnection Customer or \nMHVDC Connection Customer in the Optional Interconnection Study \nAgreement.  The Optional Interconnection Study will also identify the \nTransmission Owner’s Interconnection Facilities, System Protection \nFacilities, Distribution Upgrades, Generator Upgrades, Common Use \nUpgrades, and the Network Upgrades, and the estimated cost thereof, that \nmay be required to provide transmission service or Interconnection"},{"page":299,"startToken":85338,"endToken":85609,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nService based upon the results of the Optional Interconnection Study.  The \nOptional Interconnection Study shall be performed solely for \ninformational purposes.  Transmission Provider shall use Reasonable \nEfforts to coordinate the study with any Affected Systems that may be \naffected by the types of Interconnection Services that are being studied.  \nTransmission Provider shall utilize existing studies to the extent \npracticable in conducting the Optional Interconnection Study. \n \n10.1.3 Optional Interconnection Study Procedures.   \nThe executed Optional Interconnection Study Agreement, the prepayment, \nand technical and other data called for therein must be provided to \nTransmission Provider within ten (10) Business Days of Interconnection \nCustomer or MHVDC Connection Customer receipt of the Optional \nInterconnection Study Agreement.  Transmission Provider shall use \nReasonable Efforts to complete the Optional Interconnection Study within \na mutually agreed upon time period specified within the Optional \nInterconnection Study Agreement.  If Transmission Provider is unable to \ncomplete the Optional Interconnection Study within such time period, it \nshall notify Interconnection Customer or MHVDC Connection Customer \nand provide an estimated completion date and an explanation of the \nreasons why additional time is required.  Any difference between the study \npayment and the actual cost of the study shall be paid to Transmission \nProvider or refunded to Interconnection Customer, as appropriate.  Upon \nrequest, Transmission Provider shall provide Interconnection Customer or \nMHVDC Connection Customer supporting documentation and \nworkpapers and databases or data developed in the preparation of the \nOptional Interconnection Study, subject to confidentiality arrangements \nconsistent with Section 13.1.   \n \n10.2 \nProvisional Interconnection Study"},{"page":300,"startToken":85609,"endToken":85891,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \n10.2.1 Scope of Provisional Interconnection Study \nThe Provisional Interconnection Study will consist of stability, short \ncircuit, and voltage analysis to identify issues that would result if the \nGenerating Facility were interconnected without project modifications or \nsystem modifications.  The Provisional Interconnection Study will also \nidentify the Transmission Owner’s Interconnection Facilities, System \nProtection Facilities, Distribution Upgrades, Generator Upgrades, \nCommon Use Upgrades, and the Network Upgrades, and the estimated \ncost thereof, that may be required to provide Energy Resource \nInterconnection Service on a provisional basis based upon the results of \nthe Provisional Interconnection Study.  Transmission Provider shall use \nReasonable Efforts to coordinate the study with any affected systems that \nmay be affected by the type of Interconnection Service that is being \nstudied.  Transmission Provider shall utilize existing studies to the extent \npracticable in conducting the Provisional Interconnection Study. \n \n10.2.2 Provisional Interconnection Study Procedures \nTransmission Provider must receive the information and milestones as \ndescribed in Sections 7.9 and 7.9.1 prior to beginning the Provisional \nInterconnection Study.  Transmission Provider shall use Reasonable \nEfforts to complete the Provisional Interconnection Study within a \nmutually agreed upon time.  If Transmission Provider is unable to \ncomplete the Provisional Interconnection Study within such time period, it \nshall notify Interconnection Customer or MHVDC Connection Customer \nand provide an estimated completion date and an explanation of the \nreasons why additional time is required.  Actual cost of the Provisional \nInterconnection Study shall be paid by Interconnection Customer or \nMHVDC Connection Customer pursuant to Section 7.6.1.  Upon request, \nTransmission Provider shall provide Interconnection Customer or"},{"page":301,"startToken":85891,"endToken":86158,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nMHVDC Connection Customer supporting documentation and \nworkpapers and databases or data developed in the preparation of the \nProvisional Interconnection Study, subject to confidentiality arrangements \nconsistent with Section 13.1. \n \nSECTION 11. GENERATOR INTERCONNECTION AGREEMENT (GIA), \nFACILITIES CONSTRUCTION AGREEMENT (FCA), AND MULTI-\nPARTY FACILITIES CONSTRUCTION AGREEMENT (MPFCA). \n \n11.1 \nTender. \nExcept as provided in Section 11.1.1, Transmission Provider shall tender to the \nInterconnection Customer a draft GIA and, as applicable, draft JTIQ Service \nAgreement(s), FCA(s) and/or MPFCA(s), together with draft appendices \ncompleted to the extent practicable, within five (5) Business Days after issuance \nof the applicable first portion of the Interconnection Facilities Study report and \nFinal System Impact Study report. \n \nThroughout this Section 11, the applicable Interconnection Facilities Study for a \nGIA shall be the Interconnection Facilities Study that was initiated for that project \nin DPP Phase II.  For EGIAs, this shall be the applicable Interconnection \nFacilities Study initiated through ERAS.  Throughout this Section 11, the \napplicable Interconnection Facilities Study for a Network Upgrade that is \naddressed in a FCA or MPFCA shall be the Interconnection Facilities Study \nperformed for that Network Upgrade. \n \nAt the request of any Party, and except for Interconnection Requests for an ERAS \nor ZG Interconnection Request, Transmission Provider shall tender to the \nInterconnection Customer a draft GIA and, as applicable, JTIQ Service \nAgreement(s), draft FCA(s), together with draft appendices completed to the \nextent practicable, within ten (10) Calendar Days of receiving such request,"},{"page":302,"startToken":86158,"endToken":86468,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nprovided such request is received after the completion of Interconnection \nCustomer Decision Point II and issuance of the draft Phase II Interconnection \nFacilities Study.  The draft GIA and, as applicable, draft FCA and the \nTransmission Provider’s JTIQ Service Agreement(s), shall be in the form of the \nTransmission Provider’s current pro forma. In the event that SPP’s JTIQ Service \nAgreement has not been provided to Interconnection Customer prior to tender of a \ndraft GIA, the draft GIA shall include a milestone in Appendix B obligating \nInterconnection Customer to execute or request the unexecuted filing of SPP’s \nJTIQ Service Agreement not later than 15 Calendar Days after such agreement \nhas been tendered to the Interconnection Customer. \n \n11.1.1 Common Use Upgrades and Multi-Party Facilities Construction \nAgreements. \n \nIn the event that the Final System Impact Study report indicates that more than \none Interconnection Request causes the need for Network Upgrades or System \nProtection Facilities, Transmission Provider shall determine whether such \nNetwork Upgrades or System Protection Facilities are Common Use Upgrades \nrequiring the use of a MPFCA.  No later than ten (10) Calendar Days after \nissuance of the Final System Impact Study report and the applicable final \nInterconnection Facilities Study reports for each of the projects that are a part of \nthe MPFCA, Transmission Provider shall tender the draft MPFCA to all \nInterconnection Customers that create the need and share the responsibility for the \nCommon Use Upgrade.  If Transmission Provider determines that an \nInterconnection Customer should be added to an MPFCA as a party, Transmission \nProvider shall tender a draft MPFCA to the prospective Interconnection Customer \nand include the prospective Interconnection Customer in Group Studies as \napplicable. \n \nUpon the written request of all Interconnection Customers that are Party to the"},{"page":303,"startToken":86468,"endToken":86828,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nMPFCA, Transmission Provider shall tender the MPFCA within ten (10) \nCalendar Days of receiving such written request, provided such request is \nreceived after issuance of: (i) the Final System Impact Study report; and (ii) the \napplicable draft Interconnection Facilities Study reports for each of the projects \nthat are a part of the MPFCA.     \n \n11.2 \nNegotiation. \nInterconnection Customer and Transmission Owner shall return comments on the \ndraft GIA, and as applicable, JTIQ Service Agreement(s), draft FCA(s) and/or \nMPFCA(s) within twenty (20) Business Days, or for Interconnection Requests in \nan ERAS five (5) Business Days, of receipt of the draft GIA, and as applicable, \ndraft FCA(s) and/or MPFCA(s), along with the completion of the parts of the \nappendices for which Interconnection Customer is responsible.  Within ten (10) \nBusiness Days after the comments are submitted, or for Interconnection Requests \nin an ERAS or seeking ZG Interconnection Service five (5) Business Days, \nTransmission Provider shall tender a revised draft GIA, and as applicable, draft \nFCA(s) and/or MPFCA(s) to the Parties, together with draft appendices. \n \nThe Parties shall begin negotiations concerning the appendices to the GIA, and, as \napplicable, FCA(s) and/or MPFCA(s) upon tender of the draft GIA, and as \napplicable, draft FCA(s) and/or MPFCA(s) to the Parties in accordance with the \nterms of Section 11.1 of this GIP. Except as provided in Section 11.2.1 of this \nGIP, Transmission Provider, Transmission Owner, and Interconnection Customer \nshall negotiate the GIA for no more than forty (40) Business Days after issuance \nof the Final System Impact Study report.  For Interconnection Requests in an \nERAS or those seeking ZG Interconnection Service twenty (20) Business Days \nfrom notice to proceed in Section 3.9.4 or 3.11.3 of these GIP.  Transmission \nProvider, Transmission Owner, and Interconnection Customer shall negotiate \ndraft FCA(s) and/or MPFCA(s) for no more than forty (40) Business Days after \nissuance of the applicable final Interconnection Facilities Study reports applicable"},{"page":304,"startToken":86828,"endToken":87160,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nto the FCA(s) and/or MPFCA(s) that are subject to negotiation and the Final \nSystem Impact Study report.   \n \nIf Interconnection Customer, Transmission Owner or Transmission Provider \ndetermines that negotiations are at an impasse, it may request termination of the \nnegotiations by providing written notice to the other parties at any time after \ntender of the draft GIA, and, as applicable, JTIQ Service Agreement(s), draft \nFCA(s) and/or MPFCA(s) pursuant to Section 11.1 and request submission of the \nunexecuted GIA, and, as applicable, JTIQ Service Agreement(s), FCA(s) and/or \nMPFCA(s) with FERC or initiate Dispute Resolution procedures pursuant to \nSection 13.5. The Interconnection Customer, Transmission Owner or \nTransmission Provider may request such termination and request for an \nunexecuted filing during the negotiation period established in this Section 11.2 \nand under the negotiation period established in Section 11.2.1 of this GIP, as \napplicable. If an Interconnection Customer requests termination of its \nnegotiations, but within thirty (30) Calendar Days thereafter fails to request the \nfiling of the unexecuted GIA, and, as applicable, tendered JTIQ Service \nAgreement(s), FCA(s) and/or MPFCA(s), it shall be deemed to have withdrawn \nits Interconnection Request.   \n \n11.2.1 Optional negotiation period adjustment for Interconnection Facilities \nStudy or Affected Systems Study results. \nExcept for Interconnection Requests in an ERAS, the Interconnection Customer \nmay postpone the start of the negotiation period for the GIA, and as applicable, \ndraft FCA(s) and/or MPFCA(s), until the later of the issuance of the applicable \nfinal Interconnection Facilities Study report or the issuance of the Affected \nSystems Study Report. Interconnection Customer shall make such election by \nproviding written notice to the Transmission Provider prior to the posting of the \nFinal System Impact Study report. If Interconnection Customer makes such \nelection, Transmission Provider, Transmission Owner, and Interconnection"},{"page":305,"startToken":87160,"endToken":87517,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nCustomer shall negotiate the GIA and as applicable, JTIQ Commitment \nAgreements, draft FCA(s) and/or MPFCA(s), for no more than forty (40) \nBusiness Days after the later of the issuance of the final applicable \nInterconnection Facilities Study or issuance of the Affected System Study Report. \n \n11.3 \nExecution and Filing.   \nTransmission Provider shall provide to Interconnection Customer and \nTransmission Owner a final GIA, and, as applicable, final JTIQ Service \nAgreement(s), final FCA(s) and/or final MPFCA(s) prepared for execution by the \nparties within fifteen (15) Business Days after the completion of the forty (40) \nBusiness Day negotiation period in accordance with Section 11.2 of this GIP.  For \nInterconnection Requests for an ERAS or ZG Interconnection Service, the \nTransmission Provider shall provide to Interconnection Customer and \nTransmission Owner a final EGIA or ZGIA within ten (10) Business Days after \nthe completion of the negotiation period in accordance with Section 11.2 of this \nGIP.  Within forty-five (45) Calendar Days of tender of the final GIA or ZGIA, \nand, as applicable, final JTIQ Service Agreement(s), final FCA(s) and final \nMPFCA(s), Interconnection Customer and Transmission Owner shall either: (i) \nexecute the tendered GIA or ZGIA, and, as applicable, final JTIQ Service \nAgreement(s), FCA(s) and/or MPFCA(s); or (ii) request in writing that \nTransmission Provider file with FERC the GIA or ZGIA, and, as applicable, JTIQ \nService Agreement(s), FCA(s) and/or MPFCA(s) in unexecuted form.   \n \nIf Interconnection Customer has neither executed the GIA or ZGIA, and, as \napplicable, tendered JTIQ Service Agreement(s), FCA(s) and/or MPFCA(s), nor \nrequested filing of the GIA, and, as applicable, JTIQ Service Agreement(s), \nFCA(s) and/or MPFCA(s) in unexecuted form within forty-five (45) Calendar \nDays, or for Interconnection Requests in an ERAS ten (10) Business Days  of \ntender of the final GIA, and, as applicable, JTIQ Service Agreement(s), final \nFCA(s) and final MPFCA(s), Interconnection Customer shall be deemed to have"},{"page":306,"startToken":87517,"endToken":87865,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nwithdrawn its Interconnection Request.  The Interconnection Customer’s forty-\nfive (45) Calendar Day deadline for execution will not reset in the event that an \nadditional change is made to the GIA or ZGIA, JTIQ Service Agreement(s), FCA, \nor MPFCA after circulation for execution. \n \nWithin ten (10) Business Days after receiving from the Interconnection \nCustomer(s) and the Transmission Owner either the executed tendered GIA or \nZGIA, and, as applicable, tendered  JTIQ Service Agreement(s), FCA(s) and/or \nMPFCA(s)  or the request to file an unexecuted GIA or ZGIA, and, as applicable, \ntendered JTIQ Service Agreement(s), FCA(s) and/or MPFCA(s), Transmission \nProvider shall file the GIA or ZGIA, and, as applicable, tendered JTIQ Service \nAgreement(s), FCA(s) and/or MPFCA(s) with FERC, together with its \nexplanation of any matters as to which Interconnection Customer, Transmission \nOwner and Transmission Provider disagree and support for the costs that \nTransmission Owner proposes to charge to Interconnection Customer under the \nGIA or ZGIA, and, as applicable, tendered JTIQ Service Agreement(s), FCA(s) \nand/or MPFCA(s).  An unexecuted GIA or ZGIA, and, as applicable, JTIQ \nService Agreement(s), FCA(s) and/or MPFCA(s), shall contain terms and \nconditions deemed appropriate by Transmission Provider for the Interconnection \nRequest.   \n \nWithin one-hundred and eighty (180) Calendar Days after receipt of the final GIA \nInterconnection Customer shall provide Transmission Provider with reasonable \nevidence that one or more of the following milestones in the development of the \nGenerating Facility has been achieved:  (i) the execution of a contract for the \nsupply or transportation of fuel to the Generating Facility; (ii) the execution of a \ncontract for the supply of cooling water to the Generating Facility; (iii) execution \nof a contract for the engineering for, procurement of major equipment for, or \nconstruction of, the Generating Facility; (iv) execution of a contract for the sale of \nelectric energy or capacity from the Generating Facility, or a statement signed by"},{"page":307,"startToken":87865,"endToken":88196,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nan authorized officer from or agent of Interconnection Customer attesting that \nInterconnection Customer owns the Generating Facility and it is required to serve \nload; or (v) documentation of application for all necessary state and local air, \nwater, land, federal nuclear, and/or Environmental Law permits and that the \napplication is proceeding per regulations.   \n \n11.4 \nCommencement of Interconnection Activities.   \nIf Interconnection Customer executes the final GIA or ZGIA, and, as applicable, \ntendered JTIQ Service Agreement(s), FCA(s) and/or MPFCA(s) Transmission \nProvider, Transmission Owner and Interconnection Customer shall perform their \nrespective obligations in accordance with the terms of the GIA or ZGIA, and, as \napplicable, tendered JTIQ Service Agreement(s), FCA(s) and/or MPFCA(s), \nsubject to modification by FERC.  Unless otherwise agreed by all Parties, upon \nsubmission of an unexecuted GIA or ZGIA, and, as applicable, unexecuted \ntendered JTIQ Service Agreement(s), unexecuted FCA(s) and/or unexecuted \nMPFCA(s), the Parties shall promptly comply with the unexecuted GIA or ZGIA, \nand, as applicable, unexecuted JTIQ Service Agreement(s), unexecuted FCA(s) \nand/or unexecuted MPFCA(s), subject to modification by FERC.  As applicable, \ncompliance with the terms of such unexecuted JTIQ Service Agreement(s), \nFCA(s) and/or MPFCA(s) or execution and performance under a JTIQ Service \nAgreement(s), FCA and/or MPFCA will be a requirement under the GIA. \n \n11.5 \nSpecial Considerations. \nThe maximum permissible output of the Generating Facility in the Provisional \nGenerator Interconnection Agreement will be updated on a quarterly basis, and \ndetermined by finding the transfer limit of energy commensurate with the analysis \nfor Energy Resource Interconnection Service.  This study shall be performed \nassuming the system topology represented by the base cases used to calculate \nAvailable Flowgate Capability as described in Attachment C of this Tariff with \ndispatch and optimization algorithms posted on the MISO internet site.  Limits"},{"page":308,"startToken":88196,"endToken":88467,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nwill be posted on the Transmission Provider’s OASIS site, and operation above \nthose limits will be deemed as unauthorized use of the transmission system and \nsubject to provisions in this Tariff surrounding that use.  Interconnection \nCustomer assumes all risks and liabilities with respect to changes, which may \nimpact the Generator Interconnection Agreement including, but not limited to, \nchange in output limits and future Network Upgrade cost responsibilities. \n \n11.6 \nQuarterly Operating Limit Studies. \nInterconnection Customers subject to Quarterly Operating Limits shall be \nresponsible for the cost of performing the required quarterly studies. \nInterconnection Customers shall submit a Quarterly Operating Limit study deposit \nin the amount of $10,000 sixty (60) Calendar Days prior to the start of the first \napplicable binding quarter.  Any difference between the study deposit and the \nactual cost of the applicable Quarterly Operating Limit studies shall be paid by, or \nrefunded to, the Interconnection Customer.  MISO will refund any difference the \nquarter following the Interconnection Customer no longer being subject to \nQuarterly Operating Limits. \n \nSECTION 12. CONSTRUCTION OF TRANSMISSION OWNER’S OR AFFECTED \nSYSTEM TRANSMISSION OWNER’S INTERCONNECTION \nFACILITIES, SYSTEM PROTECTION FACILITIES, DISTRIBUTION \nUPGRADES AND NETWORK UPGRADES. \n \n12.1 \nSchedule. \nTransmission Owner, Interconnection Customer, and, as applicable, \nInterconnection Customers in an MPFCA and a Transmission Owner that is an \nAffected System and, at its election, Transmission Provider shall negotiate in \ngood faith concerning a schedule for the construction of the Transmission \nOwner’s Interconnection Facilities, System Protection Facilities, Distribution \nUpgrades, Network Upgrades, Common Use Upgrades, and the Stand-Alone"},{"page":309,"startToken":88467,"endToken":88738,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nNetwork Upgrades, excluding JTIQ Upgrades.  Interconnection Customer and \nTransmission Owner shall each provide the other Parties its detailed construction \nschedule. \n \n12.2 \nConstruction Sequencing. \n \n12.2.1 \nGeneral \nIn general, the In-Service Date of an Interconnection Customer seeking \ninterconnection to the Transmission System will determine the sequence \nof construction of Transmission Owner’s Interconnection Facilities, \nSystem Protection Facilities, Distribution Upgrades, if any, and Network \nUpgrades, including any Common Use Upgrades.  If the time required to \nbuild the facilities described in the GIA, and, as applicable, FCA(s) \nand/or MPFCA(s), excluding JTIQ Upgrades, is greater than the time \nbetween execution of the GIA, and, as applicable, FCA(s) and/or \nMPFCA(s) and the requested In-Service Date, the In-Service Date will \nbe adjusted through the milestones delineated in the GIA, and as \napplicable, FCA(s) and/or MPFCA(s) appendices prior to the execution \nof the Generator Interconnection Agreement.  \n \n12.2.2 \nAdvance Construction of Network Upgrades, System Protection \nFacilities, Distribution Upgrades or Generator Upgrades that are an \nObligation of an Entity other than Interconnection Customer \nAn Interconnection Customer with a GIA, and, as applicable, FCA(s) \nand/or MPFCA(s), in order to maintain its In-Service Date, may request \nthat Transmission Owner advance to the extent necessary the completion \nof Network Upgrades, System Protection Facilities or Distribution \nUpgrades that:  (i) were assumed in the Interconnection Studies for such \nInterconnection Customer, (ii) are necessary to support such In-Service \nDate, and (iii) would otherwise not be completed, pursuant to a"},{"page":310,"startToken":88738,"endToken":89060,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ncontractual obligation of an entity other than Interconnection Customer \nthat is seeking interconnection to the Transmission System, in time to \nsupport such In-Service Date.  Upon such request, Transmission Owner \nwill use Reasonable Efforts to advance the construction of such Network \nUpgrades, System Protection Facilities or Distribution Upgrades, to the \nextent it is obligated for any such construction, to accommodate such \nrequest; provided that Interconnection Customer commits to pay \nTransmission Owner:  (i) any associated expediting costs and (ii) the \ncost of such Network Upgrades, System Protection Facilities or \nDistribution Upgrades.  Transmission Owner will refund to \nInterconnection Customer both the expediting costs and the cost of \nNetwork Upgrades, in accordance with Article 11.4 of the GIA, and, as \napplicable, FCA(s) and/or MPFCA(s).  Consequently, the entity with a \ncontractual obligation to construct such Network Upgrades shall be \nobligated to pay only that portion of the costs of the Network Upgrades \nthat Transmission Owner has not refunded to Interconnection Customer.  \nPayment by that entity shall be due on the date that it would have been \ndue had there been no request for advance construction.  Transmission \nOwner shall forward to Interconnection Customer (with copy to \nTransmission Provider) the amount paid by the entity with a contractual \nobligation to construct the Network Upgrades as payment in full for the \noutstanding balance owed to Interconnection Customer.  Transmission \nOwner then shall refund to that entity the amount that it paid for the \nNetwork Upgrades, in accordance with Article 11.4 of the GIA, and, as \napplicable, FCA(s) and/or MPFCA(s). \n \n12.2.3 \nAdvancing Construction of Network Upgrades that are Part of an \nExpansion Plan of Transmission Provider \nAn Interconnection Customer with a GIA, and, as applicable, FCA(s) \nand/or MPFCA(s), in order to maintain its In-Service Date, may request"},{"page":311,"startToken":89060,"endToken":89325,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nthat Transmission Owner advance to the extent necessary the completion \nof Network Upgrades, System Protection Facilities or Distribution \nUpgrades that:  (i) are necessary to support such In-Service Date, \nincluding those listed as a contingent element in the Interconnection \nCustomer’s GIA, and, as applicable, FCA(s) and/or MPFCA(s); and (ii) \nwould otherwise not be completed, pursuant to an expansion plan of \nTransmission Provider, in time to support such In-Service Date.  Upon \nsuch request, Transmission Owner will use Reasonable Efforts to \nadvance the construction of such Network Upgrades, System Protection \nFacilities or Distribution Upgrades to accommodate such request; \nprovided that Interconnection Customer commits to pay Transmission \nOwner any associated expediting costs.  Interconnection Customer shall \nbe entitled to transmission credits, if any per Attachment FF, for any \nexpediting costs paid associated with the Network Upgrades. \n \n12.2.4 \nAmended Interconnection System Impact and/or Interconnection \nFacilities Study \nThe Interconnection System Impact Study resulting from the Definitive \nPlanning Phase and/or Interconnection Facilities Study(ies) will be \namended to determine the facilities necessary to support the requested \nIn-Service Date.  Any amended study will follow the procedures \nprovided in the GIP, as applicable, regarding such study and study cost, \nand include those transmission and Generating Facilities that are \nexpected to be in service on or before the requested In-Service Date. \n \nSECTION 13.  MISCELLANEOUS. \n \n13.1 \nConfidentiality. \nConfidential Information shall include, without limitation, all information relating \nto a Party’s technology, research and development, business affairs, and pricing,"},{"page":312,"startToken":89325,"endToken":89662,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nand any information supplied by any Party to another Party prior to the execution \nof a GIA or ZGIA, and, as applicable, FCA(s) and/or MPFCA(s). \n \nInformation is Confidential Information only if it is clearly designated or marked \nin writing as confidential on the face of the document, or, if the information is \nconveyed orally or by inspection, if the Party providing the information orally \ninforms the Party receiving the information that the information is confidential. \n \nIf requested by the receiving Party, the disclosing Party shall provide in writing, \nthe basis for asserting that the information referred to in this Section warrants \nconfidential treatment, and the requesting Party may disclose such writing to the \nappropriate Governmental Authority.  Each Party shall be responsible for the \ncosts associated with affording confidential treatment to its information. \n \n13.1.1 Scope \nConfidential Information shall not include information that the receiving \nParty can demonstrate: (1) is generally available to the public other than as \na result of a disclosure by the receiving Party; (2) was in the lawful \npossession of the receiving Party on a non-confidential basis before \nreceiving it from the disclosing Party; (3) was supplied to the receiving \nParty without restriction by a non-Party, who, to the knowledge of the \nreceiving Party after due inquiry, was under no obligation to the disclosing \nParty to keep such information confidential; (4) was independently \ndeveloped by the receiving Party without reference to Confidential \nInformation of the disclosing Party; (5) is, or becomes, publicly known, \nthrough no wrongful act or omission of the receiving Party or Breach of \nthe GIA or ZGIA, and, as applicable, FCA(s) and/or MPFCA(s); or (6) is \nrequired, in accordance with Section 13.1.6, Order of Disclosure, to be \ndisclosed by any Governmental Authority or is otherwise required to be \ndisclosed by law or subpoena, or is necessary in any legal proceeding"},{"page":313,"startToken":89662,"endToken":89947,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nestablishing rights and obligations under the GIA or ZGIA, and, as \napplicable, FCA(s) and/or MPFCA(s).  Information designated as \nConfidential Information will no longer be deemed confidential if the \nParty that designated the information as confidential notifies the receiving \nParty that it no longer is confidential. \n \n13.1.2 Release of Confidential Information \nNo Party shall release or disclose Confidential Information to any other \nperson, except to its Affiliates (limited by the Standards of Conduct \nrequirements) employees, agents, consultants, or to non-parties who may \nbe or considering providing financing to or equity participation with \nInterconnection Customer or MHVDC Connection Customer, or to \npotential purchasers or assignees of Interconnection Customer or MHVDC \nConnection Customer, on a need-to-know basis in connection with these \nprocedures, unless such person has first been advised of the confidentiality \nprovisions of this Section 13.1 and has agreed to comply with such \nprovisions.  Notwithstanding the foregoing, a Party providing Confidential \nInformation to any person shall remain primarily responsible for any \nrelease of Confidential Information in contravention of this Section 13.1. \n \n \n13.1.3 Rights \nEach Party retains all rights, title, and interest in the Confidential \nInformation that it discloses to the receiving Party.  The disclosure by a \nParty to the receiving Party of Confidential Information shall not be \ndeemed a waiver by the disclosing Party or any other person or entity of \nthe right to protect the Confidential Information from public disclosure. \n \n13.1.4 No Warranties \nBy providing Confidential Information, no Party makes any warranties or \nrepresentations as to its accuracy or completeness.  In addition, by"},{"page":314,"startToken":89947,"endToken":90224,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nsupplying Confidential Information, no Party obligates itself to provide \nany particular information or Confidential Information to another Party \nnor to enter into any further agreements or proceed with any other \nrelationship or joint venture. \n \n13.1.5 Standard of Care \nEach Party shall use at least the same standard of care to protect \nConfidential Information it receives as it uses to protect its own \nConfidential Information from unauthorized disclosure, publication or \ndissemination.  Each Party may use Confidential Information solely to \nfulfill its obligations to another Party under these procedures or its \nregulatory requirements. \n \n13.1.6 Order of Disclosure \nIf a court or a Government Authority or entity with the right, power, and \napparent authority to do so requests or requires any Party, by subpoena, \noral deposition, interrogatories, requests for production of documents, \nadministrative order, or otherwise, to disclose Confidential Information, \nthat Party shall provide the disclosing Party with prompt notice of such \nrequest(s) or requirement(s) so that the disclosing Party may seek an \nappropriate protective order or waive compliance with the terms of the \nGIA. Notwithstanding the absence of a protective order or waiver, the \nParty may disclose such Confidential Information which, in the opinion of \nits counsel, the Party is legally compelled to disclose.  Each Party will use \nReasonable Efforts to obtain reliable assurance that confidential treatment \nwill be accorded any Confidential Information so furnished. \n \n13.1.7 Remedies \nThe Parties agree that monetary damages would be inadequate to \ncompensate a Party for another Party’s breach of its obligations under this"},{"page":315,"startToken":90224,"endToken":90601,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nSection 13.1.  Each Party accordingly agrees that the disclosing Party shall \nbe entitled to equitable relief, by way of injunction or otherwise, if the \nreceiving Party breaches or threatens to breach its obligations under this \nSection 13.1, which equitable relief shall be granted without bond or proof \nof damages, and the breaching Party shall not plead in defense that there \nwould be an adequate remedy at law.  Such remedy shall not be deemed \nan exclusive remedy for the breach of this Section 13.1, but shall be in \naddition to all other remedies available at law or in equity.  The Parties \nfurther acknowledge and agree that the covenants contained herein are \nnecessary for the protection of legitimate business interests and are \nreasonable in scope.  No Party, however, shall be liable for indirect, \nincidental, or consequential or punitive damages of any nature or kind \nresulting from or arising in connection with this Section 13.1. \n \n13.1.8 Disclosure to FERC, Its Staff, or a State. \nNotwithstanding anything in this Section 13.1 to the contrary, and \npursuant to 18 C.F.R Section 1b.20, if FERC or its staff, during the course \nof an investigation or otherwise, requests information from a Party that is \notherwise required to be maintained in confidence pursuant to these GIP, \nthe Party shall provide the requested information to FERC or its staff, \nwithin the time provided for in the request for information.  In providing \nthe information to FERC or its staff, the Party must, consistent with 18 \nC.F.R. Section 388.112, request that the information be treated as \nconfidential and non-public by FERC and its staff and that the information \nbe withheld from public disclosure.  The Party is prohibited from notifying \nthe other Parties prior to the release of the Confidential Information to the \nCommission or its staff.  The Party shall notify the other Parties to the \nGIA when it is notified by FERC or its staff that a request to release \nConfidential Information has been received by FERC, at which time any \nof the Parties may respond before such information would be made public,"},{"page":316,"startToken":90601,"endToken":90907,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\npursuant to 18 C.F.R. Section 388.112.   \n \nRequests from a state regulatory body conducting a confidential \ninvestigation shall be treated in a similar manner, consistent with \napplicable state rules and regulations. \n \n13.1.9 Subject to the exception in Section 13.1.8, any information that a \ndisclosing Party claims is competitively sensitive, commercial or financial \ninformation (“Confidential Information”) shall not be disclosed by the \nreceiving Party to any person not employed or retained by the receiving \nParty, except to the extent disclosure is (i) required by law; (ii) reasonably \ndeemed by the disclosing Party to be required to be disclosed in \nconnection with a dispute between or among the Parties, or the defense of \nlitigation or dispute; (iii) otherwise permitted by consent of the disclosing \nParty, such consent not to be unreasonably withheld; or (iv) necessary to \nfulfill its obligations under the GIP or as the Regional Transmission \nOrganization or a Local Balancing Authority operator including disclosing \nthe Confidential Information to a subregional, regional or national \nreliability organization or planning group.  The Party asserting \nconfidentiality shall notify the receiving Party in writing of the \ninformation that Party claims is confidential.  Prior to any disclosures of \nthat Party’s Confidential Information under this subparagraph, or if any \nnon-Party or Governmental Authority makes any request or demand for \nany of the information described in this subparagraph, the receiving Party \nagrees to promptly notify the disclosing Party in writing and agrees to \nassert confidentiality and cooperate with the disclosing Party in seeking to \nprotect the Confidential Information from public disclosure by \nconfidentiality agreement, protective order or other reasonable measures. \n \n13.1.10 This provision shall not apply to any information that was or is hereafter"},{"page":317,"startToken":90907,"endToken":91207,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nin the public domain (except as a result of a breach of this provision). \n \n13.1.11 At the Interconnection Customer’s or MHVDC Connection Customer’s \nelection, Transmission Provider shall cause the party in lawful possession \nof Confidential Information to, destroy, in a confidential manner, or return \nthe Confidential Information provided at the time of Confidential \nInformation is no longer needed. \n \n13.2 \nDelegation of Responsibility. \nTransmission Provider may use the services of subcontractors as it deems \nappropriate to perform its obligations under the GIP.  Transmission Provider shall \nremain primarily liable to Interconnection Customer or MHVDC Connection \nCustomer for the performance of such subcontractors and compliance with its \nobligations of the GIP.  The subcontractor shall keep all information provided \nconfidential and shall use such information solely for the performance of such \nobligation for which it was provided and for no other purpose. \n \n13.3 \nObligation for Study Costs. \nTransmission Provider shall charge and Interconnection Customer or MHVDC \nConnection Customer shall pay the actual costs of the Interconnection Studies.  \nAny difference between the study deposit and the actual cost of the applicable \nInterconnection Study shall be paid by or refunded, except as otherwise provided \nherein, to Interconnection Customer or MHVDC Connection Customer or offset \nagainst the cost of any future Interconnection Studies associated with the \napplicable Interconnection Request prior to beginning of any such future \nInterconnection Studies.  Any invoices for Interconnection Studies shall include a \ndetailed and itemized accounting of the cost of each Interconnection Study.  \nInterconnection Customer or MHVDC Connection Customer shall pay any such \nundisputed costs within thirty (30) Calendar Days of receipt of an invoice.  \nTransmission Provider shall not be obligated to perform or continue to perform"},{"page":318,"startToken":91207,"endToken":91514,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nany studies unless Interconnection Customer or MHVDC Connection Customer \nhas paid all undisputed amounts in compliance herewith.   \n \nIn the event Interconnection Customer’s or MHVDC Connection Customer’s \nproject is withdrawn, terminated or suspended, Transmission Provider shall not be \nrequired to refund any unused portion of the study deposit paid to enter the \nDefinitive Planning Phase that is necessary to account for study costs associated \nwith the project or restudy costs associated with any affected lower-queued \nprojects, any other project with which Interconnection Customer’s or MHVDC \nConnection Customer’s project shares responsibility for funding a Common Use \nUpgrade, or, in the event the project is included in a Group Study, any other \naffected projects in the Group Study.  Unused study deposits from the Definitive \nPlanning Phase that are not otherwise required due to the withdrawals, \ntermination or suspension of the project will be refunded upon Commercial \nOperation. \n \n13.4 \nNon-Parties Conducting Studies. \nIf (i) at the time of the signing of an Interconnection Study Agreement there is \ndisagreement as to the estimated time to complete an Interconnection Study, (ii) \nInterconnection Customer or MHVDC Connection Customer receives notice \npursuant to the GIP that Transmission Provider will not complete an \nInterconnection Study within the applicable timeframe for such Interconnection \nStudy, or (iii) Interconnection Customer or MHVDC Connection Customer \nreceives neither the Interconnection Study nor a notice under the GIP within the \napplicable timeframe for such Interconnection Study, then Interconnection \nCustomer or MHVDC Connection Customer may require Transmission Provider \nor its agent to utilize a consultant reasonably acceptable to Interconnection \nCustomer or MHVDC Connection Customer and Transmission Provider to \nperform such Interconnection Study under the direction of Transmission Provider.  \nAt other times, Transmission Provider may also utilize a consultant to perform"},{"page":319,"startToken":91514,"endToken":91845,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nsuch Interconnection Study, either in response to a general request of \nInterconnection Customer or MHVDC Connection Customer, or on its own \nvolition. \n \nIn all cases, use of a consultant shall be in accord with Article 26 of the GIA or \nZGIA (subcontractors), and, as applicable, FCA(s) and/or MPFCA(s) and limited \nto situations where Transmission Provider determines that doing so will help \nmaintain or accelerate the study process for the Interconnection Customer’s or \nMHVDC Connection Customer’s pending Interconnection Request and not \ninterfere with the Transmission Provider’s progress on Interconnection Studies for \nother pending Interconnection Requests.  In cases where Interconnection \nCustomer or MHVDC Connection Customer requests use of a consultant to \nperform such Interconnection Study, Interconnection Customer or MHVDC \nConnection Customer and Transmission Provider shall negotiate all of the \npertinent terms and conditions, including reimbursement arrangements and the \nestimated study completion date and study review deadline.  Transmission \nProvider shall convey all workpapers, data bases, study results and all other \nsupporting documentation prepared to date with respect to the Interconnection \nRequest as soon as soon as practicable upon Interconnection Customer’s or \nMHVDC Connection Customer’s request subject to the confidentiality provision \nin Section 13.1.  In any case, such consultant contract may be entered into with \neither Interconnection Customer or MHVDC Connection Customer or \nTransmission Provider at the Transmission Provider’s discretion.  In the case of \n(iii), Interconnection Customer or MHVDC Connection Customer maintains its \nright to submit a claim to Dispute Resolution to recover the costs of such \nconsultant study.  Such consultant shall be required to comply with the GIP, \nArticle 26 of the GIA (subcontractors), and, as applicable, FCA(s) and/or \nMPFCA(s), and the relevant Tariff procedures and protocols as would apply if \nTransmission Provider were to conduct the Interconnection Study and shall use \nthe information provided to it solely for purposes of performing such services and"},{"page":320,"startToken":91845,"endToken":92143,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nfor no other purposes.  Transmission Provider shall cooperate with such \nconsultant and Interconnection Customer or MHVDC Connection Customer to \ncomplete and issue the Interconnection Study in the shortest reasonable time. \n \n13.5 \nDisputes. \n \n13.5.1 Submission. \nIn the event any Party has a dispute, or asserts a claim, that arises out of or \nin connection with the GIA or ZGIA, or, as applicable, FCA(s) and/or \nMPFCA(s), the GIP, or their performance, such Party (the “disputing \nParty”) shall provide the other Parties with written notice of the dispute or \nclaim (“Notice of Dispute”).  Such dispute or claim shall be referred to a \ndesignated senior representative of each Party for resolution on an \ninformal basis as promptly as practicable after receipt of the Notice of \nDispute by the other Parties.  In the event the designated representatives \nare unable to resolve the claim or dispute through unassisted or assisted \nnegotiations within thirty (30) Calendar Days of the other non-disputing \nParties’ receipt of the Notice of Dispute, such claim or dispute shall be \nsubmitted in accordance with the dispute resolution procedures of the \nTariff.  In the event the designated representatives are able to resolve the \nclaim or dispute within the above-described thirty (30) Calendar Day \nperiod, the disputing Party shall submit a written explanation of the \nresolution to the non-disputing Parties and shall obtain the written \nacknowledgement and acceptance from each non-disputing Party. \n \nDisputes received after the GIA or ZGIA, or, as applicable, FCA(s) and/or \nMPFCA(s) has been tendered for execution pursuant to section 11.1 of this \nGIP will not affect any applicable deadline pursuant to Section 11.2 of this \nGIP."},{"page":321,"startToken":92143,"endToken":92493,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n13.5.2  Non-binding Dispute Resolution \n \nIf a Party has submitted a Notice of Dispute pursuant to section 13.5.1, \nand the Parties are unable to resolve the claim or dispute through \nunassisted or assisted negotiations within the thirty (30) Calendar Days \nprovided in that section, and the Parties cannot reach mutual agreement to \npursue binding dispute resolution, a Party may request that Transmission \nProvider engage in non-binding dispute resolution pursuant to this section \nby providing written notice to the Transmission Provider and other Party \n(“Request for Non-binding Dispute Resolution”).  Such request shall not \nrequire the agreement of any other Party to proceed.  The process set forth \nin this section shall serve as an alternative to, and not a replacement of, \nany other dispute resolution procedures contained within Attachment HH \nor otherwise authorized by the Tariff.  Within 30 days of receipt of a \nRequest for Non-binding Dispute Resolution pursuant to this Section, the \nTransmission Provider shall appoint a neutral decision-maker that is an \nindependent subcontractor that shall not have any current or past \nsubstantial business or financial relationships with either Party. Unless \notherwise agreed by the Parties, the decision-maker shall render a decision \nwithin sixty (60) Calendar Days of appointment and shall notify the \nParties in writing of such decision and reasons therefore.  Such decision-\nmaker shall be authorized only to interpret and apply the provisions of the \nGIP, GIA or ZGIA, and as applicable, FCA(s) and/or MPFCA(s), and \nshall have no power to modify or change any provision of the GIP, GIA, \nZGIA FCA(s) or MPFCA(s) in any manner.  The result reached in this \nprocess is not binding, but, unless otherwise agreed, the Parties may cite \nthe record and decision in this Nonbinding Dispute Resolution Process in \nfuture dispute resolution processes under the Tariff, including in \narbitration, or in a Federal Power Act section 206 complaint.  Each Party \nshall be responsible for its own costs incurred during the process and the"},{"page":322,"startToken":92493,"endToken":92767,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ncost of the decision-maker shall be divided equally among each Party to \nthe dispute.  Non-binding dispute resolutions conducted pursuant to this \nsection shall adhere to any procedural and timing requirements set forth in \nthe Generator Interconnection Business Practices Manual unless all parties \nto such dispute agree to modify such rules. \n \n13.6 \nLocal Furnishing Bonds. \n \n13.6.1 Transmission Owners That Own Facilities Financed by Local \nFurnishing Bonds. \nThis provision is applicable only to a Transmission Owner that has \nfinanced facilities for the local furnishing of electric energy with tax-\nexempt bonds, as described in Section 142(f) of the Internal Revenue \nCode (“local furnishing bonds”).  Notwithstanding any other provision of \nthe GIP or GIA, and, as applicable, ZGIA(s), FCA(s) and/or MPFCA(s), \nTransmission Provider and Transmission Owner shall not be required to \nprovide Interconnection Service to Interconnection Customer or MHVDC \nConnection Customer pursuant to this GIA or ZGIA and GIP if the \nprovision of such Transmission Service would jeopardize the tax-exempt \nstatus of any local furnishing bond(s) used to finance Transmission \nOwner’s facilities that would be used in providing such Interconnection \nService. \n \n13.6.2 Alternative Procedures for Requesting Interconnection Service. \nIf Transmission Provider determines that the provision of Interconnection \nService requested by Interconnection Customer or MHVDC Connection \nCustomer could jeopardize the tax-exempt status of any local furnishing \nbond(s) used to finance Transmission Owner’s facilities that would be \nused in providing such Interconnection Service.  Transmission Provider \nshall notify Transmission Owner who then shall confirm the tax-exempt"},{"page":323,"startToken":92767,"endToken":93059,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nstatus of any local furnishing bond(s) used by Transmission Owner and \nshall advise Interconnection Customer or MHVDC Connection Customer \nand Transmission Provider within thirty (30) Calendar Days of \nTransmission Provider’s notice to Transmission Owner.  Interconnection \nCustomer or MHVDC Connection Customer thereafter may renew its \nrequest for interconnection using the process specified in Article 5.2(ii) of \nthe Transmission Provider’s Tariff.  \n \nSECTION 14. \nFAST TRACK PROCESS. \n \n14.1 \nApplicability. \nThe Fast Track Process is available to an Interconnection Customer proposing to \ninterconnect its Small Generating Facility with the Transmission System if the \nSmall Generating Facility is no larger than 5 MW and if the Interconnection \nCustomer’s proposed Small Generating Facility meets the codes, standards, and \ncertification requirements of Appendix 3 of this GIP, or Transmission Provider has \nreviewed the design or tested the proposed Small Generating Facility and is \nsatisfied that it is safe to operate. \n \n14.1.1 Capacity of the Small Generating Facility \nThe Interconnection Request shall be evaluated using the maximum capacity that \nthe Small Generating Facility is capable of injecting into the Transmission \nProvider’s electric system.  However, if the maximum capacity that the Small \nGenerating Facility is capable of injecting into the Transmission Provider’s \nelectric system is limited (e.g., through use of a control system, power relay(s), or \nother similar device settings or adjustments), then the Interconnection Customer \nmust obtain the Transmission Provider’s agreement, with such agreement not to be \nunreasonably withheld, that the manner in which the Interconnection Customer \nproposes to implement such a limit will not adversely affect the safety and \nreliability of the Transmission Provider’s system.  If the Transmission Provider"},{"page":324,"startToken":93059,"endToken":93322,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ndoes not so agree, then the Interconnection Request must be withdrawn or revised \nto specify the maximum capacity that the Small Generating Facility is capable of \ninjecting into the Transmission Provider’s electric system without such limitations.  \nFurthermore, nothing in this section shall prevent a Transmission Provider from \nconsidering an output higher than the limited output, if appropriate, when \nevaluating system protection impacts. \n \n14.2 \nInitial Review. \nWithin fifteen (15) Business Days after Transmission Provider notifies \nInterconnection Customer it has received a complete Interconnection Request, \nTransmission Provider shall perform an initial review using the screens set forth \nbelow, shall notify Interconnection Customer of the results, and include with the \nnotification copies of the analysis and data underlying the Transmission Provider’s \ndeterminations under the screens. \n  \n14.2.1 Screens. \n \n14.2.1.1 The proposed Small Generating Facility’s Point of Interconnection \nmust be on a portion of the Transmission System or Distribution \nSystem that is subject to the Transmission Provider’s control under \nthe Tariff. \n \n14.2.1.2 For interconnection of a proposed Small Generating Facility to a \nradial distribution circuit, the aggregated generation, including the \nproposed Small Generating Facility, on the circuit shall not exceed \nfifteen percent (15%) of the line section annual peak load as most \nrecently measured at the relevant substation.  A line section is that \nportion of a Transmission Provider controlled electric system \nconnected to a customer bounded by automatic sectionalizing \ndevices or the end of the distribution line."},{"page":325,"startToken":93322,"endToken":93598,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \n14.2.1.3 For interconnection of a proposed Small Generating Facility to the \nload side of spot network protectors, the proposed Small \nGenerating Facility must use an inverter-based equipment package \nand, together with the aggregated other inverter-based generation, \nshall not exceed the smaller of five percent (5%) of a spot \nnetwork’s maximum load or 50 kW. \n \n14.2.1.4 The proposed Small Generating Facility, in aggregation with other \ngeneration on the distribution circuit, shall not contribute more \nthan ten percent (10%) to the distribution circuit’s maximum fault \ncurrent at the point on the high voltage (primary) level nearest the \nproposed point of change of ownership. \n \n14.2.1.5 The proposed Small Generating Facility, in aggregate with other \ngeneration on the distribution circuit, shall not cause any \ndistribution protective devices and equipment (including, but not \nlimited to, substation breakers, fuse cutouts, and line reclosers), or \nInterconnection Customer equipment on the system to exceed \neighty-seven and one half percent (87.5%) of the short circuit \ninterrupting capability; nor shall the interconnection proposed for a \ncircuit that already exceeds eighty-seven and one half (87.5%) of \nthe short circuit interrupting capability. \n \n14.2.1.6 Using the table below, determine the type of interconnection to a \nprimary distribution line.  This screen includes a review of the type \nof electrical service provided to the Interconnecting Customer, \nincluding line configuration and the transformer connection to \nlimit the potential for creating over-voltages on the Transmission \nProvider’s electric power system due to a loss of ground during the"},{"page":326,"startToken":93598,"endToken":93850,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\noperating time of any anti-islanding function. \n \nPrimary Distribution Line \nType \nType of Interconnection to Primary \nDistribution Line \nResult/Criteria \nThree-phase, three wire \n3-phase or single phase, phase-to-\nphase \nPass screen \nThree-phase, four wire \nEffectively-grounded 3 phase or \nSingle-phase, line-to-neutral \nPass screen \n \n14.2.1.7 If the proposed Small Generating Facility is to be interconnected \non single-phase shared secondary, the aggregate generation \ncapacity on the shared secondary, including the proposed Small \nGenerating Facility, shall not exceed 20 kW. \n \n14.2.1.8 If the proposed Small Generating Facility is single-phase and is to \nbe interconnected on a center tap neutral of a 240 volt service, its \naddition shall not create an imbalance between the two sides of the \n240 volt service of more than twenty percent (20%) of the \nnameplate rating of the service transformer. \n \n14.2.1.9 The Small Generating Facility, in aggregate with other generation \ninterconnected to the transmission side of a substation transformer \nfeeding the circuit where the Small Generating Facility proposes to \ninterconnect shall not exceed 10 MW in an area where there are \nknown, or posted, transient stability limitations to generating units \nlocated in the general electrical vicinity (e.g., three or four \ntransmission busses from the Point of Interconnection). \n \n14.2.1.10 No construction of facilities by Transmission Provider on its own \nsystem shall be required to accommodate the Small Generating \nFacility."},{"page":327,"startToken":93850,"endToken":94123,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n14.2.2 If the proposed interconnection passes the screens, the Interconnection \nRequest shall be approved and Transmission Provider will provide \nInterconnection Customer an executable interconnection agreement within \nfive (5) Business Days after the determination. \n \n14.2.3 If the proposed interconnection fails the screens, but Transmission Provider \ndetermines that the Small Generating Facility may nevertheless be \ninterconnected consistent with safety, reliability, and power quality \nstandards, Transmission Provider shall provide Interconnection Customer \nan executable interconnection agreement within five (5) Business Days \nafter the determination. \n \n14.2.4 If the proposed interconnection fails the screens, but Transmission Provider \ndoes not or cannot determine from the initial review that the Small \nGenerating Facility may nevertheless be interconnected consistent with \nsafety, reliability, and power quality standards unless Interconnection \nCustomer is willing to consider minor modifications or further study, \nTransmission Provider shall provide Interconnection Customer with the \nopportunity to attend a customer options meeting. \n \n14.3 Customer Options Meeting. \nIf Transmission Provider determines the Interconnection Request cannot be \napproved without (1) minor modifications at minimal cost, (2) a supplemental \nstudy or other additional studies or actions, or (3) incurring significant cost to \naddress safety, reliability, or power quality problems, the Transmission Provider \nshall notify Interconnection Customer of that determination within five (5) \nBusiness Days after that determination and provide copies of all data and analyses \nunderlying its conclusion.  Within ten (10) Business Days of the Transmission \nProvider’s determination, Transmission Provider shall offer to convene a customer \noptions meeting with Transmission Provider to review possible Interconnection"},{"page":328,"startToken":94123,"endToken":94390,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nCustomer facility modifications or the screen analysis and related results, to \ndetermine what further steps are needed to permit the Small Generating Facility to \nbe connected safely and reliably.  At the time of notification of the Transmission \nProvider’s determination, or at the customer options meeting, Transmission \nProvider shall: \n \n14.3.1 Offer to perform facility modifications or minor modifications to the \nTransmission System (e.g., changing meters, fuses, relay settings) and \nprovide a non-binding good faith estimate of the limited cost to make such \nmodifications to the Transmission System.  If the Interconnection \nCustomer agrees to pay for the modifications to the Transmission System, \nthe Transmission Provider will provide the Interconnection Customer with \nan executable interconnection agreement within ten (10) Business Days of \nthe customer options meeting; or \n \n14.3.2 Offer to perform a supplemental review in accordance with Section 14.4 \nand provide a non-binding good faith estimate of the costs of such review; \nor \n \n14.3.3 Obtain the Interconnection Customer’s agreement to continue evaluating \nthe Interconnection Request under the Attachment X Generator \nInterconnection Procedures. \n \n14.4 \nSupplemental Review. \n \n14.4.1 To accept the offer of a supplemental review, Interconnection Customer \nshall agree in writing and submit a deposit for the estimated costs of the \nsupplemental review in the amount of the Transmission Provider’s good \nfaith estimate of the costs of such review, both within 15 Business Days of \nthe offer.  If the written agreement and deposit have not been received by"},{"page":329,"startToken":94390,"endToken":94684,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nthe Transmission Provider within that timeframe, the Interconnection \nRequest shall continue to be evaluated under the Attachment X Generator \nInterconnection Procedures unless it is withdrawn by the Interconnection \nCustomer. \n \n14.4.2 The Interconnection Customer may specify the order in which the \nTransmission Provider will complete the screens in section 14.4.4. \n \n14.4.3 The Interconnection Customer shall be responsible for the Transmission \nProvider’s actual costs for conducting the supplemental review.  The \nInterconnection Customer must pay any review costs that exceed the \ndeposit within 20 Business Days of receipt of the invoice or resolution of \nany dispute.  If the deposit exceeds the invoiced costs, the Transmission \nProvider will return such excess within 20 Business Days of the invoice \nwithout interest. \n \n14.4.4 Within thirty (30) Business Days following receipt of the deposit for a \nsupplemental review, the Transmission Provider shall (1) perform a \nsupplemental review using the screens set forth below; (2) notify in \nwriting the Interconnection Customer of the results; and (3) include with \nthe notification copies of the analysis and data underlying the \nTransmission Provider’s determinations under the screens.  Unless the \nInterconnection Customer provided instructions for how to respond to the \nfailure of any of the supplemental review screens below at the time the \nInterconnection Customer accepted the offer of supplemental review, the \nTransmission Provider shall notify the Interconnection Customer \nfollowing the failure of any of the screens, or if it is unable to perform the \nscreen in section 14.4.4.1, within two Business Days of making such \ndetermination to obtain the Interconnection Customer’s permission to: (1) \ncontinue evaluating the proposed interconnection under this section"},{"page":330,"startToken":94684,"endToken":94959,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n14.4.4; (2) terminate the supplemental review and continue evaluating the \nSmall Generating Facility (the Attachment X Generator Interconnection \nProcedures); or (3) terminate the supplemental review upon withdrawal of \nthe Interconnection Request by the Interconnection Customer. \n \n14.4.4.1 Minimum Load Screen:  Where 12 months of line section \nminimum load data (including onsite load but not station service \nload served by the proposed Small Generating Facility) are \navailable, can be calculated, can be estimated from existing data, \nor determined from a power flow model, the aggregate \nGenerating Facility capacity on the line section is less than 100% \nof the minimum load for all line sections bounded by automatic \nsectionalizing devices upstream of the proposed Small \nGenerating Facility. If minimum load data is not available, or \ncannot be calculated, estimated or determined, the Transmission \nProvider shall include the reason(s) that it is unable to calculate, \nestimate or determine minimum load in its supplemental review \nresults notification under section 14.4.4. \n \n14.4.4.1.1 The type of generation used by the proposed Small \nGenerating Facility will be taken into account when \ncalculating, estimating, or determining circuit or line \nsection minimum load relevant for the application of \nscreen 14.4.1.1.  Solar photovoltaic (PV) generation \nsystems with no battery storage use daytime minimum \nload (i.e. 10 a.m. to 4 p.m. for fixed panel systems and 8 \na.m. to 6 p.m. for PV systems utilizing tracking \nsystems), while all other generation uses absolute \nminimum load."},{"page":331,"startToken":94959,"endToken":95221,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n14.4.4.1.2 When this screen is being applied to a Small Generating \nFacility that serves some station service load, only the \nnet injection into the Transmission Provider’s electric \nsystem will be considered as part of the aggregate \ngeneration. \n \n14.4.4.1.3 Transmission Provider will not consider as part of the \naggregate generation for purposes of this screen \ngenerating facility capacity known to be already \nreflected in the minimum load data. \n \n14.4.4.2 Voltage and Power Quality Screen:  In aggregate with existing \ngeneration on the line section: (1) the voltage regulation on the \nline section can be maintained in compliance with relevant \nrequirements under all system conditions; (2) the voltage \nfluctuation is within acceptable limits as defined by Institute of \nElectrical and Electronics Engineers (IEEE) Standard 1453, or \nutility practice similar to IEEE Standard 1453; and (3) the \nharmonic levels meet IEEE Standard 519 limits. \n \n14.4.4.3 Safety and Reliability Screen:  The location of the proposed \nSmall Generating Facility and the aggregate generation capacity \non the line section do not create impacts to safety or reliability \nthat cannot be adequately addressed without application of the \nStudy Process.  The Transmission Provider shall give due \nconsideration to the following and other factors in determining \npotential impacts to safety and reliability in applying this screen. \n \n14.4.4.3.1 Whether the line section has significant minimum \nloading levels dominated by a small number of"},{"page":332,"startToken":95221,"endToken":95433,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ncustomers (e.g., several large commercial customers). \n \n14.4.4.3.2 Whether the loading along the line section is uniform or \neven. \n \n14.4.4.3.3 Whether the proposed Small Generating Facility is \nlocated in close proximity to the substation (i.e., less \nthan 2.5 electrical circuit miles), and whether the line \nsection from the substation to the Point of \nInterconnection is a Mainline rated for normal and \nemergency ampacity. \n \n14.4.4.3.4 Whether the proposed Small Generating Facility \nincorporates a time delay function to prevent \nreconnection of the generator to the system until system \nvoltage and frequency are within normal limits for a \nprescribed time. \n \n14.4.4.3.5 Whether operational flexibility is reduced by the \nproposed Small Generating Facility, such that transfer of \nthe line section(s) of the Small Generating Facility to a \nneighboring distribution circuit/substation may trigger \noverloads or voltage issues. \n \n14.4.4.3.6 Whether the proposed Small Generating Facility \nemploys equipment or systems certified by a recognized \nstandards organization to address technical issues such \nas, but not limited to, islanding, reverse power flow, or \nvoltage quality."},{"page":333,"startToken":95433,"endToken":95729,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n14.4.5 If the proposed interconnection passes the supplemental screens in \nsections 14.4.4.1, 14.4.4.2, and 14.4.4.3 above, the Interconnection \nRequest shall be approved and the Transmission Provider will provide the \nInterconnection Customer with an executable interconnection agreement \nwithin the timeframes established in sections 14.4.5.1 and 14.4.5.2 below.  \nIf the proposed interconnection fails any of the supplemental review \nscreens and the Interconnection Customer does not withdraw its \nInterconnection Request, it shall continue to be evaluated under the \nAttachment X Generator Interconnection Procedures consistent with \nsection 14.4.5.3 below. \n \n14.4.5.1 If the proposed interconnection passes the supplemental screens \nin sections 14.4.1.1, 14.4.1.2, and 14.4.1.3 above and does not \nrequire construction of facilities by the Transmission Provider on \nits own system, the interconnection agreement shall be provided \nwithin ten Business Days after the notification of the \nsupplemental review results.  \n \n14.4.5.2 If interconnection facilities or minor modifications to the \nTransmission Provider’s system are required for the proposed \ninterconnection to pass the supplemental screens in sections \n14.4.1.1, 14.4.1.2, and 14.4.1.3 above, and the Interconnection \nCustomer agrees to pay for the modifications to the Transmission \nProvider’s electric system, the interconnection agreement, along \nwith a non-binding good faith estimate for the interconnection \nfacilities and/or minor modifications, shall be provided to the \nInterconnection Customer within 15 Business Days after \nreceiving written notification of the supplemental review results.  \n \n14.4.5.3 If the proposed interconnection would require more than"},{"page":334,"startToken":95729,"endToken":96021,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\ninterconnection facilities or minor modifications to the \nTransmission Provider’s system to pass the supplemental screens \nin sections 14.4.1.1, 14.4.1.2, and 14.4.1.3 above, the \nTransmission Provider shall notify the Interconnection Customer, \nat the same time it notifies the Interconnection Customer with the \nsupplemental review results, that the Interconnection Request \nshall be evaluated under the Attachment X Generator \nInterconnection Procedures unless the Interconnection Customer \nwithdraws its Small Generating Facility. \n \nSECTION 15. \nPROVISIONS FOR CONNECTION TO HVDC FACILITIES \nSUBJECT TO SECTION 27A OF THE TARIFF. \n \nInterconnection Requests to HVDC Facilities that are subject to Section 27A of the Tariff \nshall follow the same process as detailed in Sections 2 through 13 of the GIP, except as specified \nin this Section 15. \n \n15.1 \nAvailability of ER Interconnection Service and NR Interconnection Service \nfor HVDC Facilities subject to Section 27A of this Tariff. \n \nER Interconnection Service and NR Interconnection Service are both available for \nHVDC Facilities subject to Section 27A of this Tariff.  In the case where \nInterconnection Customer identified a point-to-point transmission service request \nunder Section 27A of this Tariff, NR Interconnection Service will qualify the \nGenerating Facility to be designated as a Network Resource so long as (and to the \nextent that) HVDC Service is confirmed across the HVDC Facilities.  NR \nInterconnection Service will be limited to the confirmed megawatts in the \ntransmission service request.  When applicable, the HVDC Service requirement \nwill be listed in Appendix A of the GIA, and such listing will be added during the \nnegotiation phase of the document, as set forth in Section 11.2 of the GIP."},{"page":335,"startToken":96021,"endToken":96296,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\n \nSECTION 16.  \nPROVISIONS FOR OBTAINING INJECTION RIGHTS AND \nTHEIR CONVERSION TO EXTERNAL NETWORK RESOURCE \nINTERCONNECTION SERVICE  \n \n16.1 \nRequest for Injection Rights \n \nMHDVC Connection Customers electing to request Injection Rights on the Transmission \nSystem pursuant to the procedures set forth in Section 3.2.3 of Attachment GGG to the Tariff \nshall make such requests for Injection Rights by submitting to Transmission Provider a \ncompleted Interconnection Request in the manner specified by the Generator Interconnection \nBusiness Practices Manual (BPM-015).  The MHVDC Connection Customer must select \n“Injection Rights” in Appendix 1 and shall include all other relevant information required by \nAppendix 1 and its attachments.  Requests for Injection Rights shall be studied and granted by \nTransmission Provider pursuant to the terms and conditions of the GIP, including requisite \nmilestones and study deposits within the prescribed schedule deadlines. \n \nInjection Rights serve as a pre-certification of the Transmission System’s capability to \nreceive capacity and energy from the MHVDC Transmission Line at the requested Point of \nConnection, in the specified MW quantity, without degrading the reliability of the Transmission \nSystem.  Injection Rights do not convey transmission service or Interconnection Service to the \nMHVDC Connection Customer or any other entity.  Any such Injection Rights granted by \nTransmission Provider, and any increases or reductions to those Injection Rights, shall be \ndocumented in Appendix F to the Transmission Connection Agreement.  Requests for Injection \nRights will be treated similar to requests for Interconnection Service from a queue priority \nperspective. \n \n16.2 \nConversion of Injection Rights to External Network Resource \nInterconnection Service"},{"page":336,"startToken":96296,"endToken":96612,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nBefore an Interconnection Customer with an Existing Generating Facility that is external \nto the Transmission System may offer energy or capacity across the MHVDC Transmission Line \ninto the MISO markets, the Injection Rights granted pursuant to Section 3.2.3 of Attachment \nGGG to the Tariff and this Section 16 must be converted to external Network Resource \nInterconnection Service and transferred to that Interconnection Customer.  Upon the request of \nan Interconnection Customer with an Existing Generating Facility for external Network \nResource Interconnection Service via the MHVDC Transmission Line, Transmission Provider \nwill convert the Injection Rights to external Network Resource Interconnection Service in an \namount up to, but not greater than, the capacity of the MHVDC Transmission Line, and transfer \nthat amount of external Network Resource Interconnection Service to that Interconnection \nCustomer, subject to the conditions set forth below. \n \nPrior to effectuating this conversion, Transmission Provider must receive the following \ninformation:  \n(a) from the Interconnection Customer seeking conversion: \n(i) \na request for external Network Resource Interconnection Service pursuant to \nAppendix 1 of Attachment X, by including the requested MW quantity to be \nconverted and transferred; \n(ii) \ndocumentation of the agreement between the Interconnection Customer and \nthe MHVDC Connection Customer authorizing the conversion and transfer of \nthe requested amount of Injection Rights;  \n(iii) \ndocumentation that the Interconnection Customer has long-term firm \ntransmission service from the Existing Generating Facility to the Point of \nConnection, including any transmission service agreements over the MHVDC \nTransmission Line, that complies with the requirements included in the \nService Agreement for Network Resources Interconnection Service for an \nExisting Generating Facility as set forth in Appendix 13 of Attachment X; and \n(b) from the MHVDC Connection Customer that holds the Injection Rights being \nconverted: \n(i) \ndocumentation of the MHVDC Connection Customer’s procedures for the"},{"page":337,"startToken":96612,"endToken":96951,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nallocation of Injection Rights to Interconnection Customers, which shall be \nnon-discriminatory and consistent with the Commission’s approval of the \nMHVDC Connection Customer’s right to charge negotiated (market based) \nrates for service on the applicable MHVDC Transmission Line. \n \nUpon receipt of the required information, Transmission Provider will convert the \nrequested amount of the MHVDC Connection Customer’s Injection Rights into external \nNetwork Resource Interconnection Service and grant the external Network Resource \nInterconnection Service to the Interconnection Customer, subject to the Interconnection \nCustomer executing the Service Agreement for external Network Resource Interconnection \nService for an Existing Generating Facility as set forth in Appendix 13 to Attachment X.  All \nterms and conditions of such Service Agreement for external Network Resource Interconnection \nService for an Existing Generating Facility and all the terms and conditions of Attachment X, \nincluding the rights to termination of Interconnection Service, shall apply to the Interconnection \nCustomer’s external Network Resource Interconnection Service granted under this Article 16.  \nAfter conversion of the Injection Rights, Transmission Provider shall document any remaining \nInjection Rights in Appendix F of the MHVDC Connection Customer’s Transmission \nConnection Agreement and shall post the Interconnection Customer’s external Network \nResource Interconnection Service pursuant to the posting guidelines contained in Attachment X. \n \nA request by an Interconnection Customer for a conversion of Injection Rights into \nexternal Network Resource Interconnection Service pursuant to this Section 16.2, shall not \nrequire any additional studies in the Definitive Planning Phase to the extent such studies have \nbeen performed as part of the MHVDC Connection Customer’s request for Injection Rights.  To \nthe extent the MHVDC Connection Customer made the Definitive Planning Phase Milestone \nPayments (M2, M3, and M4) required in connection with its request for Injection Rights and \nevaluation, an Interconnection Customer obtaining a conversion to external Network Resource \nInterconnection Service based on the same request for Injection Rights shall not be required to \nmake any additional Milestone Payments to Transmission Provider."},{"page":338,"startToken":96951,"endToken":97246,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nAny conversion to external Network Resource Interconnection Service under this Section \n16.2 shall occur within three (3) years from the Commercial Operation Date for the MHVDC \nTransmission Line, as set forth in Appendix C of the Transmission Connection Agreement.  \nFailure to convert any amount of the Injection Rights to external Network Resource \nInterconnection Service within the time period specified above shall result in termination of \nInjection Rights with respect to such unconverted amount.  In the event any external Network \nResource Interconnection Service obtained pursuant to this Section 16 terminates more than \nthree (3) years after the Commercial Operation Date for the MHVDC Transmission Line, as set \nforth in Appendix C of the Transmission Connection Agreement, such terminated external \nNetwork Resource Interconnection Service may not revert back to Injection Rights.  \n \nSECTION 17.  \nFACILITIES SERVICE AGREEMENT. \nIn the event that the Transmission Owner elects to fund the capital for the Network \nUpgrades and the Transmission Owner’s System Protection Facilities, the Interconnection \nCustomer, Transmission Owner, and Transmission Provider shall enter into a Facilities Service \nAgreement to memorialize the terms of repayment for those Network Upgrades and \nTransmission Owner’s System Protection Facilities that the Transmission Owner elected to self-\nfund.  The Facilities Service Agreement shall take the form of the pro forma Facilities Service \nAgreement that is included as Appendix 14 of Attachment X of the MISO Tariff.  The Facilities \nService Agreement shall be subject to the terms and conditions of Attachment X, including the \nrights to termination of Interconnection Service.  The Interconnection Customer and/or the \nTransmission Owner may request in writing that Transmission Provider file the Facilities Service \nAgreement with FERC in unexecuted form."},{"page":339,"startToken":97246,"endToken":97400,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nAPPENDICES TO GIP \n \nAPPENDIX 1 \nINTERCONNECTION REQUEST FOR A GENERATING FACILITY  \nAPPENDIX 2 \nRESERVED \nAPPENDIX 3 \nCERTIFICATION CODES AND STANDARDS AND CERTIFICATION \nOF SMALL GENERATOR EQUIPMENT PACKAGES \nAPPENDIX 4 \nAPPLICATION, PROCEDURES, AND TERMS AND CONDITIONS \nFOR INTERCONNECTING A CERTIFIED INVERTER-BASED \nSMALL GENERATING FACILITY NO LARGER THAN 10 KW (“10 \nKW INVERTER PROCESS”) \nAPPENDIX 5 \nOPTIONAL INTERCONNECTION STUDY AGREEMENT \nAPPENDIX 6 \nSTANDARD GENERATOR INTERCONNECTION AGREEMENT \nAPPENDIX 7 \nINTERCONNECTION PROCEDURES FOR A WIND GENERATING \nPLANT \nAPPENDIX 8 \nFACILITIES CONSTRUCTION AGREEMENT \nAPPENDIX 9 \nMULTI-PARTY FACILITIES CONSTRUCTION AGREEMENT \nAPPENDIX 10 \nINTERCONNECTION STUDY MODEL REVIEW FORM \nAPPENDIX 11 \nMONITORING AND CONSENT AGREEMENT \nAPPENDIX 12 \nENERGY DISPLACEMENT AGREEMENT \nAPPENDIX 13 \nEXTERNAL NETWORK RESOURCE INTERCONNECTION \nSERVICE AGREEMENT \nAPPENDIX 14 \nFACILITIES SERVICE AGREEMENT \nAPPENDIX 15  \nRESERVED \nAPPENDIX 16 \nAFFECTED SYSTEM STUDY AGREEMENT \nAPPENDIX 17  \nAFFECTED SYSTEM NETWORK UPGRADE FACILITIES STUDY"},{"page":340,"startToken":97400,"endToken":97433,"text":"MISO \nATTACHMENT X\nFERC Electric Tariff \nGenerator Interconnection Procedures (GIP)\nATTACHMENTS \n188.0.0, 190.0.0\nEffective On: October 18, 2026\nAGREEMENT \nAPPENDIX 18 \nJTIQ COMMITMENT AGREEMENT \nAPPENDIX 19 \nZG INTERCONNECTION AGREEMENT"},{"page":341,"startToken":97433,"endToken":97655,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nAPPENDIX 1 TO GIP\nINTERCONNECTION REQUEST\n1.\n[The undersigned Interconnection Customer submits this request to interconnect its \nGenerating Facility, located in ______________ County, [             State], with the Transmission \nSystem pursuant to the Tariff.] or;\n[The undersigned MHVDC Connection Customer submits this request for Injection Rights for its \nMHVDC Transmission Line, located in ______________ County, [             State], with the \nTransmission System pursuant to a Tariff.];\n2.\nThis Interconnection Request is for (check one):\n_____\nProposed new Generating Facility\n_____\nIncrease in the generating capacity or a Material Modification of an Existing \nGenerating Facility\n_____\nReplacement of Existing Generating Facility with no increase in capacity\n_____\nInterconnection Request made in connection with a Generating Facility \nproposed for inclusion in a resource solicitation process\n_____\nNetwork Resource Interconnection Service for a Generating Facility in \nCommercial Operation or with an executed GIA\n_____\nGenerating Facility requesting Surplus Interconnection Service\n_____\nFast Track Process for Small Generating Facility\n_____\nInjection Rights associated with a new MHVDC Transmission Line\n_____\nExpedited Resource Addition Study\n_____\nGenerating Facility requesting ZG Interconnection Service; \n3.\nThe type of interconnection service requested is (check one as appropriate):\n_____\nEnergy Resource Interconnection Service only\n_____\nNetwork Resource Interconnection Service (includes Energy Resource \nInterconnection Service)\n_____\nNetwork Resource Interconnection Service only for an Existing Generating"},{"page":342,"startToken":97655,"endToken":97839,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nFacility\n_____\nNetwork Resource Interconnection Service in connection with a resource \nsolicitation process\n_____\nSurplus Interconnection Service\n_____\nExternal Network Resource Interconnection Service (E-NRIS) for projects \nconnecting to a Distribution System or non-MISO transmission system;\n_____\nZG Interconnection Service for a Generating Facility with ZG Associated \nLoad;\n4.\nInterconnection Customer provides the following definitive information:\na.\nSpecific address or location (use closest street or intersection if no address is \navailable) for the proposed new Generating Facility site or, in the case of an \nExisting Generating Facility, the name and specific location of the Existing \nGenerating Facility (provide a site map and GPS coordinates);\nAddress: \nCity:\nState:\nZip Code:\nGPS Coordinates:\nN\nW\nb.\nThe following specific information related to the Interconnection Service \nRequested:\nRequired Information Related to Interconnection \nRequest\nAdditional \nInformation/Documentation\nInstalled Generating \nFacility Capacity \n(Maximum Gross \nOutput)\nSummer \n(MW/MVAR): \n____/____\nWinter \n(MW/MVAR): \n____/____\n \nExisting \nInterconnection \nERIS: \n(MW/MVAR):\nNRIS: \n(MW/MVAR): \nProvide GIA, and SIS report for \nExisting Generating Facility"},{"page":343,"startToken":97839,"endToken":98051,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nService, if any\n____/____\n____/____\nNew Interconnection \nService or Increase in \nExisting \nInterconnection \nService Requested \n(Maximum Injection \nat POI)\nERIS (New)\n(MW/MVAR): \n____/____\nor\nERIS (Increase)\n(MW/MVAR): \n____/____\nNRIS (New)\n(MW/MVAR): \n____/____\nor\nNRIS (Increase)\n(MW/MVAR): \n____/____\nRequested total ERIS must be less \nthan or equal to Installed \nGenerating Facility Capacity.  \nRequested total NRIS must be less \nthan or equal to total requested \nERIS.\nStation Service Load, \nif any\nSummer \n(MW/MVAR): \n____/____\nWinter \n(MW/MVAR): \n____/____\n \nSurplus \nInterconnection \nService Requested \n(No increase in \nExisting \nInterconnection \nService)\nSurplus \nInterconnection \nService\n(MW/MVAR):\n____/____\nSIS report for existing unit and \nwritten statement pursuant to \nSection 6 of this Interconnection \nRequest\n“NRIS only”/ \nExternal NRIS\n NRIS Only\n(MW/MVAR):\n____/____\nExternal-NRIS\n(MW/MVAR):\n____/____\nCP Node: \n____________                             \nPoint of Interconnection: \n____________                                \nBus Number in Power Flow \nModels: ____________\nZG Interconnection \nService Requested\nZG \nInterconnection \nService\n(MW/MVAR):\n____/____\nThe amount of ZG Interconnection \nService is limited to and shall not \nexceed the total Demand of the \nZG Associated Load for that \nGenerating Facility.\nc.\nA description of the equipment configuration (i.e. Number of generators/inverters \nand number of Intermediate Step-up transformers, is this phase 2 of an existing"},{"page":344,"startToken":98051,"endToken":98218,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nproject, etc.) for the entire Generating Facility:\nd.\nGenerating Facility Commercial Operation Date______________, \nSynchronization Date______________, and required Interconnection Facilities \nIn-Service Date_______________ by day, month, and year;\ne. \nName, address, telephone number, and e-mail address of the Interconnection \nCustomer.  If the Interconnection Customer has designated an agent, include its \nagent’s contact person:\nInterconnection Customer\nCompany Name:_________________________________________________\nAddress:_______________________________________________________\nCity:_________________________ State:_____________ Zip:___________\nPhone:________________________Email:____________________________\nInterconnection Customer’s Agent (if applicable)\nCompany Name:________________________________________________\nAddress:_______________________________________________________\nCity:_________________________ State:_____________ Zip:___________\nPhone:________________________Email:___________________________\nAgent’s contact person:\n    ;\nf. \nAn Internal Revenue Service Form W-9 or comparable state-issued document for \nthe Interconnection Customer submitting this Interconnection Request;  \ng. \nAs applicable, documentation proving the existence of a legally-binding \nrelationship between the Interconnection Customer and any entity with a vested \ninterest in this Interconnection Request (e.g., a parent company, a subsidiary, or \nfinancing company acting as agent for the Interconnection Customer) that the"},{"page":345,"startToken":98218,"endToken":98403,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nInterconnection Customer reasonably anticipates may claim rights or authority \nunder this Interconnection Request.  Such documentation may include but is not \nlimited to the Interconnection Customer’s Articles of Organization and Operating \nAgreement describing the nature of the legally-binding relationship;\nh.\nInterconnection Customer’s banking information, or the banking information of \nany entity with a legally-binding relationship to the Interconnection Customer, in \naccordance with Section 4(f) of this Appendix 1, that wishes to make payments \nand receive refunds on behalf of the Interconnection Customer and in association \nwith this Interconnection Request;\nBank Name:\nAccount Holder Name:\nABA number:\nAccount Number:\nCompany:\nTax Reporting Name:\nTax ID:\nAddress:\nCity:\nState:\nZip:\nPhone:\nEmail:\ni.\nLocation of the proposed Point of Interconnection including the substation name \nor the name of the line to be tapped (including the voltage), the estimated distance \nfrom the substation endpoints of a line tap, address, and GPS coordinates (Not \napplicable to External NRIS Applications) \nPOI substation name:\n or"},{"page":346,"startToken":98403,"endToken":98579,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nPOI line name: \n(endpoint 1) to\n(endpoint 2)\nPOI Distance from endpoint 1: \nmiles\nPOI Distance from endpoint 2: \nmiles\nInterconnection voltage: \nkV\nAddress: \nCity:\nState:\nZip Code:\nGPS Coordinates:\nN\n        W\nj. \nGenerating Facility Data (set forth in Attachment A);\nk.\n Fuel Source(s) [Check all that are applicable]:\n□ Coal \n□ Nuclear \n□ Storage, specify type: _________\n□ Hydro \n□ Oil\n□ Wind\n□ Natural Gas\n□ Solar\n□ Other, specify type: _________\nDescribe the configuration of Generating Facility utilizing more than one fuel \nsource:\n___________________________________________\n___________________________________________;\nIf the proposed Generating Facility includes storage device(s), indicate whether \nthe storage device(s) will be charged using energy from the Transmission System \nat any time: Yes _____ or No _____. If Yes, specify maximum MW that will be \nwithdrawn from the Transmission System at any time: _____MW.  If Yes, specify \nthe peak load charging case (check one):\n____ Will charge in the peak load study case \n____ Will not charge in the peak load study case;"},{"page":347,"startToken":98579,"endToken":98853,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nl.\nQualifying Facility status including an indication of state and / or federal \nqualifications that have been met (optional); \nm.\nIf this Interconnection Request is made in connection with a resource solicitation \nprocess, attach a copy of a written agreement assigning the Interconnection \nCustomer’s rights under the GIP to the solicitor of the process and granting the \nsolicitor the right to act as the Interconnection Customer’s agent for all purposes \nin the GIP;\nn.\nIf this Interconnection Request is for Surplus Interconnection Service, attach a \ncopy of the MISO Interconnection System Impact Study performed for the \nExisting Generating Facility when the Generating Facility was originally \nproposed for interconnection to the MISO Transmission System or, for \nGenerating Facilities studied under a predecessor transmission provider’s \ninterconnection process, the original system impact study performed at the time \nsuch Generating Facility was originally studied for interconnection to the \ntransmission system.  If no such study is available, indicate this by checking the \nappropriate box below.\n□\nStudy Attached (if this box is checked, a copy of the study must be \nincluded as an attachment to this Interconnection Request); or\n□\nNo previous study is available; \no. \nEnergy Displacement Agreement (Appendix 12) and Monitoring and Consent \nAgreement (Appendix 11).  In order for a surplus Interconnection Request to \nremain valid, the Energy Displacement Agreement and Monitoring and Consent \nAgreement must be submitted prior to the conclusion of Generator \nInterconnection Agreement negotiations, pursuant to Section 11 of this GIP;\np.\nPrimary frequency response operating range for electric storage resources;"},{"page":348,"startToken":98853,"endToken":99115,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nq.\nIf this Interconnection Request is for Generating Facility Replacement, \nInterconnection Customer must submit: \nPlanned or Actual date of cessation of operation for the Existing Generating \nFacility:______________________\nExpected Commercial Operation Date for the Replacement Generating \nFacility:______________________\n_____ (check if applicable) Interconnection Customer requests MISO to perform \nAttachment Y equivalent study in the Reliability Assessment Study;\nr.\nFor Interconnection Requests proposing to share Interconnection Customer \nInterconnection Facilities with another Interconnection Request or existing \nproject, a consent agreement meeting the requirements of Section 3.3.1.4 of the \nGIP and the Generator Interconnection Business Practices Manual executed by all \nInterconnection Customers affiliated with projects that propose to connect, or are \nconnected, to the shared Interconnection Customer Interconnection Facilities.\n_____ (check if applicable) Interconnection Customer proposes either to (1) \nshare Interconnection Customer Interconnection Facilities with a separate \nInterconnection Request or existing project and has attached a fully \nexecuted consent agreement to this Interconnection Request or; (2) share a \nsingle Interconnection Request with another Interconnection Customer \nusing a Shared Interconnection Request.\nIf Interconnection Customer Interconnection Facilities will be shared, the \nMISO Project Number(s) of other Existing Generating Facilities or \nInterconnection Requests with which Interconnection Customer \nInterconnection Facilities will be shared shall be listed below.  If no \nproject number is available for any of the other Generating Facilities with \nwhich Interconnection Customer Interconnection Facilities will be shared, \nstate the name of the Interconnection Customer and describe the \napplicable Generating Facilities below."},{"page":349,"startToken":99115,"endToken":99344,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\ns.\nFor Interconnection Requests seeking processing through an Expedited Resource \nAddition Study, identify the resource adequacy deficiency (i.e. the county and \nstate, the associated electrical bus location(s), the Local Resource Zone, and the \npeak MW demand of the load and/or reliability need) that the Generating Facility \nclaims to address, the RERRA (if applicable), and include the location of the \nGenerating Facility (i.e. county and state, the associated electrical bus location(s), \nand the Local Resource Zone).\n__________________________________________________________________\n__________________________________________________________________\n________________________________________________________________\n5.\nInterconnection Customer shall provide the applicable deposit amount as specified in the \nGIP;\n 6.\nIf this Interconnection Request is submitted to request Surplus Interconnection Service, \nthe undersigned Interconnection Customer shall supply a written statement from an \nofficer of the Existing Generating Facility that is associated with this request for Surplus \nInterconnection Service that confirms the following:\n(i.)\nthe amount of Surplus Interconnection Service made available by the \nInterconnection Customer of the Existing Generating Facility;\n(ii.)\nthe type of Interconnection Service (i.e., ERIS or NRIS) made available by the \nInterconnection Customer for the Existing Generating Facility in accordance with \nthe provisions in Section 3.2.3.1 of GIP (Attachment X); and\n(iii.)\nthe circumstances under which the proposed Surplus Interconnection Service"},{"page":350,"startToken":99344,"endToken":99612,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nwould be available, including an indication of whether the proposed \nInterconnection Service would be available on a continuous basis (i.e., a certain \nnumber of MW of Surplus Interconnection Service would always be available for \nuse by a co-located generating facility) or on a scheduled, periodic basis (i.e., a \nspecified number of MW of Surplus Interconnection Service that would be \navailable intermittently);\n7.\nEvidence of Site Control as specified in the GIP (check one)\n____\nIs attached to this Interconnection Request \n____\nWill be provided at a later date in accordance with the GIP;\n8.\nThis Interconnection Request shall be submitted electronically to the Transmission \nProvider in the manner specified by the Generator Interconnection Business Practices \nManual (BPM-015).; \n9. \nBy submitting the Interconnection Request, the Interconnection Customer represents that \nthe Generating Facility shall, upon Commercial Operation, connect exclusively to the \nTransmission Provider’s Transmission System.  Interconnection Customer shall not \nconnect or seek to connect the Generating Facility to another transmission provider’s \ntransmission system except as may be expressly allowed by the Transmission Provider’ \nTariff.;\n10.\nFor ZG Interconnection Service, a description of the ZG Associated Load and facilities to \nconnect to, along with any System Protection Facilities and/or proposed operating \nprocedures to prevent injections onto the Transmission System beyond the substation \nwhere the Point of Interconnection is located.  This shall include the need-by date for \nsuch ZG Associated Load.;\n11.\nPrimary Representative of Interconnection Customer to contact:\n[To be completed by Interconnection Customer]"},{"page":351,"startToken":99612,"endToken":99665,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nName:\nAddress:_______________________________________________\nCity:___________________ State:___________ Zip:___________\nPhone:__________________ Email:_________________________;\n1112. This Interconnection Request is submitted by:\n[Name of Interconnection Customer Company]\nBy (signature):  \nName (type or print):  \nTitle:  \nDate:"},{"page":352,"startToken":99665,"endToken":99840,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nAttachment A to Appendix 1\nInterconnection Request\nGENERATING FACILITY DATA\nA. Unit Ratings\n1. Total Generator Rated Output (MW)\n2. Rated MVA\n3. Number of Generating units (repeat items 3-11 for each type of generator)\n4. Individual generator rated output (MW) \n5. Individual generator rated MVA \n6. Manufacturer \n7. Year manufactured*\n8. Nominal terminal voltage (kV)\n9. Minimum Short Circuit Ratio for turbine operation\n10. Rated power factor \nRefer:\ni.\nFERC Order No. 827\nhttps://www.ferc.gov/whats-new/comm-meet/2016/061616/E-1.pdf \nii.\nMISO TO power factor requirements\nhttps://cdn.misoenergy.org/Reactive_Generator_Requirements108137.p\ndf\n11. Generator Voltage Regulation range (+/-)\n12. Generator Power Factor Regulation range (+/-)\n13. Primary frequency response operating range for electric storage resources:\ni.\nMinimum state of charge:\nii.\nMaximum state of charge:\n14. Type (Induction, Synchronous, D.C. with Inverter)\n15. Connection (Delta, Grounded WYE, Undergrounded WYE, Impedance  \nGrounded)\n*If available"},{"page":353,"startToken":99840,"endToken":100016,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nA-1.  Generator Short Circuit Information*\n(Provide following reactances in p.u. on the generator base)\n1. X’’1—Positive sequence sub transient reactance (p.u.)\n2. X2—Negative sequence reactance (p.u.)\n3. X0—Zero sequence reactance (p.u)\n4. Generator grounding: \n      4.a. Solidly grounded (yes/no)\n      4.b. Grounded through an impedance (yes/no) \n              If yes: R_____ p.u.    X_____p.u. \n      4.c. Ungrounded\nA-2.  Main Generator Step-up Up (GSU) Transformer\n(Please fill out data in table below for each GSU transformer)\nNumber of Transformers __________\nRATINGS\nSelf-Cooled\nMaximum \nNameplate\nCapacity (kVA)\nGenerator Side\nSystem Side\nTertiary\nVoltage Ratio (kV)\nLow Voltage\nHigh Voltage\nTertiary Voltage\nWinding \nConnections (Delta \nor Wye)\nIMPEDANCE\nPrimary-Secondary\nPrimary-Tertiary\nSecondary-Tertiary\nPositive Z1 (on \nself-cooled kVA \nrating)\n         %         X/R\n         %         X/R\n         %         X/R\nZero Z0 (on self-\ncooled kVA rating)\n         %         X/R\n         %         X/R\n         %         X/R\nFixed Taps \nAvailable\nPresent Tap \nAvailable\nTAP SETTING"},{"page":354,"startToken":100016,"endToken":100122,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nA-3.  Pad Mount Transformer\n(Please fill out data in table below for each GSU transformer)\nNumber of Transformers __________\nRATINGS\nSelf-Cooled\nMaximum \nNameplate\nCapacity (kVA)\nGenerator Side\nSystem Side\nTertiary\nVoltage Ratio (kV)\nLow Voltage\nHigh Voltage\nTertiary Voltage\nWinding \nConnections (Delta \nor Wye)\nIMEPDANCE\nPrimary-Secondary\nPrimary-Tertiary\nSecondary-Tertiary\nPositive Z1 (on \nself-cooled kVA \nrating)\n         %         X/R\n         %         X/R\n         %         X/R\nZero Z0 (on self-\ncooled kVA rating)\n         %         X/R\n         %         X/R\n         %         X/R\nFixed Taps \nAvailable\nPresent Tap \nAvailable\nTAP SETTING"},{"page":355,"startToken":100122,"endToken":100371,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nA-4.  Interconnection Facilities Tie Line Information\n(Only list data for lines that are to be added by the generation developer)\n1. Nominal Voltage (kV) \n2.\nLine length (miles)\n3. Line termination points\n1.\n2.\n4. Conductor Type/Size (kcm)\n5. Phase Configuration (Vertical or Horizontal)\n6. Summer line ratings in amperes (MVA)\n7. Positive sequence resistance (R) for entire length (in p.u.*)\n8. Positive sequence reactance (X) for entire length (in p.u.*)\n9. Zero sequence resistance (R0) for entire length (in p.u.*)\n10. Zero sequence reactance (X0) for entire length (in p.u.*)\n11.  Positive sequence line charging (B) for the entire length (in \np.u.*)\n* On 100-MVA and nominal line voltage (kV) Base\nFor wind/photovoltaic plants, provide System Equivalence Impedance Data. (Provide \nvalues for each equivalence collector circuit at all voltage levels. Equivalent collector \nsystem impedance does not include pad mount impedance)\n1. Nominal Voltage (kV) \n2.\nSummer line ratings in amperes (MVA) \n3. Positive sequence resistance (R) for entire length (in p.u.*)\n4. Positive sequence reactance (X) for entire length (in p.u.*)\n5. Zero sequence resistance (R0) for entire length (in p.u.*)\n6. Zero sequence reactance (X0) for entire length (in p.u.*)\n7. Positive sequence line charging (B) for the entire length (in p.u.*)\n* On 100-MVA and nominal line voltage (kV) Base"},{"page":356,"startToken":100371,"endToken":100645,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nA-5.  Dynamic Modeling Information\nFor a synchronous Generating Facility, the Interconnection Customer is to provide the \nappropriate PSS/E library model in the form of a Siemens PTI PSS/E dyr file. A detailed model \nof a generator must include:\n•\nGenerator Model\n•\nExcitation System Model\no\nMay be omitted if unit is operated under manual excitation control\n•\nTurbine-Governor Model\no\nMay be omitted if unit doesn’t regulate frequency\n•\nPower System Stabilizer Model\no\nMay be omitted if device is not installed or not active\n•\nReactive Line Drop Compensation Model\no\nMay be omitted if device is not installed or not active\nModels submitted must be allowable under the Acceptable Models Working Group (AMWG) \nDynamic Model List facilitated by the Eastern Interconnection Reliability Assessment Group \n(ERAG) posted at:\nhttps://www.rfirst.org/eastern-interconnection-reliability-assessment-group/.\nThe models must also comply with MISO’s MOD-032 Model Data Requirements and Reporting \nProcedures posted at: https://www.misoenergy.org/planning/planning-modeling/.\nFor a non-synchronous Generating Facility, Interconnection Customer shall provide (1) a \nvalidated user-defined root mean squared (RMS) positive sequence dynamics model; (2) an \nappropriately parameterized standard library RMS positive sequence dynamics model, including \nmodel block diagram of the inverter control and plant control systems allowable under the \nERAG AMWG Dynamic Model List, and compliant with MISO’s MOD-032 Model Data \nRequirements and Reporting Procedures that corresponds to Interconnection Customer’s \nGenerating Facility; and (3) if applicable, a validated electromagnetic transient model if \nTransmission Provider performs an electromagnetic transient study as part of the interconnection \nstudy process."},{"page":357,"startToken":100645,"endToken":100947,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nA user-defined model is a set of programming code created by equipment manufacturers or \ndevelopers that captures the latest features of controllers that are mainly software based and \nrepresents the entities’ control strategies but does not necessarily correspond to any standard \nlibrary model.  Interconnection Customer must also demonstrate that the model is validated by \nproviding evidence that the equipment behavior is consistent with the model behavior (e.g., an \nattestation from Interconnection Customer that the model accurately represents the entire \nGenerating Facility; attestations from each equipment manufacturer that the user defined model \naccurately represents the component of the Generating Facility; or test data).\nAn Interconnection Request seeking ZG Interconnection Service shall include a detailed power \nflow model for the proposed Generating Facility that includes all ZG Associated Loads, Point(s) \nof Withdrawal and the Point of Interconnections for the Interconnection Request, as well as any \nproposed system protection facilities.\nA-6. ONE-LINE & MODEL INFORMATION\nThe Interconnection Customer shall provide a Power Flow model describing the generator in a \nformat compatible with Siemens PTI PSS/E (.sav, .raw, .idev, .py, .prj, or equivalent format as \nspecified by MISO).\nThe Interconnection Customer is to provide the definitive one-line diagram for the POI – \nInformation shall include:\n•\nBreaker layout, bus configuration (if available) and number of generators\n•\nThe zero sequence impedance (if applicable)\n•\nThe distance from the collector substation to the POI referenced in miles and the line \nimpedance\n•\nIf the POI is a line tap, distance from the tap to the endpoints of the existing line \nreferenced in miles\n•\nGenerator step up (GSU) transformer data and collector substation transformer data, \nincluding impedances for each phase of the transformer (if applicable)"},{"page":358,"startToken":100947,"endToken":101077,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\n•\nFor inverter based generators, FERC Order 827 requires\no\nLocation and size of any dynamic and/or static VAR compensation devises\no\nEquivalent collector system impedance\nModels submitted should comply with MISO’s Model Data Requirements and Reporting \nProcedures posted at: https://www.misoenergy.org/planning/planning-modeling/mod-032-01\nAn Interconnection Request for seeking ZG Interconnection Service shall include a one line \ndiagram showing the Generating Facility and associated electrical equipment with appropriate \nrating and impedance information and all the ZG Associated Loads including all Point(s) of \nWithdrawal and the Point of Interconnection of the Generating Facility to the Transmission \nSystem for the Interconnection Request."},{"page":359,"startToken":101077,"endToken":101298,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nB.  Synchronous Generator Information\n(e.g. Biomass, Coal, Diesel, Hydro, Natural Gas, Nuclear, Oil)\n1.(Repeat the following for each generator model) Rated Generator \nspeed (rpm)\n2.Maximum Turbine MW (ºF)\n3. Moment-of-Inertia, WR2 (lb.ft.2 for combined Turbine-Generator-\nExciter-Inertia Data)\n4. Inertia Constant, H (kW sec/kVA for combined Turbine-Generator-\nExciter-Inertia Data)\nReactance Data (Per Unit- Rated kVA)\nDirect Axis\nQuadrature Axis\nSynchronous-saturated\nXdv:\nXqv:\nSynchronous-unsaturated\nXdi\nXqi\nTransient – saturated\nXdv:\nXqv:\nTransient – unsaturated\nXdi:\nXqi:\nSubtransient – saturated\nXdv:\nXqv:\nSubtransient – unsaturated\nXdi:\nXqi:\nNegative Sequence - saturated\nX2v:\nNegative Sequence - usaturated\nX2i:\nZero Sequence – saturated\nX0v:\nZero Sequence – unsaturated\nX0i:\nLeakage Reactance\nXlm:\nField Time Constant Data (sec)\nOpen Circuit\nTd0:\nTq0:\nThree-Phase Short Circuit Transient\nTd3:\nTq:\nLine-to-Line Short Circuit Transient\nTd2:\nLine-to-Neutral Short Circuit Transient\nTd1:\nShort Circuit Subtransient\nTd:\nTq:\nOpen Circuit Subtransient\nTd0:\nTq0:\nArmature Time Constant Data (sec)\nThree Phase Short Circuit\nTa3\nLine-to-Line Short Circuit\nTa2\nLine-to-Neutral Short Circuit\nTa1\nArmature Winding Resistance Data (Per Unit)\nPositive\nR1\nNegative\nR2\nZero\nR0\nRotor Short Time Thermal capacity I22t\nField Current Rated kVA, Armature \nVoltage and,  PF\n=______________amps\nField Current Rated kVA, Armature \nVoltage and,  0 PF\n=______________amps"},{"page":360,"startToken":101298,"endToken":101585,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nThree Phase Armature Winding \nCapacitance\n=______________microfarad\nField Winding Resistance\n=______________ohms ____C\nArmature Winding Resistance (per Phase)\n=______________ohms ____C\n5.Attach generator reactive capability curves\n6.Attach a plot of generator terminal voltage versus field current showing the air gap \nline, open-circuit saturation curve, and saturation curve at full load and rated power \nfactor, and power quality curves specifying percent total harmonic distortion vertically \nand percent power output horizontally from 25 – 100% power output for both current \nand voltages or specify that the unit is IEEE 519 compliant.  \nB-1.  Excitation System Information\n(Repeat the following for each generator model)\n1. Manufacturer and Type of excitation system used for the generator. \n2. Excitation System Response Ratio (ASA)\n3. Full load rated exciter output voltage\n4. Maximum exciter output voltage (ceiling voltage)\n5. Other comments regarding excitation system\n6. Attach IEEE block diagram of the excitation system and power system stabilizer \n(PSS) for computer representation in power system stability simulations and the \ncorresponding excitation system and PSS constants for use in the model.\nB-2. Turbine Governor Information\n(Repeat the following for each generator model and complete only section that applies to \ncorresponding turbine type)\na.\nTurbine manufacturer\nb. Maximum turbine power output (MW)\nc.\nMinimum turbine power output while on-\nline (MW)\nd. Droop setting (speed regulation)\ne.\nIs the governor mechanical-hydraulic or \nelectro-hydraulic? \nFor all turbine types\nf.\nOther comments about turbine governor \nsystem? \na. Unit type (Steam, Gas, Combined Cycle) \nSteam, gas or \ncombined cycle\nb. If steam or combined-cycle, does turbine \nsystem have re-heat process (both high and \nlow pressure turbines)?"},{"page":361,"startToken":101585,"endToken":101764,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nc. If steam with reheat process, or if \ncombined cycle, indicate low/high pressure \nturbine gas/steam (%)\na. Turbine efficiency at rated load (%)\nb. Length of penstock (ft)\nc. Average cross-sectional area of penstock \n(ft2)\nd. Typical maximum head (vertical distance \nfrom the bottom of the penstock, at the \ngate, to the water level (ft)\ne. Water supply (run-of-the-river or reservoir)\nf. Water flow rate at typical maximum head \n(ft3/sec)\ng. Average energy rate (kWh/acre-ft)\nHydro Turbines\nh. Estimated yearly energy production (kWh)\nB-3.  Induction Generator Information\n1. Motoring Power (kW) \n2. Neutral Grounding Resistor (If Applicable)\n3. I22t or K (Heating Time Constant) \n4. Rotor Resistance\n5. Stator Resistance\n6. Stator Reactance:\n7. Rotor Reactance:\n8. Magnetizing Reactance:\n9. Short Circuit Reactance:\n10. Exciting Current:\n11. Temperature Rise:\n12. Frame Size:\n13. Design Letter:\n14. Reactive Power Required In Vars (No Load):\n15. Reactive Power Required In Vars (Full Load):"},{"page":362,"startToken":101764,"endToken":102019,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\n16. Total Rotating Inertia, H:\n______ in\nPer Unit on KVA \nBase\nC. Non-Synchronous Generator Information\nC-1.  Wind Generators Information\n1. Number of generators to interconnect pursuant to \nInterconnection Request \n2. Average site elevation \n3. Field Volts\n4. Field Amperes\n5. Heating time constant (I22t)\n6. Rotor Resistance\n7. Stator Resistance\n8. Rotor Reactance\n9. Stator Reactance\n10. Exciting Current\n11. Temperature Rise\n12. Total Rotating inertia (H) (Per unit on 100 MVA \nBase)\n13. List of adjustable set- points for protective \nequipment or software*\n14. Generator type (e.g. GE doubly fed induction \nmachine with back-to-back IGBT converters, or \nMicon induction generator)\n15. Generator voltage ride through capability\nMin low-voltage threshold in \npercent to enable tripping ____\nMax low-voltage duration in \nseconds to enable tripping ____\n16. Provide voltage flicker data, if available, for the wind generator model to be installed \nspecified in percent of total voltage output.  The data may be provided at 25, 50, 75, \nand 100% of output or in the form of a curve with the Y-axis showing percent of \nflicker versus total output and the X-axis showing percent load output from at least \n25% to 100% of total output.\n17. Provide voltage dropout limits expressed in voltage level versus time\n18. Provide frequency dropout limits expressed in frequency versus time\n19. Provide reactive power capability curve\n20. Provide a validated user-defined RMS positive sequence dynamic model"},{"page":363,"startToken":102019,"endToken":102129,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\n*If available\nC-2.  Inverter-Based Parameters (e.g. Solar,  Storage, Type 4 Wind Turbines)\n1. Number of inverters to be interconnected \n2. Inverter Manufacturer\n3. Inverter Model Name\n4. Inverter Model Number\n5. Inverter Version Number\n6. List of adjustable set points for the protective equipment or software\n7. Maximum design fault contribution current\n8. Harmonics Characteristics\n9. Start – up requirements\n*PSCAD models may be required/requested for inverter based resources as needed during \nthe Generator Interconnection Process. If available please provide with application \nmaterials."},{"page":364,"startToken":102129,"endToken":102383,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nATTACHMENT B TO APPENDIX 1 TO GIP\nINTERCONNECTION STUDY AGREEMENT (GENERATING FACILITY)\nTHIS AGREEMENT is made and entered into this        day of             , 20     by and \nbetween                         , a                  organized and existing under the laws of the State of  \n____________________, (“Interconnection Customer,”) and the Midcontinent Independent \nSystem Operator, Inc., a non-profit, non-stock corporation organized and existing under the \nlaws of the State of Delaware, sometimes hereinafter referred to as the “Transmission Provider.”  \nInterconnection Customer and Transmission Provider each may be referred to as a “Party,” or \ncollectively as the “Parties.”  Any capitalized term used herein but not defined herein shall have \nthe meaning assigned to such term in the GIP and the GIA.\nRECITALS\nWHEREAS, Interconnection Customer is proposing to develop a Generating Facility or \ngenerating capacity addition to an Existing Generating Facility consistent with the \nInterconnection Request submitted by Interconnection Customer dated                 ; and\nWHEREAS, Interconnection Customer desires to interconnect the Generating Facility \nwith the Transmission System; and\nWHEREAS, Interconnection Customer has requested Transmission Provider to perform \nInterconnection Studies and/or Provisional Interconnection Studies to assess interconnecting the \nproposed Generating Facility to the Transmission System, and of any Affected Systems; \nNOW, THEREFORE, in consideration of and subject to the mutual covenants contained \nherein the Parties agreed as follows:\n1.0\nWhen used in this Agreement, with initial capitalization, the terms specified shall \nhave the meanings indicated in the Transmission Provider’s Commission-"},{"page":365,"startToken":102383,"endToken":102632,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\napproved GIP. \n2.0\nInterconnection Customer elects and Transmission Provider shall cause to be \nperformed an Interconnection Study and/or an Provisional Interconnection Study \nconsistent with the GIP in accordance with the Tariff, an Interconnection System \nImpact Study consistent with  the GIP and an Interconnection Facilities Study \nconsistent with the GIP, collectively referred to as the “Studies.”\n3.0\nThe Studies shall be based on the technical information provided by \nInterconnection Customer in the Interconnection Request, as may be modified as \nthe result of the Scoping Meeting, study results, or any other reason identified in \nthe GIP.  Transmission Provider reserves the right to request additional technical \ninformation from Interconnection Customer as such information may reasonably \nbecome necessary consistent with Good Utility Practice during the course of the \nStudies and as designated in accordance with Section 3.3.3 of the GIP.  If, after the \ndesignation of the Point of Interconnection pursuant to Section 3.3 of the GIP, \nInterconnection Customer modifies its Interconnection Request pursuant to \nSection 4.4, Transmission Provider may extend the time to complete The Studies.\n4.0\n{Reserved}\n5.0\nThe Interconnection System Impact Study report shall provide the following \ninformation:\n-\nidentification of any equipment short circuit capability limits exceeded as \na result of the interconnection;\n-\nidentification of any thermal overload or voltage limit violations resulting \nfrom the interconnection;"},{"page":366,"startToken":102632,"endToken":102885,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\n-\nidentification of any instability or inadequately damped response to \nsystem disturbances resulting from the interconnection (including as \nnecessary, transient stability, both large and small signal, sub synchronous \nstability, dynamic voltage stability, mid and long-term stability, voltage \nflicker analyses, and excessive neutral current studies in accordance with \nGood Utility Practice), and\n-\npreliminary description and non-binding, good faith, planning level \nestimated cost of facilities required to interconnect the Generating Facility \nto the Transmission System and to address the identified short circuit, \ninstability, and power flow issues.\n6.0\nThe Interconnection Facilities Study shall provide draft GIA appendices and \nsupporting documentation, which will:  (i)  provide a description, estimated cost \nof (consistent with Attachment A), and schedule for required facilities to \ninterconnect the Generating Facility to the Transmission System and (ii) address \nthe short circuit, instability, and power flow issues identified in the \nInterconnection System Impact Study.\n7.0\nInterconnection Customer shall provide deposits in the amount and timing \noutlined in Sections 3.3 of the GIP for the performance of the Studies.\nAny difference between the deposit and the actual cost of The Studies shall be \npaid by or refunded to Interconnection Customer, as appropriate under Section \n13.3 of the GIP.\n8.0\nInterconnection Customer may request all Base Cases and work papers associated \nwith this Interconnection Request, subject to Transmission Provider provisions \naround acquiring Critical Energy Infrastructure Information."},{"page":367,"startToken":102885,"endToken":103230,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\n9.0\nIndemnity.  To the extent permitted by law, each Party shall at all times \nindemnify, defend and hold the other Parties harmless from any and all damages, \nlosses, claims, including claims and actions relating to injury to or death of any \nperson or damage to property, demand, suits, recoveries, costs and expenses, court \ncosts, attorney fees, and all other obligations by or to third parties, arising out of \nor resulting from the other Party’s performance, or non-performance of its \nobligations under this Agreement on behalf of the indemnifying Party, except in \ncases of gross negligence or intentional wrongdoing by the indemnified Party.\n10.0\nLimitation of Liability.  Except with respect to the duties of defense and \nindemnity expressly provided in this Agreement, a Party shall not be liable to \nanother Party or to any third party or other person for any damages arising out of \nactions under this Agreement, including, but not limited to, any act or omission \nthat results in an interruption, deficiency or imperfection of Interconnection \nService, except as provided in the Tariff.  The provisions set forth in the Tariff \nshall be additionally applicable to any Party acting in good faith to implement or \ncomply with its obligations under this Agreement, regardless of whether the \nobligation is preceded by a specific directive.\n11.0\nMiscellaneous.  Except as otherwise provided herein, this Agreement shall \ninclude standard miscellaneous terms including, but not limited to, \nrepresentations, disclaimers, warranties, governing law, amendment, execution, \nwaiver, enforceability and assignment, that reflect best practices in the electric \nindustry, that are consistent with regional practices, Applicable Laws and \nRegulations and the organizational nature of each Party.  All of these provisions, \nto the extent practicable, shall be consistent with the provisions of the GIP and the \nGIA.\nIN WITNESS THEREOF, the Parties have caused this Agreement to be duly executed \nby their duly authorized officers or agents on the day and year first above written."},{"page":368,"startToken":103230,"endToken":103272,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nMidcontinent Independent \nSystem Operator, Inc.\nBy: \nName: \nTitle: \n[Insert name of Interconnection Customer]\nBy: \nName: \nTitle:"},{"page":369,"startToken":103272,"endToken":103518,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nINTERCONNECTION STUDY AGREEMENT (INJECTION RIGHTS)\nTHIS AGREEMENT is made and entered into this        day of             , 20     by and \nbetween                         , a                  organized and existing under the laws of the State of  \n____________________, (“MHVDC Connection Customer,”) and the Midcontinent \nIndependent System Operator, Inc., a non-profit, non-stock corporation organized and existing \nunder the laws of the State of Delaware, sometimes hereinafter referred to as the “Transmission \nProvider.”  MHVDC Connection and Transmission Provider each may be referred to as a \n“Party,” or collectively as the “Parties.”  Any capitalized term used herein but not defined herein \nshall have the meaning assigned to such term in the GIP and the GIA.\nRECITALS\nWHEREAS, MHVDC Connection Customer is proposing to develop an MHVDC  \nTransmission Line or capacity addition to an existing MHVDC Transmission Line consistent \nwith the Interconnection Request submitted by MHVDC Connection Customer dated                 ; \nand\nWHEREAS, MHVDC Connection Customer desires to interconnect the MHVDC \nTransmission Line with the Transmission System; and\nWHEREAS, MHVDC Connection Customer has requested Transmission Provider to \nperform Interconnection Studies and/or Provisional Interconnection Studies to assess \ninterconnecting the proposed MHVDC Transmission Line to the Transmission System, and of \nany Affected Systems; \nNOW, THEREFORE, in consideration of and subject to the mutual covenants contained \nherein the Parties agreed as follows:\n1.0\nWhen used in this Agreement, with initial capitalization, the terms specified shall"},{"page":370,"startToken":103518,"endToken":103777,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nhave the meanings indicated in the Transmission Provider’s Commission-\napproved GIP. \n2.0\nMHVDC Connection Customer elects and Transmission Provider shall cause to \nbe performed an Interconnection Study and/or an Provisional Interconnection \nStudy consistent with the GIP in accordance with the Tariff, an Interconnection \nSystem Impact Study consistent with the GIP and an Interconnection Facilities \nStudy consistent with the GIP, collectively referred to as the “Studies.”\n3.0\nThe Studies shall be based on the technical information provided by MHVDC \nConnection Customer in the Interconnection Request, as may be modified as the \nresult of the Scoping Meeting, study results, or any other reason identified in the \nGIP.  Transmission Provider reserves the right to request additional technical \ninformation from MHVDC Connection Customer as such information may \nreasonably become necessary consistent with Good Utility Practice during the \ncourse of the Studies and as designated in accordance with Section 3.3.3 of the \nGIP.  If, after the designation of the Point of Interconnection pursuant to Section \n3.3 of the GIP, MHVDC Connection Customer modifies its Interconnection \nRequest pursuant to Section 4.4, Transmission Provider may extend the time to \ncomplete The Studies.\n4.0\n{Reserved}\n5.0\nThe Interconnection System Impact Study report shall provide the following \ninformation:\n-\nidentification of any equipment short circuit capability limits exceeded as \na result of the interconnection;\n-\nidentification of any thermal overload or voltage limit violations resulting"},{"page":371,"startToken":103777,"endToken":104031,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nfrom the interconnection; \n-\nidentification of any instability or inadequately damped response to \nsystem disturbances resulting from the interconnection (including as \nnecessary, transient stability, both large and small signal, sub synchronous \nstability, dynamic voltage stability, mid and long-term stability, voltage \nflicker analyses, and excessive neutral current studies in accordance with \nGood Utility Practice), and\n-\npreliminary description and non-binding, good faith, planning level \nestimated cost of facilities required to interconnect the MHVDC \nTransmission Line to the Transmission System and to address the \nidentified short circuit, instability, and power flow issues.\n6.0\nThe Interconnection Facilities Study shall provide draft TCA appendices and \nsupporting documentation, which will:  (i)  provide a description, estimated cost \nof (consistent with Attachment A), and schedule for required facilities to \ninterconnect the MHVDC Transmission Line to the Transmission System and (ii) \naddress the short circuit, instability, and power flow issues identified in the \nInterconnection System Impact Study.\n7.0\nMHVDC Connection Customer shall provide deposits in the amount and timing \noutlined in Sections 3.3 of the GIP for the performance of the Studies.\nAny difference between the deposit and the actual cost of The Studies shall be \npaid by or refunded to MHVDC Connection Customer, as appropriate under \nSection 13.3 of the GIP.\n8.0\nMHVDC Connection Customer may request all Base Cases and work papers \nassociated with this Interconnection Request, subject to Transmission Provider"},{"page":372,"startToken":104031,"endToken":104355,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nprovisions around acquiring Critical Energy Infrastructure Information.\n9.0\nIndemnity.  To the extent permitted by law, each Party shall at all times \nindemnify, defend and hold the other Parties harmless from any and all damages, \nlosses, claims, including claims and actions relating to injury to or death of any \nperson or damage to property, demand, suits, recoveries, costs and expenses, court \ncosts, attorney fees, and all other obligations by or to third parties, arising out of \nor resulting from the other Party’s performance, or non-performance of its \nobligations under this Agreement on behalf of the indemnifying Party, except in \ncases of gross negligence or intentional wrongdoing by the indemnified Party.\n10.0\nLimitation of Liability.  Except with respect to the duties of defense and \nindemnity expressly provided in this Agreement, a Party shall not be liable to \nanother Party or to any third party or other person for any damages arising out of \nactions under this Agreement, including, but not limited to, any act or omission \nthat results in an interruption, deficiency or imperfection of Interconnection \nService, except as provided in the Tariff.  The provisions set forth in the Tariff \nshall be additionally applicable to any Party acting in good faith to implement or \ncomply with its obligations under this Agreement, regardless of whether the \nobligation is preceded by a specific directive.\n11.0\nMiscellaneous.  Except as otherwise provided herein, this Agreement shall \ninclude standard miscellaneous terms including, but not limited to, \nrepresentations, disclaimers, warranties, governing law, amendment, execution, \nwaiver, enforceability and assignment, that reflect best practices in the electric \nindustry, that are consistent with regional practices, Applicable Laws and \nRegulations and the organizational nature of each Party.  All of these provisions, \nto the extent practicable, shall be consistent with the provisions of the GIP and the \nGIA."},{"page":373,"startToken":104355,"endToken":104426,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nIN WITNESS THEREOF, the Parties have caused this Agreement to be duly executed \nby their duly authorized officers or agents on the day and year first above written.\nMidcontinent Independent \nSystem Operator, Inc.\nBy: \nName: \nTitle: \n[Insert name of MHVDC Connection Customer]\nBy: \nName: \nTitle:"},{"page":374,"startToken":104426,"endToken":104652,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nATTACHMENT C TO APPENDIX 1:  UNIVERSAL NON-DISCLOSURE AND \nCONFIDENTIALITY AGREEMENT\nPROJECT NO. _____\nThis Universal Non-Disclosure and Confidentiality Agreement (the “Agreement”) is entered into \non this _______ day of ___________________, 20____ and effective as of the ______ day of \n_____________________, 20____ (the “Effective Date”), by and between Midcontinent \nIndependent System Operator, Inc. (“MISO”) and ______________________________, \n(“Company”) whose principal offices are located at ___________________________________.  \nMISO and Company each may be referred to individually as a “Party” or collectively as the \n“Parties.”  \nWHEREAS, MISO is prepared to disclose confidential information under this Agreement \nto Company in connection with MISO’s business with, or possible engagement of, Company (the \n“Purpose”);\nWHEREAS, Company represents that it desires to receive confidential information \npursuant to this Agreement; and,\nWHEREAS, MISO and Company desire to set forth in writing the terms and conditions of \ntheir agreement.\nNOW THEREFORE, in consideration of the mutual promises, covenants, representations \nand agreements contained in this Agreement and other good and valuable consideration, the \nreceipt and sufficiency of which are hereby acknowledged, the Parties agree as follows:\n1.0\nConfidential Information.  “Confidential Information” as used in this Agreement means \nall information disclosed to Company by MISO or its employees, agents, contractors, \nrepresentatives, consultants and advisors (collectively “Disclosing Party”) in connection"},{"page":375,"startToken":104652,"endToken":105028,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nwith the Purpose.  Confidential Information includes, without limitation, (i) any and all \nbusiness, technical, marketing, financial or other information, whether in electronic, oral \nor written form; (ii) trade secrets, business plans, techniques, methods, or systems, data, \nknow-how, formulae, compositions, designs, sketches, mock-ups, prototypes, \nphotographs, charts, graphs, forms, documents, drawings, samples, inventions, ideas, \nresearch and development, customer and vendor lists (including, without limitation, the \nidentity, characteristics, contact persons, product and service needs thereof), rates, price \nlists, computer software programs and systems, financial statements, and budgets; (iii) all \nmemoranda, summaries, notes, analyses, compilations, studies or those portions of other \ndocuments prepared by Company to the extent they contain or reflect such information \nof, or the contents of discussions with the Disclosing Party (“Company’s Material”), \nincluding the contents or existence of discussions or negotiations related to the Purpose; \n(iv) information not generally known or readily ascertainable; (v) information that \nprovides a competitive advantage for Disclosing Party; and (vi) information that is \nmarked “Confidential” or nonpublic information which under the circumstances \nsurrounding disclosure a reasonable person would conclude should be treated as \nconfidential.  Confidential Information shall not include information that (a) is or \nbecomes part of the public domain other than as a result of disclosure by Company, (b) \nbecomes available to Company on a non-confidential basis from a source other than \nDisclosing Party, provided that, to the best of Company’s knowledge, such source is not \nprohibited from transmitting such information by a contractual, legal, or other obligation, \nor (c) was in Company’s possession prior to disclosure of the same by Disclosing Party.\n2.0\nNon-Use; Protection and Dissemination of Confidential Information.  Company \nagrees not to disclose, discuss, use, reproduce, duplicate, distribute, copy, reconstruct or \nin any way communicate, directly or indirectly, the Confidential Information for purposes \nother than in connection with the Purpose.  Company shall not disclose, discuss, use, \nreproduce, duplicate, distribute or in any way communicate, directly or indirectly, the \nConfidential Information to any other party and will use all reasonable efforts to protect \nthe confidentiality of such information.  Company will require that Company’s \nemployees, officers, directors, agents, contractors, representatives, consultants and"},{"page":376,"startToken":105028,"endToken":105401,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nadvisors who need to have access to such Confidential Information in order to assist \nCompany in connection with the Purpose (1) are aware of the Company’s confidentiality \nobligation hereunder, and (2) agree to be bound by such confidentiality obligations.  \nCompany shall notify Disclosing Party immediately of any loss, misuse, or \nmisappropriation of any Confidential Information of which Company becomes aware.\n3.0\nOwnership and Return.  All Confidential Information, including Company’s Material, \nshall be and remain the property of Disclosing Party, and no right or license is granted to \nCompany with respect to any Confidential Information.  No transfer or creation of \nownership rights in any intellectual property comprising Confidential Information is \nintended or shall be inferred by the disclosure of Confidential Information by Disclosing \nParty, and any and all intellectual property comprising Confidential Information \ndisclosed and any derivations thereof, shall continue to be the exclusive intellectual \nproperty of Disclosing Party.  Upon the termination by any Party of the Purpose, or \nsooner if so requested, Company agrees to immediately return all Confidential \nInformation, including Company’s Material, to Disclosing Party or to destroy all \nConfidential Information, including all copies of the same, however, Company shall not \nbe required to destroy Confidential Information that has become embedded in Company’s \nplanning models.  Upon request, the fact of any such destruction shall be certified in \nwriting to Disclosing Party by Company.  Nothing in this Agreement obligates \nDisclosing Party to disclose any information to Company or creates any agency or \npartnership relation between them.\n4.0\nCompliance and Protection of Confidential Information.  Company represents and \nwarrants that it has practices and procedures adequate to protect against the unauthorized \nrelease of Confidential Information received.  Company must educate its employees, \nagents, and assigns in the provisions of this Agreement and provide to Disclosing Party \nupon request any information necessary to determine compliance with the terms of this \nAgreement.\n5.0\nIndemnification.  To the extent permitted by law, Company agrees to indemnify, hold \nharmless and defend MISO, its employees, principals (owners, partners, shareholders or \nholders of an ownership interest, as the case may be), agents, contractors, representatives,"},{"page":377,"startToken":105401,"endToken":105797,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nconsultants and/or advisors against any and all liability, loss, costs, damages, expenses, \nclaims or actions, joint or several, arising out of or by reason of any breach of this \nAgreement by Company and/or Company’s employees, agents, contractors, \nrepresentatives or consultants, or arising out of or by reason of any act or omission of \nCompany and/or Company’s employees, agents, contractors, representatives or \nconsultants in the execution, performance, or failure to adequately perform their \nobligations under this Agreement.  For purposes of this Section, to “indemnify” means to \ndefend and pay all expenses (including reasonable attorneys’ fees) and satisfy all \njudgments (including costs and reasonable attorneys’ fees) which may be incurred or \nrendered against MISO, its employees, principals (owners, partners, shareholders or \nholders of an ownership interest, as the case may be), agents, contractors, representatives, \nconsultants and/or advisors.\n6.0\nCompelled Disclosure.  If Company is requested or required by legal or administrative \nprocess to disclose any Confidential Information, Company shall promptly notify \nDisclosing Party of such request or requirement so that Disclosing Party may seek an \nappropriate protective order or other relief.  In any case, Company will (a) disclose only \nthat portion of the Confidential Information that its legal counsel advises is required to \nbe disclosed, (b) use its reasonable efforts to ensure that such Confidential Information is \ntreated confidentially, including seeking an appropriate protective order, and (c) notify \nDisclosing Party as soon as reasonably practicable of the items of Confidential \nInformation so disclosed.\n7.0\nRemedies.  The Parties acknowledge that remedies at law may be inadequate to protect \nDisclosing Party against any actual or threatened breach of this Agreement by Company, \nand, without prejudice to any other rights and remedies otherwise available to Disclosing \nParty, agree to the immediate granting of preliminary and final injunctive relief (without \nprior notice and without posting any bond) in favor of Disclosing Party to enjoin and \nrestrain any breach or violation, either actual or anticipatory, of this Agreement.\n8.0\nPurpose.  None of the Parties will be under any legal obligation of any kind whatsoever \nwith respect to the Purpose by virtue of this Agreement, except for the matters \nspecifically agreed to herein.  No representation or warranty is made by the Disclosing"},{"page":378,"startToken":105797,"endToken":106210,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nParty as to the accuracy or completeness of any information provided to the Company.  \n9.0\nTerm and Termination.  Company’s obligations under this Agreement shall be effective \non the date set forth above and shall be perpetual, notwithstanding any expiration, \ncancellation or termination of this Agreement.  Upon termination of the Agreement, \nCompany shall either promptly (1) deliver or cause to be delivered to Disclosing Party or \n(2) certify to the Disclosing Party the destruction of, all Confidential Information, \nincluding all copies of the Confidential Information in Company’s possession or control \nincluding, without limitation, originals and copies of documents, customer lists, prospect \nlists, price lists, operations manuals, and all other documents reflecting or referencing the \nConfidential Information, as well as all other materials furnished to or acquired by \nCompany to facilitate the Purpose of the Agreement.\n10.0\nAgency.  This Agreement is binding on Company, its employees, agents, contractors, \nrepresentatives, consultants, advisors, successors and assigns.  In the event of a dispute \nregarding liability for breach of this Agreement, common law agency principles apply.\n11.0\nWaiver.  No waiver of any of the provisions of this Agreement will be deemed or will \nconstitute a waiver of any other provision, whether or not similar, nor will any waiver \nconstitute a continuing waiver.  No waiver will be binding unless executed in writing by \nan authorized representative of the Party making the waiver.  The failure of either Party \nin any one or more instances to insist upon strict performance of any of the terms and \nconditions of this Agreement will not be construed as a waiver or relinquishment, to any \nextent, of the right to assert or rely upon any such terms or conditions on any future \noccasion.  \n12.0\nModification.  This Agreement may not be amended except in a writing signed by \nauthorized representatives of both Parties.\n13.0\nGoverning Law.  Indiana law shall govern the interpretation and implementation of the \nAgreement and the resolution of any dispute between the parties regarding the effect of \nthe Agreement without giving effect to principles of conflicts of law, and shall \nsupplement, but not replace, the Uniform Trade Secrets Act as enacted by the State of \nIndiana.  Each Party hereby submits itself for the sole purpose of this Agreement and any \ncontroversy arising hereunder to the exclusive jurisdiction of the federal or state courts"},{"page":379,"startToken":106210,"endToken":106607,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nlocated in the State of Indiana serving the counties of Hamilton and Marion, and any \ncourts of appeal therefrom, and waives any objection (on the grounds of lack of \njurisdiction, or forum not convenient or otherwise) to the exercise of such jurisdiction \nover it by any such courts.\n14.0\nSeverability and Survival.  Should any clause, portion or paragraph of this Agreement \nbe unenforceable or invalid for any reason, such unenforceability or invalidity will not \naffect the enforceability or validity of the remainder of this Agreement, and any court \nhaving jurisdiction is specifically authorized and encouraged by the Parties to hold \ninviolate all portions of this Agreement that are valid and enforceable without \nconsideration of any invalid or unenforceable portions hereof.\n15.0\nThe headings of the sections in this Agreement are for the purposes of convenient \nreference only and are not intended to be part of this Agreement, or to limit or affect the \nmeaning or interpretation of any of the terms hereof.  \n16.0\nAssignment and Succession.  This Agreement shall inure to the benefit of and be \nbinding upon the successors and permitted assigns of the Parties hereto.  Any successor \nto or assignee of MISO shall assume its rights and obligations under this Agreement with \nor without notice to Company.  Company may not assign its rights hereunder without the \nwritten permission of MISO.\n17.0\nAttorney’s Fees.  If Company breaches or defaults in the performance of any of the \ncovenants, agreements, representations, or warranties described in this Agreement, then \nin addition to any and all of the rights and remedies which MISO may have against \nCompany, Company will also be liable to and pay MISO its court costs and reasonable \nattorney’s fees incurred in enforcing MISO’s covenants, agreements, representations and \nwarranties herein.\n18.0\nEmployees Bound by Agreement.  The representative executing this Agreement hereby \nacknowledges and agrees that he/she is duly authorized to execute this Agreement on \nbehalf of Company and that this Agreement shall bind and be enforceable by and against \nthe employees, agents, or consultants of Company.  The authorized representative of \nCompany further acknowledges and agrees that only those employees who are listed on \nthe attached Appendix A incorporated herein shall be authorized to receive Confidential"},{"page":380,"startToken":106607,"endToken":106799,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nInformation directly from MISO and that he/she will notify MISO in writing of any \nmodification to Appendix A prior to releasing Confidential Information to those \nemployees listed on Appendix A.\n19.0\nNotices.  All notices and other communications hereunder shall be in writing and shall be \ndeemed given if delivered personally or by commercial delivery service, or mailed by \nregistered or certified mail (return receipt requested) or sent via facsimile (with \nacknowledgment of complete transmission) to the parties at the following addresses (or at \nsuch other address for a party as shall be specified by like notice):\nif to MISO, to:\n720 West City Center Drive\nCarmel, Indiana  46032\nAttn:  General Counsel\nFacsimile No.:  (317) 249-5912\nif to ___________, to: ________________________________\n________________________________\n________________________________\nFacsimile No.:  _____________________\n20.0\nEntire Agreement.  The Parties agree that this Agreement, including Appendix A \nincorporated herein and as modified, constitute their entire agreement with respect to the \nsubject matter hereof and that it supersedes any prior agreements or understandings \nbetween them, whether written or oral."},{"page":381,"startToken":106799,"endToken":106892,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nCompany acknowledges that it has read the Agreement, had the opportunity to discuss it with \ncounsel, and is executing it with an understanding of its provisions.  This Agreement may be \nexecuted in two or more counterparts, each of which will be deemed an original and all of which \ntogether will constitute one and the same document.\nremainder of page left intentionally blank\n[signatures appear on following page]"},{"page":382,"startToken":106892,"endToken":106965,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nIN WITNESS WHEREOF, the Parties have caused this Agreement to be executed, \neffective as of the day, month and year written above.\nMidcontinent Independent System Operator, Inc.\nMidcontinent Independent  System \nOperator, Inc.\nCompany:\n____________________________________\nBy:  ______________________________\nBy:  ________________________________\nPrint name:  _______________________\nPrint Name:  _________________________\nTitle:  ____________________________\nTitle:  _______________________________\nDate:\n_______________________\nDate:\n_______________________\nPhone: _______________________\nPhone: _______________________\nFax:\n_______________________\nFax:\n_______________________"},{"page":383,"startToken":106965,"endToken":107171,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nAPPENDIX A TO ATTACHMENT C\nTO MISO UNIVERSAL NON-DISCLOSURE AND \nCONFIDENTIALITY AGREEMENT\nCompany, ___________________________________________ Employees, Agents, or Consultants \nsubject to Confidentiality Agreement as of this _______ day of _________________, 20____:\nTransmission/Reliability or\n Print Name\nTitle\nE-mail Address\nMerchant/Market, or N/A*)\n1.\n2.\n3.\n4.\n5.\n6.\n7.\n8.\n9.\n10.\n(Attach Additional Pages If Necessary)\n* An individual who is an employee of a Transmission Provider (as defined in 18 C.F.R. § \n358.3(k) may not be subject to the FERC functional separation requirements (i.e., “N/A” \ndesignation) under certain circumstances in accordance with FERC Order No. 717 and the \nFERC regulations therein adopted.  If such an individual would receive information subject to \nthis Amendment, the copy of this Appendix A executed for that individual must be \naccompanied by written confirmation from Company stating the following:  (1) the designated \nindividual is not engaged in transmission or marketing functions (i.e., day-to-day duties and \nresponsibilities for planning, directing, organizing or carrying out operations); (2) the \nindividual has received training on the Standards of Conduct; and (3) the individual undertakes"},{"page":384,"startToken":107171,"endToken":107248,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nto comply with such Standards, including in particular the “no conduit rule” set forth in 18 \nC.F.R. § 358.6.\nNOTE:  Any changes to the information on this Appendix A must be submitted electronically to the \nTransmission Provider in the manner specified by the Generator Interconnection Business Practices \nManual (BPM-015)."},{"page":385,"startToken":107248,"endToken":107541,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nATTACHMENT D TO APPENDIX 1: CRITICAL ENERGY INFRASTRUCTURE \nINFORMATION GENERAL NON-DISCLOSURE AGREEMENT\nWHEREAS, Midcontinent Independent  System Operator, Inc. (“MISO”) is prepared to \ndisclose Critical Energy Infrastructure Information (“CEII”) under this Critical Energy \nInfrastructure Information General Non-Disclosure Agreement (“NDA”) to \n__________________ (“Recipient”), an individual (employee, manager or officer) employed \nwith _______________________, in connection with a legitimate need for the CEII (the \n“Purpose”) (MISO and Recipient may be collectively referred to as “Parties” or singly as \n“Party”);\nWHEREAS, Recipient represents that he/she has a legitimate purpose for requesting the \nCEII pursuant to this Agreement; and,\nWHEREAS, MISO and Recipient desire to set forth in writing the terms and conditions \nof their agreement.\nNOW THEREFORE, in consideration of the mutual promises, covenants, representations \nand agreements contained in this Agreement and other good and valuable consideration, the \nreceipt and sufficiency of which are hereby acknowledged, the Parties agree as follows:\n1.\nDefinitions - For purposes of these provisions:\na.\nThe term “CEII” shall include specific engineering, vulnerability, or detailed \ndesign information about proposed or existing critical infrastructure that:  (1) relates \ndetails about the production, generation, transportation, transmission, or distribution of \nenergy; (2) could be useful to a person in planning an attack on critical infrastructure; (3) \nis exempt from mandatory disclosure under the Freedom of Information Act, 5 U.S.C. \n552 (2000); and (4) does not simply give the general location of the critical infrastructure.  \nNarratives such as the descriptions of facilities and processes are generally not CEII \nunless they describe specific engineering and design details of critical infrastructure.\nb.\nThe term “Recipient” means someone who has executed this NDA and is"},{"page":386,"startToken":107541,"endToken":107871,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\napproved to receive CEII.\n2.\nA Recipient certifies that it is his/her understanding that access to CEII is provided \npursuant to the terms and restrictions of the provisions in this NDA, and that such Recipient has \nread the provisions and agrees to be bound by them.\n3.\nRecipient may only discuss CEII with another Recipient of the identical CEII.  A \nRecipient may check with MISO to determine whether another individual is a Recipient of the \nidentical CEII.\n4.\nA Recipient of CEII may use CEII as foundation for advice provided to others, but may \nnot disclose CEII to another individual unless that individual is an approved Recipient of the \nsame CEII.\n5.\nA Recipient will not knowingly use CEII for an illegal or non-legitimate purpose.\n6.\nAll CEII shall be maintained by Recipient in a secure place.  Access to those materials \nshall be limited to other Recipients of the identical material.  Recipients may make copies of \nCEII, but such copies become CEII and subject to these same procedures.  Recipients may make \nnotes of CEII, which shall be treated as CEII notes if they contain CEII.\n7.\nRecipients must return CEII to MISO or destroy CEII within fifteen days of a written \nrequest by MISO to do so, except that CEII notes may be retained in accordance with Paragraph \n6, above.  Within such time period, each Recipient, if requested to do so, shall also submit to \nMISO an affidavit stating that, to the best of his or her knowledge, all CEII has been returned or \ndestroyed and that CEII notes have either been returned, destroyed or are being maintained by \nRecipient in accordance with Paragraph 6.\n8.\nThe Recipient remains bound by these provisions unless MISO rescinds the provisions or \na court of competent jurisdiction finds that the information does not qualify as CEII."},{"page":387,"startToken":107871,"endToken":108083,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\n9.\nMISO may reasonably audit the Recipient’s compliance with this NDA.\n10.\nViolation of this NDA will be reported to the Federal Energy Regulatory Commission \n(the “Commission”) which in turn may result in criminal or civil sanctions against the Recipient.\n11.\nI hereby certify my understanding that access to CEII is provided to me pursuant to the \nterms and restrictions of the above CEII provisions, that I have been given a copy of and have \nread the provisions, and that I agree to be bound by them.  I understand that the contents of the \nCEII, any notes or other memoranda, or any other form of information that copies or discloses \nCEII shall not be disclosed to anyone other than another person who has been granted access to \nthese same materials.  I acknowledge that a violation of this NDA may result in criminal or civil \nsanctions, including the suspension of my ability to appear before the Commission pursuant to \n18 C.F.R. § 385.2102.  I agree that my compliance with this NDA is subject to reasonable audit \nby MISO.\nBy: _____________________________________\nSignature\nPrint Name: ______________________________\nTitle: ___________________________________\nRepresenting: _____________________________\nDate: ____________________________________"},{"page":388,"startToken":108083,"endToken":108314,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nATTACHMENT E TO APPENDIX 1: SITE CONTROL DEMONSTRATION \nMidcontinent Independent System Operator, Inc.\nAttn: Manager, Queue Administration \n720 City Center Drive \nCarmel, IN 46032 \n[Date]\nSubject: Proof of Site Control Affidavit \n1.  \nThe undersigned (“Affiant”) is an officer or an agent of the Interconnection Customer for \nthe Interconnection Request associated with [Project Name].\n2. \nAffiant affirms that all of the Site Control documents for [Project Name] required \npursuant to Section 7.2 of Attachment X of the MISO Tariff are submitted to MISO in \ntheir entirety.\n3. \nAffiant has reviewed all such Site Control documents submitted for [Project Name] and \nhas personal knowledge of its contents.\n4.\nAffiant hereby affirms that the Interconnection Customer [PLEASE SELECT FROM \nTHE FOLLOWING:\n____\n (1) possesses Site Control for (Project Name) in accordance with Sections 7.2.1.1 of \nthis GIP; OR \n____ (2) is presently subject to regulatory restrictions that preclude Interconnection \nCustomer from obtaining Site Control for (Project Name) pursuant to Section 7.2.1.2 of \nthis GIP].\n5. \n[TO THE EXTENT THAT REGULATORY RESTRICTIONS PRECLUDE SITE \nCONTROL PURSUANT TO GIP SECTION 7.2.1.2] In accordance with Section \n7.2.1.2 of the GIP, attached hereto the affiant provides a description of conditions that"},{"page":389,"startToken":108314,"endToken":108376,"text":"MISO\nAttachment X: Appendix 1\nFERC Electric Tariff\nInterconnection Request for a Generating Facility\nATTACHMENTS\n60.0.0, 61.0.0\nEffective On: October 18, 2026\nmust be met in order to satisfy the regulatory restrictions and the anticipated time by \nwhich the Interconnection Customer expects to satisfy the regulatory restrictions.\nSincerely,\n[Affiant signature]\n[Affiant printed name]\n[Affiant title]\n[Affiant company name]"},{"page":390,"startToken":108376,"endToken":108637,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nAPPENDIX 19 TO GIP \nZG INTERCONNECTION AGREEMENT (ZGIA) \n \nTHIS ZGINTERCONNECTION AGREEMENT (“ZGIA”) is made and entered into \nthis ____ day of ________ 20__, by and between ________________, a \n______________________ organized and existing under the laws of the State/Commonwealth of \n_____________________ (“Interconnection Customer” with a Generating Facility), and  \n__________________________, a [corporation] organized and existing under the laws of the \nState/Commonwealth of ____________ (“Transmission Owner”), and the Midcontinent \nIndependent System Operator, Inc., a non-profit, non-stock corporation organized and existing \nunder the laws of the State of Delaware (“Transmission Provider”).  Interconnection Customer, \nTransmission Owner and Transmission Provider each may be referred to as a “Party,” or \ncollectively as the “Parties.” \n \nRECITALS \n \nWHEREAS, Transmission Provider has functional control of the operations of the \nTransmission System, as defined herein and according to NERC’s Rules of Procedure, and is \nresponsible for providing Transmission Service and Interconnection Service on the transmission \nfacilities under its control; and  \n \nWHEREAS, Interconnection Customer intends to own, lease and/or control and operate \nthe Generating Facility identified as a Generating Facility in Appendix A to this ZGIA; and \n \nWHEREAS, Interconnection Customer will use the output of its Generating Facility to \nserve the ZG Associated Load identified in Appendix A of this Agreement and otherwise will \nnot inject energy onto the Transmission System; and \n \nWHEREAS, Transmission Owner owns or operates the Transmission System, whose \noperations are subject to the functional control of Transmission Provider, to which \nInterconnection Customer desires to connect the Generating Facility, and may therefore be"},{"page":391,"startToken":108637,"endToken":108717,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nrequired to construct certain Interconnection Facilities and Network Upgrades, as set forth in this \nZGIA; and \n \nWHEREAS, Interconnection Customer, Transmission Owner and Transmission Provider \nhave agreed to enter into this ZGIA for the purpose of interconnecting the Generating Facility \nwith the Transmission System; \n \nNOW, THEREFORE, in consideration of and subject to the mutual covenants contained \nherein, it is agreed:"},{"page":392,"startToken":108717,"endToken":108993,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nARTICLE 1.  DEFINITIONS \n \n \nWhen used in this ZGIA, terms with initial capitalization that are not defined in Article 1 \nshall have the meanings specified in the Article in which they are used.  Those capitalized terms \nused in this ZGIA that are not otherwise defined in this ZGIA have the meaning set forth in the \nTariff. \n \n10 kW Inverter Process shall mean the procedure for evaluating an Interconnection \nRequest for a certified inverter-based Small Generating Facility no larger than 10 kW that uses \nthe screen set forth in Section 14. \n \nAdverse System Impact shall mean the negative effects due to technical or operational \nlimits on conductors or equipment being exceeded that may compromise the safety and \nreliability of the electric system. \n \nAffected System(s) shall mean an electric transmission system or the electric system \nassociated with an Existing Generating Facility or of a higher queued Generating Facility, which \nis an electric system other than the Transmission Provider’s Transmission System that is affected \nby the Interconnection Request.  An Affected System may or may not be subject to FERC \njurisdiction. \n \nAffected System Interconnection Customer shall mean any entity that submits an \ninterconnection request for a Generating Facility to a transmission system other than \nTransmission Provider’s Transmission System that may cause the need for Affected System \nNetwork Upgrades on the Transmission Provider’s Transmission System. \n \nAffected System Network Upgrades shall mean the additions, modifications, and \nupgrades to Transmission Provider’s Transmission System required to accommodate Affected \nSystem Interconnection Customer’s proposed interconnection to a transmission system other \nthan Transmission Provider’s Transmission System."},{"page":393,"startToken":108993,"endToken":109262,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \nAffected System Operator shall mean the entity that operates an Affected System. \n \nAffected System Queue Position shall mean the queue position of an Affected System \nInterconnection Customer in Transmission Provider’s interconnection queue relative to \nTransmission Provider’s Interconnection Customers’ Queue Position. \n \nAffected System Study shall mean the evaluation of Affected System Interconnection \nCustomers’ proposed interconnection(s) to a transmission system other than the Transmission \nProvider’s Transmission System that have an impact on Transmission Provider’s Transmission \nSystem, as described in Section 8 of this GIP. \n \nAffected System Study Agreement shall mean the agreement contained in Appendix 16 \nto the GIP that is made between Transmission Provider and host transmission provider, in \nabsence of a JOA, JPA, or other agreement filed with the Commission, as noted in Section 8 of \nthe GIP. \n \nAffected System Study Report shall mean the report issued following completion of an \nAffected System Study. \n \nAffiliate shall mean, with respect to a corporation, partnership or other entity, each such \nother corporation, partnership or other entity that directly or indirectly, through one or more \nintermediaries, controls, is controlled by, or is under common control with, such corporation, \npartnership or other entity. \n \nAncillary Services shall mean those services that are necessary to support the \ntransmission of capacity and energy from resources to loads while maintaining reliable operation \nof the Transmission System in accordance with Good Utility Practice. \n \nApplicable Laws and Regulations shall mean all duly promulgated applicable federal, \nstate and local laws, regulations, rules, ordinances, codes, decrees, judgments, directives, or"},{"page":394,"startToken":109262,"endToken":109527,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\njudicial or administrative orders, permits and other duly authorized actions of any Governmental \nAuthority having jurisdiction over the Parties, their respective facilities and/or the respective \nservices they provide.  \n \nApplicable Reliability Standards shall mean the requirements and guidelines of the \nElectric Reliability Organization and the Balancing Authority Area of the Transmission System \nto which the Generating Facility is directly interconnected. \n \nBalancing Authority shall mean an entity that integrates resource plans ahead of time, \nmaintains demand and resource balance within a Balancing Authority Area, and supports \ninterconnection frequency in real time. \n \nBalancing Authority Area shall mean the collection of generation, transmission, and \nloads within the metered boundaries of the Balancing Authority.  The Balancing Authority \nmaintains load-resource balance within this area. \n \nBase Case shall mean the base case power flow, short circuit, and stability databases \nused for the Interconnection Studies by Transmission Provider or Interconnection Customer. \n \nBase Case Data shall mean base case power flow, short circuit and stability databases, \nincluding all underlying assumptions, and contingency lists.  Such databases and lists, hereinafter \nreferred to as Base Cases, shall include all (1) generation projects and (2) transmission projects, \nincluding merchant transmission projects that are proposed for the Transmission System for \nwhich a transmission expansion plan has been submitted and approved by the MISO Board. \n \nBreach shall mean the failure of a Party to perform or observe any material term or \ncondition of this GIA. \n \nBreaching Party shall mean a Party that is in Breach of this GIA."},{"page":395,"startToken":109527,"endToken":109820,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \nBusiness Day shall mean Monday through Friday, excluding Federal Holidays. \n \nCalendar Day shall mean any day including Saturday, Sunday or a Federal Holiday.  In \nthe event that a period specified in this GIA is calculated in Calendar Days ends on a non-\nbusiness day, such period shall be deemed to conclude on the following business day. \n \nCluster shall mean a group of one or more Interconnection Requests that are studied \ntogether for the purpose of conducting a Group Study. \n \nCommercial Operation shall mean the status of a Generating Facility that has \ncommenced generating electricity for sale, excluding electricity generated during Trial \nOperation. \n \nCommercial Operation Date (COD) of a unit shall mean the date on which the \nGenerating Facility commences Commercial Operation as agreed to by the Parties pursuant to \nAppendix E to this GIA. \n \nCommitment Projection shall mean a projection of the number of MW expected to \ncommit to the JTIQ Portfolio from ERAS and all DPP study clusters that already have passed \nDP1 as described in Section 9.4.2.e.ii of Rate Schedule 6 (MISO SPP-JOA).  \n \nCommon Use Upgrade (CUU) shall mean an Interconnection Facility, Network \nUpgrade, System Protection Facility, or any other classified addition, alteration, or improvement \non the Transmission System or the transmission system of an Affected System, not classified \nunder Attachment FF as a Baseline Reliability Project, Market Efficiency Project, or Multi-Value \nProject, that is needed for the interconnection of multiple Interconnection Customers’ Generating \nFacilities and which is the shared responsibility of such Interconnection Customers.   \n \nConfidential Information shall mean any proprietary or commercially or competitively \nsensitive information, trade secret or information regarding a plan, specification, pattern,"},{"page":396,"startToken":109820,"endToken":110148,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nprocedure, design, device, list, concept, policy or compilation relating to the present or planned \nbusiness of a Party, or any other information as specified in Article 22, which is designated as \nconfidential by the Party supplying the information, whether conveyed orally, electronically, in \nwriting, through inspection, or otherwise, that is received by another Party. \n \nConnection Facilities shall mean the Transmission Owner’s Connection Facilities and \nthe MHVDC Connection Customer’s Connection Facilities, as defined in the MHCP. \n \nContingent Facilities shall mean those unbuilt Interconnection Facilities and Network \nUpgrades upon which the Interconnection Request’s costs, timing and study findings are \ndependent, and if delayed or not built, could cause a need for restudies of the Interconnection \nRequest or a reassessment of the Interconnection Facilities and/or Network Upgrades and/or \ncosts and timing.  Contingent Facilities may include facilities identified in MTEP that if delayed \nor not built could impact the timing of the Interconnection Request. \n \nCustomer Engagement Window shall mean the time period prior to the start of \nDefinitive Planning Phase I set forth in Section 3.3.4 of the GIP. \n \nDefault shall mean the failure of a Breaching Party to cure its Breach in accordance with \nArticle 17 of this GIA. \n \nDefinitive Planning Phase shall mean the Generator Interconnection Procedures process \nwhich leads to a Generator Interconnection Agreement.  An Interconnection Customer enters the \nDefinitive Planning Phase pursuant to GIP Section 7.2.  The Definitive Planning Phase includes \nthree distinct phases (Definitive Planning Phases I, II, and III) pursuant to Section 7 of the \nGenerator Interconnection Procedures. \n \nDefinitive Planning Phase Queue Position shall mean the order of a valid \nInterconnection Request, relative to all other pending valid Interconnection Requests, in the \nDefinitive Planning Phase.  The Definitive Planning Phase Queue Position is established based \nupon the date Interconnection Customer satisfies all of the requirements of GIP Section 7.2 to"},{"page":397,"startToken":110148,"endToken":110469,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nenter the Definitive Planning Phase.  All Interconnection Requests within the same Definitive \nPlanning Phase cycle shall have equal priority (i.e. similarly queued).   \n \nDemonstrated Capability shall mean the continuous net real power output that the \nGenerating Facility is required to demonstrate in compliance with Applicable Reliability \nStandards.   \n \nDispute Resolution shall mean the procedure for resolution of a dispute between or \namong the Parties in which they will first attempt to resolve the dispute on an informal basis. \n \nDistribution System shall mean the Transmission Owner’s facilities and equipment, or \nthe Distribution System of another party that is interconnected with the Transmission Owner’s \nTransmission System, if any, connected to the Transmission System, over which facilities \nTransmission Service or Wholesale Distribution Service under the Tariff is available at the time \nInterconnection Customer has requested interconnection of a Generating Facility for the purpose \nof either transmitting electric energy in interstate commerce or selling electric energy at \nwholesale in interstate commerce and which are used to transmit electricity to ultimate usage \npoints such as homes and industries directly from nearby generators or from interchanges with \nhigher voltage transmission networks which transport bulk power over longer distances.  The \nvoltage levels at which distribution systems operate differ among Local Balancing Authorities \nand other entities owning distribution facilities interconnected to the Transmission System.   \n \nDistribution Upgrades shall mean the additions, modifications, and upgrades to the \nDistribution System at or beyond the Point of Interconnection to facilitate interconnection of the \nGenerating Facility and render the delivery service necessary to affect Interconnection \nCustomer’s wholesale sale of electricity in interstate commerce.  Distribution Upgrades do not \ninclude Interconnection Facilities. \n \nEffective Date shall mean the date on which this GIA becomes effective upon execution \nby the Parties subject to acceptance by the Commission, or if filed unexecuted, upon the date \nspecified by the Commission."},{"page":398,"startToken":110469,"endToken":110819,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \nElectric Reliability Organization shall mean the North American Electric Reliability \nCorporation or its successor organization. \n \nEmergency Condition shall mean a condition or situation:  (1) that in the reasonable \njudgment of the Party making the claim is imminently likely to endanger, or is contributing to \nthe endangerment of, life, property, or public health and safety; or (2) that, in the case of either \nTransmission Provider or Transmission Owner, is imminently likely (as determined in a non-\ndiscriminatory manner) to cause a material adverse effect on the security of, or damage to the \nTransmission System, Transmission Owner’s Interconnection Facilities or the electric systems of \nothers to which the Transmission System is directly connected; or (3) that, in the case of \nInterconnection Customer, is imminently likely (as determined in a non-discriminatory manner) \nto cause a material adverse effect on the security of, or damage to, the Generating Facility or \nInterconnection Customer’s Interconnection Facilities.  System restoration and blackstart shall be \nconsidered Emergency Conditions; provided that Interconnection Customer is not obligated by \nthis GIA to possess blackstart capability.  Any condition or situation that results from lack of \nsufficient generating capacity to meet load requirements or that results solely from economic \nconditions shall not constitute an Emergency Condition, unless one of the enumerated conditions \nor situations identified in this definition also exists. \n \nEnergy Displacement Agreement shall mean an agreement between an Interconnection \nCustomer with an Existing Generating Facility on the Transmission Provider’s Transmission \nSystem and an Interconnection Customer with a proposed Generating Facility seeking to \ninterconnect with Surplus Interconnection Service.  The Energy Displacement Agreement \nspecifies the term of operation, the Generating Facility Interconnection Service limit, and the \nmode of operation for energy production (common or singular operation). \n \nEnergy Resource Interconnection Service (ER Interconnection Service) shall mean \nan Interconnection Service that allows Interconnection Customer to connect its Generating \nFacility to the Transmission System or Distribution System, as applicable, to be eligible to \ndeliver the Generating Facility’s electric output using the existing firm or non-firm capacity of"},{"page":399,"startToken":110819,"endToken":111075,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nthe Transmission System on an as available basis.  Energy Resource Interconnection Service \ndoes not convey transmission service. \n \nEngineering & Procurement (E&P) Agreement shall mean an agreement that \nauthorizes Transmission Owner to begin engineering and procurement of long lead-time items \nnecessary for the establishment of the interconnection in order to advance the implementation of \nthe Interconnection Request. \n \nEnvironmental Law shall mean Applicable Laws or Regulations relating to pollution or \nprotection of the environment or natural resources. \n \nExisting Generating Facility shall mean a Generating Facility that is either under \nconstruction or is in service, and has an unsuspended interconnection agreement with its host \ntransmission provider. \n \nExpanded Scope Analysis shall mean the analysis described in Section 9.4.2.d.iv.a of \nRate Schedule 6 (MISO-SPP JOA). \nExpedited Resource Addition Study (ERAS) shall mean the temporary procedure for \nexpediting interconnection projects identified for claimed resource adequacy and/or reliability \nneeds. \n \nExpedited Generator Interconnection Agreement (EGIA) shall mean the \ninterconnection agreement for the Expedited Resource Addition Study established between the \nTransmission Provider and/or the Transmission Owner and the Interconnection Customer as set \nforth in Section 3.9 of this Attachment X.  This agreement shall take the form of the \nTransmission Provider’s pro forma Generator Interconnection Agreement modified for the \nExpedited Resource Addition Study.  Unless otherwise provided in the GIP, all requirements \napplicable to the pro forma Generator Interconnection Agreement shall apply to the Expedited \nGenerator Interconnection Agreement."},{"page":400,"startToken":111075,"endToken":111363,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nFacilities Construction Agreement (FCA) shall mean the form of facilities construction \nagreement, set forth in Appendix 8 to these Generator Interconnection Procedures.  The FCA \nshall be used when an Interconnection Customer or an Affected System Interconnection \nCustomer causes the need for the construction of Network Upgrades, Affected System Network \nUpgrades, or System Protection Facilities on the transmission system of the Transmission \nProvider.  \n  \nFast Track Process shall mean the procedure for evaluating an Interconnection Request \nfor a certified Small Generating Facility no larger than five MW that includes the screen set forth \nin Section 14, customer options meeting, and optional supplemental review. \n \nFederal Holiday shall mean a Federal Reserve Bank holiday for a Party that has its \nprincipal place of business in the United States and a Canadian Federal or Provincial banking \nholiday for a Party that has its principal place of business located in Canada. \n \nFederal Power Act shall mean the Federal Power Act, as amended, 16 U.S.C. §§ 791a \net seq. \n \nFERC shall mean the Federal Energy Regulatory Commission, also known as \nCommission, or its successor. \n \nFinal System Impact Study shall mean the Interconnection System Impact Study \nperformed during Definitive Planning Phase III. \n \nForce Majeure shall mean any act of God, labor disturbance, act of the public enemy, \nwar, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or \nequipment, any order, regulation or restriction imposed by governmental, military or lawfully \nestablished civilian authorities, or any other cause beyond a Party’s control.  A Force Majeure \nevent does not include an act of negligence or intentional wrongdoing by the Party claiming \nForce Majeure."},{"page":401,"startToken":111363,"endToken":111660,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nGenerating Facility shall mean Interconnection Customer’s device(s) for the production \nand/or storage for later injection of electricity identified in the Interconnection Request, but shall \nnot include the Interconnection Customer’s Interconnection Facilities. A Generating Facility \nconsists of one or more generating unit(s) and/or storage device(s) which usually can operate \nindependently and be brought online or taken offline individually. \n \nGenerating Facility Capacity shall mean the net capacity of the Generating Facility and \nthe aggregate net capacity of the Generating Facility where it includes  more than one device for \nthe production and/or storage for later injection of electricity. \n \nGenerating Facility Modification shall mean modification to an Existing Generating \nFacility, including comparable replacement of only a portion of its equipment at the Existing \nGenerating Facility.  \n \nGenerating Facility Replacement shall mean replacement of one or more generating \nunits and/or storage devices at the Existing Generating Facility with one or more new generating \nunits or storage devices at the same electrical Point of Interconnection as the generating units \nand/or storage devices that is/are being decommissioned and electrically disconnected. \n \nGenerator Interconnection Agreement (GIA) shall mean the form of interconnection \nagreement, set forth as Appendix 6 to Attachment X of the Tariff. \n \nGenerator Interconnection Procedures (GIP) shall mean the interconnection \nprocedures set forth in Attachment X of the Tariff. \n \nGenerator Upgrades shall mean the additions, modifications, and upgrades to the \nelectric system of an Existing Generating Facility or of a higher queued Generating Facility at or \nbeyond the Point of Interconnection to facilitate interconnection of the Generating Facility and \nrender the Transmission Service necessary to affect Interconnection Customer’s wholesale sale \nof electricity in interstate commerce."},{"page":402,"startToken":111660,"endToken":112004,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nGood Utility Practice shall mean any of the practices, methods and acts engaged in or \napproved by a significant portion of the electric industry during the relevant time period, or any \nof the practices, methods and acts which, in the exercise of reasonable judgment in light of the \nfacts known at the time the decision was made, could have been expected to accomplish the \ndesired result at a reasonable cost consistent with good business practices, reliability, safety and \nexpedition.  Good Utility Practice is not intended to be limited to the optimum practice, method, \nor act to the exclusion of all others, but rather to be acceptable practices, methods, or acts \ngenerally accepted in the region. \n \nGovernmental Authority shall mean any federal, state, local or other governmental \nregulatory or administrative agency, court, commission, department, board, or other \ngovernmental subdivision, legislature, rulemaking board, tribunal, or other governmental \nauthority having jurisdiction over the Parties, their respective facilities, or the respective services \nthey provide, and exercising or entitled to exercise any administrative, executive, police, or \ntaxing authority or power; provided, however, that such term does not include Interconnection \nCustomer, Transmission Provider, Transmission Owner, or any Affiliate thereof. \n \nGroup Restudy shall mean a restudy of a Group Study conducted pursuant to Section \n7.5 of the GIP. \n \nGroup Study(ies) shall mean the evaluation of one or more Interconnection Requests \nwithin a Cluster as described in Section 7 of the GIP.  Group Studies are divided into phases as \ndescribed in section 7.3 of the GIP. \n \nHazardous Substances shall mean any chemicals, materials or substances defined as or \nincluded in the definition of “hazardous substances,” “hazardous wastes,” “hazardous materials,” \n“hazardous constituents,” “restricted hazardous materials,” “extremely hazardous substances,” \n“toxic substances,” “radioactive substances,” “contaminants,” “pollutants,” “toxic pollutants” or \nwords of similar meaning and regulatory effect under any applicable Environmental Law, or any \nother chemical, material or substance, exposure to which is prohibited, limited or regulated by \nany applicable Environmental Law."},{"page":403,"startToken":112004,"endToken":112307,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \nHVDC Facilities shall mean the high voltage direct current transmission facilities, \nincluding associated alternating current facilities, if any, that are subject to Section 27A of the \nTariff and that are specifically identified in (i) any Agency Agreement pertaining to such \nfacilities between Transmission Provider and Transmission Owner that owns or operates such \nfacilities, or (ii) in any other arrangement that permits or will permit Transmission Provider to \nprovide HVDC Service over such facilities as set forth in Section 27A of the Tariff. \n \nHVDC Service shall mean Firm and Non-Firm Point-To-Point Transmission Service \nprovided by Transmission Provider on HVDC Facilities pursuant to Section 27A of the Tariff. \n \nInitial Synchronization Date shall mean the date upon which the Generating Facility is \ninitially synchronized and upon which Trial Operation begins. \n \nInjection Rights shall mean the Transmission Provider’s pre-certification of the \nTransmission System’s capability to receive capacity and energy from the MHVDC \nTransmission Line at the requested Point of Connection, and in the specified MW quantity, \nwithout degrading the reliability of the Transmission System, as described in Section 16 of the \nGIP and Section 3.2.3 of the MHCP. \n \nIn-Service Date (ISD) shall mean the date upon which Interconnection Customer \nreasonably expects it will be ready to begin use of the Transmission Owner’s Interconnection \nFacilities to obtain backfeed power. \n \nInterconnection Customer shall mean any entity, including Transmission Provider, \nTransmission Owner or any of the Affiliates or subsidiaries of either, that proposes to \ninterconnect its Generating Facility with the Transmission System. \n \nInterconnection Customer Decision Point I shall mean the time period beginning when \nthe Interconnection Customer is provided the Preliminary System Impact Study results including \ncost estimates for upgrades and concludes after fifteen (15) Business Days."},{"page":404,"startToken":112307,"endToken":112606,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \nInterconnection Customer Decision Point II shall mean the time period beginning \nwhen the Interconnection Customer is provided the Revised System Impact Study results \nincluding cost estimates for upgrades and concludes after fifteen (15) Business Days. \n \nInterconnection Customer’s Interconnection Facilities (ICIF) shall mean all facilities \nand equipment, as identified in Appendix A of this GIA, that are located between the Generating \nFacility and the Point of Change of Ownership, including any modification, addition, or upgrades \nto such facilities and equipment necessary to physically and electrically interconnect the \nGenerating Facility to the Transmission System or Distribution System, as applicable.  \nInterconnection Customer’s Interconnection Facilities are sole use facilities. \n \nInterconnection Facilities shall mean the Transmission Owner’s Interconnection \nFacilities and the Interconnection Customer’s Interconnection Facilities.  Collectively, \nInterconnection Facilities include all facilities and equipment between the Generating Facility \nand the Point of Interconnection, including any modification, additions or upgrades that are \nnecessary to physically and electrically interconnect the Generating Facility to the Transmission \nSystem.  Interconnection Facilities shall not include Distribution Upgrades, Generator Upgrades, \nStand Alone Network Upgrades or Network Upgrades. \n \nInterconnection Facilities Study(ies) shall mean a study conducted by Transmission \nOwner, or its agent, for Interconnection Customer(s) to determine a list of facilities (including \nInterconnection Customer’s Interconnection Facilities or Affected System Interconnection \nCustomer’s interconnection facilities, Transmission Owner’s Interconnection Facilities, System \nProtection Facilities, and if such upgrades have been determined, Network Upgrades, \nDistribution Upgrades, Generator Upgrades, Common Use Upgrades, and Affected System \nNetwork Upgrades, as identified in the Interconnection System Impact Study, Affected System \nStudy, or Affected System Operator’s applicable study), the cost of those facilities, and the time \nrequired to interconnect with the Transmission System or the Affected System Operator’s \ntransmission system."},{"page":405,"startToken":112606,"endToken":112898,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nInterconnection Facilities Study Agreement shall mean the form of agreement \ncontained in Appendix 4 of the Generator Interconnection Procedures for conducting the \nInterconnection Facilities Study. \n \nInterconnection Request shall mean (1) an Interconnection Customer’s request, in the \nform of Appendix 1 to the Generator Interconnection Procedures, to interconnect a new \nGenerating Facility, or a request for the Expedited Resource Addition Study for new generation \ncapacity, or to increase the capacity of, or make a Material Modification to the operating \ncharacteristics of, an Existing Generating Facility that is interconnected with the Transmission \nSystem, or to interconnect an Existing Generating Facility that is external to the Transmission \nSystem, or to change Energy Resource Interconnection Service to Network Resource \nInterconnection Service for an Existing Generating Facility; or (2) an MHVDC Connection \nCustomer’s request, in the form of Appendix 1 to the Generator Interconnection Procedures, to \nobtain Injection Rights.. \n \nInterconnection Service shall mean the service provided by Transmission Provider \nassociated with interconnecting the Generating Facility to the Transmission System, or external \nhost transmission provider if applicable,  and enabling it to receive electric energy and capacity \nfrom the Generating Facility at the Point of Interconnection pursuant to the terms of this \nGenerator Interconnection Agreement or Point of Delivery as set forth in the Service Agreement \nfor Network Resource Interconnection Service for an External Generating Facility and, if \napplicable, the Tariff. \n \nInterconnection Study (or Study) shall mean any of the studies described in the \nGenerator Interconnection Procedures. \n \nInterconnection Study Agreement shall mean the form of agreement contained in \nAttachment B to Appendix 1 of the Generator Interconnection procedures for conducting all \nstudies required by the Generator Interconnection Procedures."},{"page":406,"startToken":112898,"endToken":113156,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nInterconnection System Impact Study shall mean an engineering study that evaluates \nthe impact of the proposed interconnection on the safety and reliability of Transmission System \nand, if applicable, an Affected System.  The study shall identify and detail the system impacts \nthat would result if the Generating Facility were interconnected without project modifications or \nsystem modifications, or to study potential impacts, including but not limited to those identified \nin the Scoping Meeting as described in the Generator Interconnection Procedures. \n \nInterconnection Study Agreement shall mean the forms of agreement contained in \nAttachment B to Appendix 1 of the Generator Interconnection Procedures for conducting all \nstudies required by the Generator Interconnection Procedures. \n \nIRS shall mean the Internal Revenue Service. \n \nJoint Planning Agreement (“JPA”) shall mean an agreement between adjacent \nbalancing authorities or transmission providers for the coordination of planning. \n \nJoint Operating Agreement between the Midcontinent Independent System \nOperator, Inc. and Southwest Power Pool, Inc. (MISO-SPP JOA) shall mean Rate Schedule \n6 to the MISO Tariff. \n \nJoint Planning Agreement (“JPA”) shall mean an agreement between adjacent \nbalancing authorities or transmission providers for the coordination of planning. \n \nJoint Targeted Interconnection Queue (JTIQ) shall refer to the study and processes \ndescribed in Section 9.4.2 of Rate Schedule 6 (MISO-SPP JOA). \n \nJoint Targeted Interconnection Queue Study (“JTIQ Study”) shall mean a \ntransmission planning study conducted jointly by SPP and MISO to facilitate the interconnection \nof new generator capacity in both Parties’ regions."},{"page":407,"startToken":113156,"endToken":113477,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nJTIQ Commitment Group Member shall mean any JTIQ Commitment Group Member \nincluded in a Commitment Group consistent with Section 9.4 of Rate Schedule 6 (MISO-SPP \nJOA). \n \nJTIQ Commitment Group or Commitment Group shall mean a group of JTIQ \nCommitment Group Members that have executed a JTIQ Generator Interconnection Agreement \nwithin the twelve (12) month period ending April 30th of each year.  The Commitment Group \nshall also include JTIQ Commitment Group Members for which a JTIQ Generator \nInterconnection Agreement has been filed unexecuted by SPP or the Transmission Provider and \nthe Commission has accepted the agreement within the twelve (12) month period ending April \n30th of each year. \n \nJTIQ Generator Charge shall mean the charge to JTIQ Commitment Group Members \nto recover the JTIQ Commitment Group Member’s share of the JTIQ Monthly Revenue \nRequirement for each of the JTIQ Upgrades in the JTIQ Portfolio in the Transmission Provider’s \nRegion. \n \nJTIQ Participation Group shall mean the group of Interconnection Requests that shall \nconsist of all interconnection customers included in the JTIQ Screening Groups whose \ninterconnection request meets the distribution factor and impact criteria specified in Section \n9.4.2(d)((ii) of Rate Schedule 6 (MISO-SPP JOA). \n \nJTIQ Portfolio shall mean a group of JTIQ Upgrades identified pursuant to Section 9.4 \nof Rate Schedule 6 (MISO-SPP JOA). \n \nJTIQ Screening Group shall mean a group of MISO Interconnection Customers and \nSPP interconnection customers whose Interconnection Requests will be screened for inclusion in \na JTIQ Participation Group. The JTIQ Screening Group shall consist of all interconnection \ncustomers who have submitted interconnection requests into a MISO ERAS, SPP ERAS, DPP \nstudy cluster, or SPP DISIS study cluster that: (1) has a study commencement or kick off date \nthat is after the date that the Parties’ respective Boards of Directors have approved a JTIQ"},{"page":408,"startToken":113477,"endToken":113790,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nPortfolio; and (2) has not commenced DPP Phase I, a MISO ERAS, the SPP ERAS or DISIS \nPhase One studies pursuant to each party’s OATT as of the date that the Parties have declared \nthe JTIQ Portfolio fully subscribed.  \n \nJTIQ Service Agreements shall mean the JTIQ Commitment Agreement attached to the \nMISO GIA as Appendix 17 and the SPP’s pro forma agreement(s)  that obligate interconnection \ncustomers to provide security for and  pay the JTIQ Generator Charge for JTIQ Network \nUpgrades included in the applicable JTIQ Portfolio. \n \nJTIQ Upgrade shall mean a Network Upgrade included in a JTIQ portfolio pursuant to \nSection 9.4 of Rate Schedule 6 (MISO-SPP JOA).  \n \nLocal Balancing Authority shall mean an operational entity or a Joint Registration \nOrganization which is (i) responsible for compliance with the subset of Electric Reliability \nOrganization Balancing Authority Reliability Standards defined in the Balancing Authority \nAgreement for their local area within the MISO Balancing Authority Area, (ii) a Party to \nBalancing Authority Agreement, excluding MISO, and (iii) provided in the Balancing Authority \nAgreement. \n \nLocal Resource Zone (LRZ) shall mean a geographic area within the Transmission \nProvider Region that is prescribed by the Transmission Provider, based upon the criteria in \nSection 68A.3, to address congestion that limits Planning Resource deliverability.   \n \nLoss shall mean any and all damages, losses, claims, including claims and actions \nrelating to injury to or death of any person or damage to property, demand, suits, recoveries, \ncosts and expenses, court costs, attorney fees, and all other obligations by or to third parties, \narising out of or resulting from the other Party’s performance, or non-performance of its \nobligations under this GIA on behalf of the indemnifying Party, except in cases of gross \nnegligence or intentional wrongdoing, by the indemnified party."},{"page":409,"startToken":113790,"endToken":114100,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nMaterial Modification shall mean: (1) modification to an Interconnection Request in the \nqueue, that has a material adverse impact on the cost or timing of any other Interconnection \nRequest with an equal or later queue priority date; or Qualified Change.   \n \nMetering Equipment shall mean all metering equipment installed or to be installed at \nthe Generating Facility, Interconnection Customer’s Interconnection Facilities, and/or \nTransmission Owner's Interconnection Facilities pursuant to this GIA at the metering points, \nincluding but not limited to instrument transformers, MWh-meters, data acquisition equipment, \ntransducers, remote terminal unit, communications equipment, phone lines, and fiber optics. \n \nMonitoring and Consent Agreement shall mean an agreement that defines the terms \nand conditions applicable to a Generating Facility acquiring Surplus Interconnection Service.  \nThe Monitoring and Consent Agreement will list the roles and responsibilities of an \nInterconnection Customer seeking to interconnect with Surplus Interconnection Service and \nTransmission Owner to maintain the total output of the Generating Facility inside the parameters \ndelineated in the GIA. \n \nMulti-Party Facilities Construction Agreement (MPFCA) shall mean the form of \nfacilities construction agreement, set forth in Appendix 9 to these Generator Interconnection \nProcedures.  The MPFCA shall be used when multiple Interconnection Requests or \ninterconnection requests from Affected System Interconnection Customers cause the need for the \nconstruction of Common Use Upgrades on the Transmission System and share cost \nresponsibility for such Common Use Upgrades.   \n \nNetwork Customer shall have that meaning as provided in the Tariff. \n \nNetwork Resource shall mean any designated generating resource owned, purchased, or \nleased by a Network Customer under the Tariff.  Network Resources do not include any \nresource, or any portion thereof, that is committed for sale to third parties or otherwise cannot be \ncalled upon to meet the Network Customer’s Network Load on a non-interruptible basis."},{"page":410,"startToken":114100,"endToken":114371,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nNetwork Resource Interconnection Service (NR Interconnection Service) shall mean \nan Interconnection Service that allows Interconnection Customer to integrate its Generating \nFacility with the Transmission System in the same manner as for any Generating Facility being \ndesignated as a Network Resource.  Network Resource Interconnection Service does not convey \ntransmission service.  Network Resource Interconnection Service shall include any network \nresource interconnection service established under an agreement with, or the tariff of, a \nTransmission Owner prior to integration into MISO, that is determined to be deliverable through \nthe integration deliverability study process. \n \nNetwork Upgrades shall mean the additions, modifications, and upgrades to the \nTransmission System required at or beyond the point at which the Interconnection Facilities \nconnect to the Transmission System or Distribution System, as applicable, to accommodate the \ninterconnection of the Generating Facility(ies) to the Transmission System.  Network Upgrades \nshall not include any HVDC Facility Upgrades. \n \nNotice of Dispute shall mean a written notice of a dispute or claim that arises out of or in \nconnection with this GIA or its performance. \n \nOptional Interconnection Study shall mean a sensitivity analysis based on assumptions \nspecified by Interconnection Customer in the Optional Interconnection Study Agreement. \n \nOptional Interconnection Study Agreement shall mean the form of agreement \ncontained in Appendix 5 of the Generator Interconnection Procedures for conducting the \nOptional Interconnection Study. \n \nOutage Transfer Distribution Factor (OTDF) Outage Transfer Distribution Factor, as \ndefined by the Electric Reliability Organization. \n \nParty or Parties shall mean Transmission Provider, Transmission Owner, \nInterconnection Customer, or any combination of the above."},{"page":411,"startToken":114371,"endToken":114655,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \nPermissible Technological Advancement shall mean advancements to turbines, \ninverters, plant supervisory controls, excitation systems, or other technological advancements \nsubmitted to the Transmission Provider prior to the issuance of this draft Generator \nInterconnection Agreement for such project provided that such advancements does not: (1) \ndegrade the electrical characteristics of the generating equipment; (2) does not cause any material \nadverse impact on the Transmission System with regard to short circuit capability limits, steady-\nstate thermal and voltage limits, or dynamic system stability and response; (3) does not increase \nthe installed capacity of the Generating Facility; or (4) change the fuel source of the proposed \nGenerating Facility.   \n \nPoint of Change of Ownership (PCO) shall mean the point, as set forth in Appendix A \nto the Generator Interconnection Agreement, where the Interconnection Customer’s \nInterconnection Facilities connect to the Transmission Owner’s Interconnection Facilities. \n \nPoint of Interconnection (POI) shall mean the point, as set forth in Appendix A of the \nGIA, where the Interconnection Facilities connect to the Transmission System. \n \nPoint(s) of Withdrawal (POW) shall mean the point(s) where a non-transmission \nfacility used to withdraw Energy from the Transmission System to serve Load connects to the \nTransmission System.  \n \nPotential MW Total shall mean a projection of the number of MW that may commit to \nthe JTIQ Portfolio from all ERAS and study clusters to date, including the current study \ncluster(s).   \n \nPreliminary System Impact Study shall mean the Interconnection System Impact Study \nperformed during Definitive Planning Phase I. \n \nPre-Queue Phase shall mean Interconnection Customer outreach and education effort \nundertaken prior to the submission of the Interconnection Request."},{"page":412,"startToken":114655,"endToken":114970,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \nProportional Impact Method shall mean a technical analysis conducted by \nTransmission Provider to determine the degree to which each Generating Facility in the Group \nStudy contributes to the need for a specific Network Upgrade. \n \nProvisional Generator Interconnection Agreement shall mean the interconnection \nagreement for Provisional Interconnection Service established between the Transmission \nProvider and/or the Transmission Owner and the Interconnection Customer as set forth in \nSection 7.9 of this Attachment X.  This agreement shall take the form of the Generator \nInterconnection Agreement modified for provisional purposes.  Unless otherwise provided in the \nGIP, all requirements applicable to the Generator Interconnection Agreement shall apply to the \nProvisional Generator Interconnection Agreement. \n \nProvisional Interconnection Service shall mean Interconnection Service provided by \nthe Transmission Provider associated with interconnecting the Interconnection Customer’s \nGenerating Facility to the Transmission Provider’s Transmission System and enabling that \nTransmission System to receive electric energy and capacity from the Generating Facility at the \nPoint of Interconnection, pursuant to the terms of the Provisional Generator Interconnection \nAgreement and the Tariff. \n \nProvisional Interconnection Study shall mean an engineering study, performed at \nInterconnection Customer’s request, as a condition to entering into a Provisional Generator \nInterconnection Agreement,  that evaluates the impact of the proposed interconnection on the \nsafety and reliability of the Transmission System and, if applicable, any Affected System.  The \nstudy shall identify and detail the impacts on the Transmission System and, if applicable, an \nAffected System, from stability, short circuit, and voltage issues that would result if the \nGenerating Facility were interconnected without project modifications or system modifications. \n \nQualified Change shall mean a planned modification to an Existing Generating Facility \nthat is undergoing evaluation for a Generating Facility Modification or Generating Facility \nReplacement, and has a material adverse impact on the Transmission System with respect to: i)"},{"page":413,"startToken":114970,"endToken":115277,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nsteady-state thermal or voltage limits, ii) dynamic system stability and response, or iii) short-\ncircuit capability limit; compared to the impacts of the Existing Generating Facility prior to the \nmodification or replacement. \n \nQueue Position shall mean the order of a valid Interconnection Request, relative to all \nother pending valid Interconnection Requests pursuant to Section 4.1 of the GIP. \n \nReasonable Efforts shall mean, with respect to an action required to be attempted or \ntaken by a Party under this Generator Interconnection Agreement, efforts that are timely and \nconsistent with Good Utility Practice and are otherwise substantially equivalent to those a Party \nwould use to protect its own interests. \n \nRelevant Electric Retail Regulatory Authority (RERRA) shall mean an entity that has \njurisdiction over and establishes prices and/or policies for providers of retail electric service to \nend-customers, such as the city council for a municipal utility, the governing board of a \ncooperative utility, the state public utility commission or any such entity. \n \nReliability Assessment Study shall mean an engineering study that evaluates the impact \nof a proposed Generating Facility Replacement on the reliability of Transmission System during \nthe time period between the date that the Existing Generating Facility ceases commercial \noperations and the Commercial Operation Date of the Replacement Generating Facility. \n \nReplacement Generating Facility shall mean a Generating Facility that replaces an \nExisting Generating Facility, or a portion thereof, at the same electrical Point of Interconnection \npursuant to Section 3.7 of this Attachment X. \n \nReplacement Impact Study shall mean an engineering study that evaluates the impact of \na proposed Generating Facility Replacement on the reliability of the Transmission System. \n \nRevised System Impact Study shall mean the Interconnection System Impact Study \nperformed during Definitive Planning Phase II."},{"page":414,"startToken":115277,"endToken":115628,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \nScoping Meeting shall mean the meeting between representatives of Interconnection \nCustomer, Transmission Owner, Affected System  and Transmission Provider conducted for the \npurpose of discussing the proposed Interconnection Request and any alternative interconnection \noptions, exchanging information including any transmission data and earlier study evaluations \nthat would be reasonably expected to impact such interconnection options,  refining information \nand models provided by Interconnection Customer(s), discussing the Group Study materials \nposted to OASIS pursuant to Section 3.4 of the GIP, and analyzing such information. \n \nShared Interconnection Request shall mean (1) multiple Interconnection Customer’s \nrequest, in the form of Appendix 1 to the Generator Interconnection Procedures, to interconnect \nnew Generating Facilities, or to increase the capacity of, or make a Material Modification to the \noperating characteristics of, Existing Generating Facilities that are interconnected with the \nTransmission System, or to interconnect Existing Generating Facilities that are external to the \nTransmission System, or to change Energy Resource Interconnection Service to Network \nResource Interconnection Service for Existing Generating Facilities; or (2) multiple MHVDC \nConnection Customer’s request, in the form of Appendix 1 to the Generator Interconnection \nProcedures, to obtain Injection Rights. \n \nShared Network Upgrade shall mean a Network Upgrade or Common Use Upgrade that \nis funded by an Interconnection Customer(s), including when the Transmission Owner elects to \nfund the capital cost of such a Network Upgrade or Common Use Upgrade under Section 11.3 of \nthe GIA, and also benefits other Interconnection Customer(s) that are later identified as \nbeneficiaries.  \n \nSite Control shall mean a documented right for one or more parcels of land for the \npurpose of constructing a Generating Facility, Interconnection Customer’s Interconnection \nFacilities, and, if applicable (i.e., when the Interconnection Customer is providing the site for \nsuch facilities), the Transmission Owner’s Interconnection Facilities and Network Upgrades at \nthe POI that the Interconnection Customer will develop.  Such documented right shall be one of \nthe following:  (1) ownership of a site; (2) a leasehold interest in a site; or (3) an option to"},{"page":415,"startToken":115628,"endToken":115988,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\npurchase or acquire a leasehold interest in a site; or (4) any other contractual or legal right to \npossess or occupy a site.  Transmission Provider will maintain acreage requirements for each \nGenerating Facility type on its OASIS or public website. \n \nSmall Generating Facility shall mean a Generating Facility that has an aggregate net \nGenerating Facility Capacity of no more than five MW and meets the requirements of Section 14 \nand Appendix 3 of the GIP.  \n \nSouthwest Power Pool (SPP) shall refer to the Southwest Power Pool, Inc. the Regional \nTransmission Organization that is the counterparty to Rate Schedule 6 (MISO-SPP JOA). \n \nSpecial Protection System (SPS) shall mean an automatic protection system or remedial \naction scheme designed to detect abnormal or predetermined system conditions, and take \ncorrective actions other than and/or in addition to the isolation of faulted components, to \nmaintain system reliability.  Such action may include changes in demand (MW and MVar), \nenergy (MWh and MVarh), or system configuration to maintain system stability, acceptable \nvoltage, or power flows.  An SPS does not include (a) underfrequency or undervoltage load \nshedding, (b) fault conditions that must be isolated, (c) out-of-step relaying not designed as an \nintegral part of an SPS, or (d) Transmission Control Devices. \n \nStand Alone Network Upgrades shall mean Network Upgrades, that are not part of an \nAffected System or a JTIQ Upgrade, that Interconnection Customer may construct without \naffecting day-to-day operations of the Transmission System during their construction.  \nTransmission Provider, Transmission Owner and Interconnection Customer must agree as to \nwhat constitutes Stand Alone Network Upgrades and identify them in Appendix A to this GIA.  \nIf the Transmission Provider or Transmission Owner and Interconnection Customer disagree \nabout whether a particular Network Upgrade is a Stand Alone Network Upgrade, the \nTransmission Provider or Transmission Owner that disagrees with the Interconnection Customer \nmust provide the Interconnection Customer a written technical explanation outlining why the \nTransmission Provider or Transmission Owner does not consider the Network Upgrade to be a \nStand Alone Network Upgrade within fifteen (15) Business Days of its determination."},{"page":416,"startToken":115988,"endToken":116317,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \nSupplemental Affected System Analysis shall mean the affected systems analysis \ndescribed in Section 7.3.2.3.1 of this GIP and Section 9.4.2.e.iii.a.i of the Rate Schedule 6 \n(MISO-SPP JOA) to determine if Supplemental Affected System Upgrades are required for one \nor more JTIQ Participation Group member(s). \n \nSubstation Network Upgrades shall mean Network Upgrades that are required at or \nnear the Point of Interconnection and are identified in the first portion of the Interconnection \nFacilities Study as described in GIP Section 7.3.2.5. \n \nSupplemental Affected System Upgrade shall mean a Network Upgrade in addition to \nthose required to address the impact of interconnection requests in the current study cluster as \ndescribed in Section 9.4.2.e.iii.a.i of Rate Schedule 6 (MISO-SPP-JOA). \n \nSurplus Interconnection Service shall mean any Interconnection Service that is derived \nfrom the unneeded portion of Interconnection Service established in a GIA or in agreement with, \nor under the tariff of, a Transmission Owner prior to integration into MISO, such that if Surplus \nInterconnection Service is utilized the total amount of Interconnection Service at the Point of \nInterconnection would remain the same. \n \nSystem Planning and Analysis Phase shall mean the phase of the Generator \nInterconnection Procedure process, prior to January 4, 2017, which consisted of an \nInterconnection System Impact Study for those Interconnection Requests that were studied in \nthis phase.   \n \nSystem Protection Facilities shall mean the equipment, including necessary protection \nsignal communications equipment, required to protect (1) the Transmission System or other \ndelivery systems or other generating systems from faults or other electrical disturbances \noccurring at the Generating Facility and (2) the Generating Facility from faults or other electrical \nsystem disturbances occurring on the Transmission System or on other delivery systems or other \ngenerating systems to which the Transmission System is directly connected."},{"page":417,"startToken":116317,"endToken":116664,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \nTarget MW Value shall mean the projected new generation interconnection MW \nenabled by the JTIQ Portfolio.  The Target MW Value for each JTIQ Portfolio shall be identified \nin Section 9.4 and related subsections of Rate Schedule 6. \n \nTariff shall mean the Transmission Provider’s Tariff through which open access \ntransmission service and Interconnection Service are offered, as filed with the Commission, and \nas amended or supplemented from time to time, or any successor tariff.   \n \nThreshold Charge shall mean the charge calculated using an estimate of plant in service \nvalue for the JTIQ Portfolio, excluding amounts funded under the GRIP Program, as described in \nSection 9.4.2 of Rate Schedule 6 (MISO-SPP JOA). \n \nTransient Tolerance Window shall mean the period of time after a reduction or loss of \nload by the ZG Associated Load by the end of which window the Generating Facility with ZG \nInterconnection Service must have reduced its injections to an amount not greater than the Load \nof the ZG Associated Load.  The Transient Tolerance Window shall be no greater than 20 \nseconds, and is further described by the Business Practices Manual for Large Load.  The \nTransient Tolerance Window will be subject to Transmission Owner local planning criteria. \n \nTransmission Control Devices shall mean a generally accepted transmission device that \nis planned and designed to provide dynamic control of electric system quantities, and are usually \nemployed as solutions to specific system performance issues.  Examples of such devices include \nfast valving, high response exciters, high voltage DC links, active or real power flow control and \nreactive compensation devices using power electronics (e.g., unified power flow controllers), \nstatic var compensators, thyristor controlled series capacitors, braking resistors, and in some \ncases mechanically-switched capacitors and reactors.  In general, such systems are not \nconsidered to be Special Protection Systems. \n \nTransmission Owner shall mean that Transmission Owner as defined in the Tariff, \nwhich includes an entity that owns, leases or otherwise possesses an interest in the portion of the"},{"page":418,"startToken":116664,"endToken":116968,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nTransmission System at which Interconnection Customer proposes to interconnect or otherwise \nintegrate the operation of the Generating Facility.  Transmission Owner should be read to include \nany Independent Transmission Company that manages the transmission facilities of \nTransmission Owner and shall include, as applicable, the owner and/or operator of distribution \nfacilities interconnected to the Transmission System, over which facilities transmission service \nor Wholesale Distribution Service under the Tariff is available at the time Interconnection \nCustomer requests Interconnection Service and to which Interconnection Customer has requested \ninterconnection of a Generating Facility for the purpose of either transmitting electric energy in \ninterstate commerce or selling electric energy at wholesale in interstate commerce. \n \nTransmission Provider shall mean the Midcontinent Independent System Operator, Inc. \n(“MISO”), the Regional Transmission Organization that controls or operates the transmission \nfacilities of its transmission-owning members used for the transmission of electricity in interstate \ncommerce and provides transmission service under the Tariff. \n \nTransmission Owner’s Interconnection Facilities (TOIF) shall mean all facilities and \nequipment owned by Transmission Owner from the Point of Change of Ownership to the Point \nof Interconnection as identified in Appendix A to this GIA, including any modifications, \nadditions or upgrades to such facilities and equipment.  Transmission Owner’s Interconnection \nFacilities are sole use facilities and shall not include Distribution Upgrades, Generator Upgrades, \nStand Alone Network Upgrades or Network Upgrades.  \n \nTransmission System shall mean the facilities owned by Transmission Owner and \ncontrolled or operated by Transmission Provider or Transmission Owner that are used to provide \nTransmission Service (including HVDC Service) or Wholesale Distribution Service under the \nTariff.  \n \nTrial Operation shall mean the period during which Interconnection Customer is \nengaged in on-site test operations and commissioning of the Generating Facility prior to \nCommercial Operation."},{"page":419,"startToken":116968,"endToken":117312,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nUser-Defined Model shall mean any set of programming code created by equipment \nmanufacturers or developers that captures the latest features of controllers that are mainly \nsoftware-based and represent the entities’ control strategy but does not necessarily correspond to \nany particular generic library model, as contained in Attachment A to Appendix 1 of the GIP. \n \nVariable Energy Resource shall mean a device for the production of electricity that is \ncharacterized by an energy source that: (1) is renewable; (2) cannot be stored by the facility \nowner or operator; and (3) has variability that is beyond the control of the facility owner or \noperator. \n \nWholesale Distribution Service shall have that meaning as provided in the Tariff.  \nWherever the term “transmission delivery service” is used, Wholesale Distribution Service shall \nalso be implied. \n \nZero Injection Generation (ZG) Associated Load shall mean a source of electrical load \nthat has a Point of Withdrawal that is at the same substation as the Point of Interconnection to the \nTransmission System (i.e. same voltage level at the interconnecting substation) as the Generating \nFacility with ZG Interconnection Service that will serve it. \n \nZero Injection Generation (ZG) Interconnection Service shall mean a limited form of \nInterconnection Service that allows an Interconnection Customer to connect its Generating \nFacility to the Transmission System or Distribution System, as applicable, for the limited \npurpose of delivering energy to ZG Associated Load.  ZG Interconnection Service does not grant \nany right to inject energy onto the Transmission System except as may be authorized by Section \n3.11 of the Generator Interconnection Procedures.  ZG Interconnection Service does not convey \nTransmission Service.  ZG Interconnection Service also does not provide a right to serve, or a \nright to Transmission Service to serve, a ZG Associated Load or retail customer except as \nallowed by applicable state law. \n \nZero Injection Generation (ZG) Resource shall mean a generating resource with an \nAttachment X defined ZG Interconnection Agreement.  A ZG Resource may participate as a"},{"page":420,"startToken":117312,"endToken":117627,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nGeneration Resource, Dispatchable Intermittent Resource, Electric Storage Resource, or Behind \nthe Meter Generation resource. \nZG Facilities Study shall mean the study described in Section 3.2.5.2.2 of these GIP that \nis used to identify any Network Upgrades or Interconnection Facilities that may be needed to for  \nan Interconnection Request seeking ZG Interconnection Service. \n \nZG Impact Assessment shall mean the study described in Section 3.2.5.2.1 of these GIP \nthat is used to evaluate the impact of an Interconnection Request seeking ZG Interconnection \nServices. \n \nZG Interconnection Agreement (ZGIA) shall mean the form of interconnection \nagreement governing the terms and conditions of ZG Interconnection Service, set forth in \nAppendix 19 to the GIP.  This agreement shall follow the form of the Transmission Provider’s \npro forma Generator Interconnection Agreement with modifications to reflect ZG \nInterconnection Service and the ZG Interconnection Service study process.  Unless otherwise \nprovided in the GIP, all requirements applicable to the pro forma Generator Interconnection \nAgreement shall apply to the ZGIA.  A ZGIA is a form of GIA and, where used in the Tariff, \nreferences to Generator Interconnection Agreements or GIAs encompasses ZGIAs. \n \nZG Interconnection Process Quarterly Study Period shall mean the period of time in \nwhich Interconnection Requests seeking ZG Interconnection Service are submitted to the \nTransmission Provider and compiled for study.  There are four study periods in a year with the \nfollowing start and end dates: \nQuarter 1: The first Business Day of March through the last Business Day of May; \nQuarter 2: The first Business Day of June through the last Business Day of August; \nQuarter 3: The first Business Day of September through the last Business Day of \nNovember; \nQuarter 4: The first Business Day of December through the last Business Day of \nFebruary."},{"page":421,"startToken":117627,"endToken":117957,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nARTICLE 2.  EFFECTIVE DATE, TERM AND TERMINATION \n \n2.1 \nEffective Date.  This ZGIA shall become effective upon execution by the Parties subject \nto acceptance by FERC (if applicable), or if filed unexecuted, upon the date specified by \nFERC.  Transmission Provider shall promptly file this ZGIA with FERC upon execution \nin accordance with Article 3.1, if required. \n \n2.2 \nTerm of Agreement.  Subject to the provisions of Article 2.3, this ZGIA shall remain in \neffect for a period of ______ years from the Effective Date and shall be automatically \nrenewed for each successive one-year period thereafter on the anniversary of the \nEffective Date. \n \n2.3 \nTermination Procedures.  This ZGIA may be terminated as follows: \n \n2.3.1 Written Notice.  This ZGIA may be terminated by Interconnection Customer \nafter giving Transmission Provider and Transmission Owner ninety (90) Calendar \nDays advance written notice.  This ZGIA shall be terminated by Transmission \nProvider if the Generating Facility or a portion of the Generating Facility fails to \nachieve Commercial Operation by the Commercial Operation Date established in \naccordance with Section 4.4.4 of Attachment X, including any extension provided \nthereunder, or has ceased Commercial Operation for three (3) consecutive years, \nbeginning with the last date of Commercial Operation for the Generating Facility, \nafter giving Interconnection Customer ninety (90) Calendar Days advance written \nnotice.  Where only a portion of the Generating Facility fails to achieve \nCommercial Operation by the Commercial Operation Date established in \naccordance with Section 4.4.4 of Attachment X, including any extension provided \nthereunder, Transmission Provider shall only terminate that portion of the ZGIA.  \nNotwithstanding the foregoing, in the limited circumstance that the \nInterconnection Request is served by a contingent Network Upgrade with an in-\nservice date that is farther out than the Commercial Operation Date permitted \nunder Section 4.4.4 of Attachment X, Transmission Provider shall only terminate"},{"page":422,"startToken":117957,"endToken":118275,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nthis ZGIA for failure to achieve Commercial Operation by that later in-service \ndate of the contingent Network Upgrade.  For the purposes of this ZGIA, \nCommercial Operation shall mean the supply of energy from the Generating \nFacility to the ZG Associated Load identified in Appendix A and exclude sales of \nenergy, capacity, or other commercial arrangements regarding the output of the \nGenerating Facility with any entity or load source other than the ZG Associated \nLoad identified in Appendix A.  The Generating Facility will not be deemed to \nhave ceased Commercial Operation for purposes of this Article 2.3.1 if \nInterconnection Customer can document that it has taken other significant steps to \nmaintain or restore operational readiness of the Generating Facility for the \npurpose of returning the Generating Facility to Commercial Operation as soon as \npossible. \n \n2.3.1.1 Surplus Interconnection Service. Where this ZGIA provides for Surplus \nInterconnection Service and the Energy Displacement Agreement or the \nMonitoring and Consent Agreement required for Surplus Interconnection \nService are no longer in effect, Interconnection Customer shall \nimmediately cease Commercial Operation of the Generating Facility and \nthis ZGIA shall be deemed terminated.  In the event that the Existing \nGenerating Facility retires and/or permanently ceases commercial \noperation, the Surplus Interconnection Service provided under this ZGIA \nshall terminate except as provided in Section 3.3.1.3 of the GIP. \n \n2.3.2 Default.  Any Party may terminate this ZGIA in accordance with Article 17. \n \n2.3.3 Notwithstanding Articles 2.3.1 and 2.3.2, no termination shall become effective \nuntil the Parties have complied with all Applicable Laws and Regulations \napplicable to such termination, including the filing with FERC of a notice of \ntermination of this ZGIA, if required, which notice has been accepted for filing by \nFERC."},{"page":423,"startToken":118275,"endToken":118660,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nFor EGIAs, no termination shall become effective until Interconnection Customer \nhas provided all security as required by Section 2.4. \n \n \n2.4 \nTermination Costs.  If a Party elects to terminate this ZGIA pursuant to Article 2.3 \nabove, each Party shall pay all costs incurred for which that Party is responsible \n(including any cancellation costs relating to orders or contracts for Interconnection \nFacilities, applicable upgrades, and related equipment) or charges assessed by the other \nParties, as of the date of the other Parties’ receipt of such notice of termination, under this \nZGIA. In the event that this ZGIA is terminated by Interconnection Customer, \nInterconnection Customer is responsible for all financial impact that is caused as a result \nof this termination or the termination of Interconnection Customer’s FCA(s) or \nMPFCA(s), such financial impact being determined through the financial impact analysis \nperformed in accordance with Section 7.8 of Attachment X. In the event of termination \nby a Party, the Parties shall use commercially Reasonable Efforts to mitigate the costs, \ndamages and charges arising as a consequence of termination.  Upon termination of this \nZGIA, unless otherwise ordered or approved by FERC: \n \nIn the event that this EGIA is terminated by Interconnection Customer that had an \nInterconnection Request studied in ERAS, Interconnection Customer is responsible for \nthe full cost of all Network Upgrades identified in this EGIA as well as any Network \nUpgrades identified during the ERAS process that are to be memorialized in an \nagreement other that this EGIA, including any applicable FCA, MPFCA, or JTIQ Service \nAgreements.  If the Network Upgrade costs for Network Upgrades subject to an FCA, \nMPFCA, or JTIQ Service Agreement have not been finalized or the Interconnection \nCustomer has not made the payment under such agreement as of the date that termination \nof this EGIA is sought, Interconnection Customer shall provide the payment or security \nfor such Network Upgrades in the amount required by the applicable agreement.  If such \nagreement has not been executed and final costs are not available as of a date that \ntermination is sought, Interconnection Customer shall provide such payment or security \nin an amount corresponding to the most recent estimate provided by the Transmission"},{"page":424,"startToken":118660,"endToken":119011,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nProvider during the ERAS process.  Interconnection Customer shall pay or Transmission \nProvider shall refund, as applicable, to Interconnection Customer the difference between \nthe amount of any estimated payment or security made pursuant to this Article and the \nfinal cost of such NU within ninety (90) Calendar Days after such final costs are invoiced \nto the Interconnection Customer. \n \n \n2.4.1 With respect to any portion of the Transmission Owner’s Interconnection \nFacilities, Network Upgrades, System Protection Facilities, Distribution \nUpgrades, Generator Upgrades, and if so determined and made a part of this \nZGIA, upgrades on Affected Systems, that have not yet been constructed or \ninstalled, Transmission Owner shall to the extent possible and to the extent of \nInterconnection Customer’s written notice under Article 2.3.1, cancel any pending \norders of, or return, any materials or equipment for, or contracts for construction \nof, such facilities; provided that in the event Interconnection Customer elects not \nto authorize such cancellation, Interconnection Customer shall assume all \npayment obligations with respect to such materials, equipment, and contracts, and \nTransmission Owner shall deliver such material and equipment, and, if necessary, \nassign such contracts, to Interconnection Customer as soon as practicable, at \nInterconnection Customer’s expense.  To the extent that Interconnection \nCustomer has already paid Transmission Owner for any or all such costs of \nmaterials or equipment not taken by Interconnection Customer or upgrades not \nyet constructed, Transmission Owner shall promptly transfer such amounts to \nTransmission Provider, less any costs, including penalties incurred by \nTransmission Owner to cancel any pending orders of or return such materials, \nequipment, or contracts.  Except for agreements providing for ZG Interconnection \nService, Transmission Provider will perform a financial impact analysis in \naccordance with Section 7.8 of Attachment X to determine the amount that should \nbe refunded to Interconnection Customer.  Except for agreements providing for \nZG Interconnection Service, Transmission Provider shall refund such remaining \namounts to Interconnection Customer, less the amount of Automatic Withdrawal \nPenalty funds received by the Interconnection Customer in accordance with"},{"page":425,"startToken":119011,"endToken":119346,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nSection 7.8.1 of the Attachment X and less any financial impact caused by the \ntermination of this ZGIA or Interconnection Customer’s FCA(s) or MPFCA(s), as \ndetermined through the analysis performed in accordance with Section 7.8 of \nAttachment X. If Interconnection Customer made its payment(s) through a letter \nof credit, surety bond, or parental guarantee, Transmission Owner will draw \nagainst that letter of credit, surety bond, or parental guarantee in an amount \ndetermined through the analysis performed in accordance with Section 7.8 of \nAttachment X plus the amount of any Automatic Withdrawal Penalty funds \nreceived by the Interconnection Customer in accordance with Section 7.8.1 of the \nAttachment X, and transfer that amount to Transmission Provider, unless \nInterconnection Customer funds the financial impact through another means. \n \nIf an Interconnection Customer terminates this ZGIA, it shall be responsible for \nall costs incurred in association with that Interconnection Customer’s \ninterconnection, including any cancellation costs relating to orders or contracts for \nInterconnection Facilities and equipment, and other expenses including any \nupgrades or related equipment for which Transmission Owner has incurred \nexpenses and has not been reimbursed by Interconnection Customer. \n \n2.4.2 Transmission Owner may, at its option, retain any portion of such materials, \nequipment, or facilities that Interconnection Customer chooses not to accept \ndelivery of, in which case Transmission Owner shall be responsible for all costs \nassociated with procuring such materials, equipment, or facilities.  If \nTransmission Owner does not so elect, then Interconnection Customer shall be \nresponsible for such costs. \n \n2.4.3 With respect to any portion of the Interconnection Facilities, and any other \nfacilities already installed or constructed pursuant to the terms of this ZGIA, \nInterconnection Customer shall be responsible for all costs associated with the \nremoval, relocation, reconfiguration or other disposition or retirement of such \nmaterials, equipment, or facilities, and such other expenses actually incurred by"},{"page":426,"startToken":119346,"endToken":119632,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nTransmission Owner necessary to return the Transmission, Distribution or \nGenerator System, as applicable, to safe and reliable operation. \n \n2.5 \nDisconnection.  Upon termination of this ZGIA, the Parties will take all appropriate steps \nto disconnect the Generating Facility from the Transmission or Distribution System, as \napplicable.  All costs required to effectuate such disconnection shall be borne by the \nterminating Party, unless such termination resulted from the non-terminating Party’s \nDefault of this ZGIA or such non-terminating Party otherwise is responsible for these \ncosts under this ZGIA.  \n \n2.6 \nSurvival.  This ZGIA shall continue in effect after termination to the extent necessary to \nprovide for final billings and payments and for costs incurred hereunder, including \nbillings and payments pursuant to this ZGIA; to permit the determination and \nenforcement of liability and indemnification obligations arising from acts or events that \noccurred while this ZGIA was in effect; and to permit each Party to have access to the \nlands of the other Party pursuant to this ZGIA or other applicable agreements, to \ndisconnect, remove or salvage its own facilities and equipment. \n \nARTICLE 3.  REGULATORY FILINGS \n \n3.1 \nFiling.  Transmission Provider shall file this ZGIA (and any amendment hereto) with the \nappropriate Governmental Authority, if required.  A Party may request that any \ninformation so provided be subject to the confidentiality provisions of Article 22.  If that \nParty has executed this ZGIA, or any amendment thereto, the Party shall reasonably \ncooperate with Transmission Provider with respect to such filing and to provide any \ninformation reasonably requested by Transmission Provider needed to comply with \napplicable regulatory requirements.  \n \nARTICLE 4.  SCOPE OF SERVICE"},{"page":427,"startToken":119632,"endToken":119893,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n4.1 \nInterconnection Product Options.  Interconnection Customer has selected the following \n(checked) type of Interconnection Service:  \n \n \nCheck: : ____ ZG or ____ SI or  ____ ER and/or ____ NR (See Appendix A for \ndetails) \n \n4.1.1 Energy Resource Interconnection Service (ER Interconnection Service). \n \n4.1.1.1 The Product.  ER Interconnection Service allows Interconnection \nCustomer to connect the Generating Facility to the Transmission or \nDistribution System, as applicable, and be eligible to deliver the \nGenerating Facility’s output using the existing firm or non-firm capacity \nof the Transmission System on an “as available” basis.  To the extent \nInterconnection Customer wants to receive ER Interconnection Service, \nTransmission Owner shall construct facilities consistent with the studies \nidentified in Appendix A.   \n \nAn Interconnection Customer seeking ER Interconnection Service for \nnew or added capacity at a Generating Facility may be granted \nconditional ER Interconnection Service status to the extent there is such \ncapacity available on the Transmission System to accommodate the \nInterconnection Customer’s Generating Facility.  At the request of \nInterconnection Customer, conditional ER Interconnection Service status \nmay be granted subject to the system being able to accommodate the \ninterconnection without upgrades, until such time as a higher queued \nproject(s) with a later service date affecting the same common elements \nis placed into service.  The conditional ER Interconnection Service shall \nbe terminated in the event Interconnection Customer fails to fund the \nnecessary studies and the Network Upgrades necessary to grant the \nInterconnection Customer’s ER Interconnection Service upon the"},{"page":428,"startToken":119893,"endToken":120200,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\ncompletion of higher queued projects involving the same common \nelements. \n \n4.1.1.2 Transmission Delivery Service Implications.  Under ER \nInterconnection Service, Interconnection Customer will be eligible to \ninject power from the Generating Facility into and deliver power across \nthe Transmission System on an “as available” basis up to the amount of \nMW identified in the applicable stability and steady state studies to the \nextent the upgrades initially required to qualify for ER Interconnection \nService have been constructed.  After that date FERC makes effective \nMISO’s Energy Market Tariff filed in Docket No. ER04-691-000, \nInterconnection Customer may place a bid to sell into the market up to \nthe maximum identified Generating Facility output, subject to any \nconditions specified in the Interconnection Service approval, and the \nGenerating Facility will be dispatched to the extent the Interconnection \nCustomer’s bid clears.  In all other instances, no transmission or other \ndelivery service from the Generating Facility is assured, but \nInterconnection Customer may obtain Point-To-Point Transmission \nService, Network Integration Transmission Service or be used for \nsecondary network transmission service, pursuant to the Tariff, up to the \nmaximum output identified in the stability and steady state studies.  In \nthose instances, in order for Interconnection Customer to obtain the right \nto deliver or inject energy beyond the Point of Interconnection or to \nimprove its ability to do so, transmission delivery service must be \nobtained pursuant to the provisions of the Tariff.  The Interconnection \nCustomer’s ability to inject its Generating Facility output beyond the \nPoint of Interconnection, therefore, will depend on the existing capacity \nof the Transmission or Distribution System as applicable, at such time as \na Transmission Service request is made that would accommodate such \ndelivery.  The provision of Firm Point-To-Point Transmission Service or"},{"page":429,"startToken":120200,"endToken":120495,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nNetwork Integration Transmission Service may require the construction \nof additional Network or Distribution Upgrades. \n \n4.1.2 Network Resource Interconnection Service (NR Interconnection Service). \n \n4.1.2.1 The Product.  Transmission Provider must conduct the necessary \nstudies and Transmission Owner shall construct the facilities identified \nin Appendix A of this GIA, subject to the approval of Governmental \nAuthorities, needed to integrate the Generating Facility in the same \nmanner as for any Generating Facility being designated as a Network \nResource.   \n \n4.1.2.2 Transmission Delivery Service Implications.  NR Interconnection \nService allows the Generating Facility to be designated by any Network \nCustomer under the Tariff on the Transmission System as a Network \nResource, up to the Generating Facility’s full output, on the same basis \nas existing Network Resources that are interconnected to the \nTransmission or Distribution System, as applicable, and to be studied as \na Network Resource on the assumption that such a designation will \noccur.  Although NR Interconnection Service does not convey a \nreservation of Transmission Service, any Network Customer can utilize \nNetwork Integration Transmission Service under the Tariff to obtain \ndelivery of energy from the Generating Facility in the same manner as it \naccesses Network Resources.  A Generating Facility receiving NR \nInterconnection Service may also be used to provide Ancillary Services \nafter technical studies and/or periodic analyses are performed with \nrespect to the Generating Facility’s ability to provide any applicable \nAncillary Services, provided that such studies and analyses have been or \nwould be required in connection with the provision of such Ancillary \nServices by any existing Network Resource.  However, if the \nGenerating Facility has not been designated as a Network Resource by"},{"page":430,"startToken":120495,"endToken":120787,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nany Network Customer, it cannot be required to provide Ancillary \nServices except to the extent such requirements extend to all generating \nfacilities that are similarly situated.  The provision of Network \nIntegration Transmission Service or Firm Point-To-Point Transmission \nService may require additional studies and the construction of additional \nupgrades.  Because such studies and upgrades would be associated with \na request for delivery service under the Tariff, cost responsibility for the \nstudies and upgrades would be in accordance with FERC’s policy for \npricing transmission delivery services. \n \nNR Interconnection Service does not necessarily provide Interconnection \nCustomer with the capability to physically deliver the output of its \nGenerating Facility to any particular load on the Transmission System \nwithout incurring congestion costs.  In the event of transmission or \ndistribution constraints on the Transmission or Distribution System, as \napplicable, the Generating Facility shall be subject to the applicable \ncongestion management procedures in the Transmission System in the \nsame manner as Network Resources. \n \nThere is no requirement either at the time of study or interconnection, or \nat any point in the future, that the Generating Facility be designated as a \nNetwork Resource by a Network Customer or that Interconnection \nCustomer identify a specific buyer (or sink).  To the extent a Network \nCustomer does designate the Generating Facility as a Network Resource, \nit must do so pursuant to the Tariff. \n \nOnce an Interconnection Customer satisfies the requirements for \nobtaining NR Interconnection Service, any future Transmission Service \nrequest for delivery from the Generating Facility within the \nTransmission System of any amount of capacity and/or energy, up to the \namount initially studied, will not require that any additional studies be"},{"page":431,"startToken":120787,"endToken":121079,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nperformed or that any further upgrades associated with such Generating \nFacility be undertaken, regardless of whether such Generating Facility is \never designated by a Network Customer as a Network Resource and \nregardless of changes in ownership of the Generating Facility.  To the \nextent Interconnection Customer enters into an arrangement for long \nterm Transmission Service for deliveries from the Generating Facility to \ncustomers other than the studied Network Customers, or for any Point-\nTo-Point Transmission Service, such request may require additional \nstudies and upgrades in order for Transmission Provider to grant such \nrequest.  However, the reduction or elimination of congestion or \nredispatch costs may require additional studies and the construction of \nadditional upgrades. \n \nTo the extent Interconnection Customer enters into an arrangement for \nlong term Transmission Service for deliveries from the Generating \nFacility outside the Transmission System, such request may require \nadditional studies and upgrades in order for Transmission Provider to \ngrant such request. \n \n4.1.2.3 Conditional NR Interconnection Service.  An Interconnection Customer \nseeking NR Interconnection Service for new or added capacity at a \nGenerating Facility may be granted conditional NR Interconnection \nService status to the extent there is such capacity available on the \nTransmission System to accommodate the Interconnection Customer’s \nGenerating Facility.  At the request of Interconnection Customer, \nconditional NR Interconnection Service status may be granted subject to \nthe system being able to accommodate the interconnection without \nupgrades, until such time as higher queued project(s) with a later service \ndate affecting the same common elements is placed into service.  The \nconditional NR Interconnection Service status may be converted to ER \nInterconnection Service if either of the following occurs:"},{"page":432,"startToken":121079,"endToken":121332,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \n1)  \nInterconnection Customer fails to fund necessary studies and \nNetwork Upgrades required to allow the Interconnection \nCustomer’s Generating Facility to receive NR Interconnection \nService upon the completion of higher queued projects involving \nthe same common elements; or \n \n2)  \nThe higher queued project(s) or planned and required Network \nUpgrades are placed in service and the Network Upgrades required \nto provide NR Interconnection Service status to the \nInterconnection Customer’s Generating Facility are not in service. \n \nIn the event Interconnection Customer fails to fund the necessary studies \nand Network Upgrades for NR Interconnection Service, the \nInterconnection Customer’s conditional NR Interconnection Service status \nshall be converted to ER Interconnection Service status unless \nInterconnection Customer makes a new Interconnection Request.  Such \nnew Interconnection Request shall be evaluated in accordance with the \nGIP and its new queue position.  \n \nSome or all of the conditional NR Interconnection Service status may be \ntemporarily revoked if the Network Upgrades are not in service when the \nhigher queued project(s) are placed in service.  The availability of \nconditional NR Interconnection Service status will be determined by \nTransmission Provider’s studies.  Upon funding and completion of the \nNetwork Upgrades required to establish the Generating Facility’s NR \nInterconnection Service status, the Generating Facility will be granted NR \nInterconnection Service status. \n \nThe Parties agree that the portion of the Generating Facility classified as \nNR Interconnection Service is the first portion of the output of the"},{"page":433,"startToken":121332,"endToken":121615,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\ncombined output of all the units at the Generating Facility except in \ncircumstances where Interconnection Customer otherwise elects this GIA, \nas amended, to allocate that portion to the output of specific unit(s) at the \nGenerating Facility, the total of which will not exceed the output eligible \nfor NR Interconnection Service as shown by the additional studies.  To the \nextent Interconnection Customer desires to obtain NR Interconnection \nService for any portion of the Generating Facility in addition to that \nsupported by such additional studies, Interconnection Customer will be \nrequired to request such additional NR Interconnection Service through a \nseparate Interconnection Request in accordance with the GIP. \n \n4.1.3 Surplus Interconnection Service (SI). \n \n4.1.3.1 The Product.  Surplus Interconnection Service is restricted \nInterconnection Service that allows an Interconnection Customer to \nincrease the gross generating capability at the same Point of \nInterconnection of an Existing Generating Facility without increasing the \ntotal amount of Interconnection Service at the Point of Interconnection.   \n \n4.1.3.2 Transmission Delivery Service Implications.  Surplus Interconnection \nService does not convey any right to deliver electricity to any specific \ncustomer or Point of Delivery.  \n \n4.1.4 ZG Interconnection Service. \n \n4.1.4.1 The Product.  ZG Interconnection Service is restricted Interconnection \nService that allows an Interconnection Customer to connect its Generating \nFacility to the Transmission System or Distribution System, as applicable, \nfor the limited purpose of delivering Energy to a source of electrical load \nthat is at the same substation as the Point of Interconnection to the \nTransmission System (i.e., same voltage level at the interconnecting"},{"page":434,"startToken":121615,"endToken":121912,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nsubstation) as the Generating Facility with ZG Interconnection Service \nthat will serve it. \n \n \nThis service is available only if the study required by Section 3.2.3.2 of \nthe GIP determines that the proposed interconnection:   \n(1) \nwill not result in any injections of Energy onto the Transmission \nSystem beyond the substation identified in the Interconnection \nRequest as the Point of Interconnection.  The restriction on Energy \ninjection in this paragraph shall not apply to transient, limited \ninjections associated with a reduction or loss of Load by the ZG \nAssociated Load provided these remain within the Transient \nTolerance Window established in the Business Practices Manual \nfor Large Load.   \n \n(2) \nwill not require the construction or modification of any Network \nUpgrades to address impacts to the Transmission System with the \nexception of Network Upgrades located at the same substation as \nthe POI and system protection facilities at adjacent substations.  \n \n \n \nZG Interconnection Service is specific to the ZG Associated Load(s) that the \nGenerating Facility identifies in its Interconnection Request, and which shall be \nmemorialized in the ZGIA.  The Generating Facility’s requesting ZG \nInterconnection Service will be dispatched, and granted service at a level not to \nexceed the total Demand of the ZG Associated Load. \n \n4.1.4.2 Transmission Delivery Service Implications.   \nZG Interconnection Service does not grant any right to inject energy onto \nthe Transmission System beyond the Point of Interconnection except as \nmay be authorized by Section 3.11.1(a) of these Generator Interconnection \nProcedures.  ZG Interconnection Service does not provide interconnection \nservice for the purpose of serving Load other than the ZG Associated \nLoad(s) identified in the Interconnection Request and memorialized in the"},{"page":435,"startToken":121912,"endToken":122228,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nZGIA. ZG Interconnection Service does not convey transmission service, \nwhich is obtained through a separate process, and does not provide a right \nto serve, or a right to transmission service to serve, a ZG Associated Load \nor retail customer except as allowed by state laws and regulations.   \n \n \n4.2 \nProvision of Service.  Transmission Provider shall provide Interconnection Service for \nthe Generating Facility at the Point of Interconnection. \n \n4.3 \nPerformance Standards.  Each Party shall perform all of its obligations under this ZGIA \nin accordance with Applicable Laws and Regulations, Applicable Reliability Standards, \nand Good Utility Practice.  To the extent a Party is required or prevented or limited in \ntaking any action by such regulations and standards, or if the obligations of any Party \nmay become limited by a change in Applicable Laws and Regulations, Applicable \nReliability Standards, and Good Utility Practice after the execution of this ZGIA, that \nParty shall not be deemed to be in Breach of this ZGIA for its compliance therewith.  The \nParty so limited shall notify the other Parties whereupon Transmission Provider shall \namend this ZGIA in concurrence with the other Parties and submit the amendment to the \nCommission for approval.  The ZG Interconnection Service product does not supersede \nany state or local laws or regulations nor does it authorize operations that would violate \nstate or local laws and regulations, including those establishing which entities have the \nright or obligation to serve load.  Interconnection Customers are separately responsible \nfor adhering to all Applicable Laws and Regulations. \n \n4.4 \nNo Transmission Delivery Service.  The execution of this ZGIA does not constitute a \nrequest for, or the provision of, any transmission delivery service under the Tariff, and \ndoes not convey any right to deliver electricity to any specific customer or Point of \nDelivery."},{"page":436,"startToken":122228,"endToken":122552,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n4.5 \nInterconnection Customer Provided Services.  The services provided by \nInterconnection Customer under this ZGIA are set forth in Article 9.6 and Article 13.4.1.  \nInterconnection Customer shall be paid for such services in accordance with Article 11.7. \n \nARTICLE 5.  INTERCONNECTION FACILITIES ENGINEERING, PROCUREMENT, \nAND CONSTRUCTION \n \n5.1 \nOptions.  Unless otherwise mutually agreed to between the Parties, Interconnection \nCustomer shall select:  1) the In-Service Date, Initial Synchronization Date, and \nCommercial Operation Date based on a reasonable construction schedule that will allow \nsufficient time for design, construction, equipment procurement, and permit acquisition \nof Transmission System equipment or right-of-way; and 2) either the Standard Option or \nAlternate Option set forth below and such dates and selected option shall be set forth in \nAppendix B.  If the dates designated by Interconnection Customer are not acceptable to \nTransmission Owner, Transmission Owner shall so notify Interconnection Customer \nwithin thirty (30) Calendar Days.  Upon receipt of the notification that Interconnection \nCustomer’s designated dates are not acceptable to Transmission Owner, the \nInterconnection Customer shall notify Transmission Owner within thirty (30) Calendar \nDays whether it elects to exercise the Option to Build if it has not already elected to \nexercise the Option to Build.   \n \n5.1.1 Standard Option.  Transmission Owner shall design, procure, and construct the \nTransmission Owner’s Interconnection Facilities, Network Upgrades, System \nProtection Facilities, Distribution Upgrades, and Generator Upgrades using \nReasonable Efforts to complete the Transmission Owner’s Interconnection \nFacilities, Network Upgrades, System Protection Facilities, Distribution Upgrades \nand Generator Upgrades by the dates set forth in Appendix B, Milestones, subject \nto the receipt of all approvals required from Governmental Authorities and the \nreceipt of all land rights necessary to commence construction of such facilities, \nand such other permits or authorizations as may be required.  Transmission \nProvider or Transmission Owner shall not be required to undertake any action"},{"page":437,"startToken":122552,"endToken":122850,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nwhich is inconsistent with its standard safety practices, its material and equipment \nspecifications, its design criteria and construction procedures, its labor \nagreements, Applicable Laws and Regulations and Good Utility Practice.  In the \nevent Transmission Owner reasonably expects that it will not be able to complete \nthe Transmission Owner’s Interconnection Facilities, Network Upgrades, System \nProtection Facilities, Distribution Upgrades and Generator Upgrades by the \nspecified dates, Transmission Owner shall promptly provide written notice to \nInterconnection Customer and Transmission Provider and shall undertake \nReasonable Efforts to meet the earliest dates thereafter. \n \n5.1.2 Alternate Option.  If the dates designated by Interconnection Customer are \nacceptable to Transmission Provider and Transmission Owner, Transmission \nProvider shall so notify Interconnection Customer within thirty (30) Calendar \nDays, and Transmission Owner shall assume responsibility for the design, \nprocurement and construction of the Transmission Owner’s Interconnection \nFacilities by the designated dates. \n \nIf Transmission Owner subsequently fails to complete the Transmission Owner’s \nInterconnection Facilities by the In-Service Date, to the extent necessary to \nprovide back feed power; or fails to complete Network Upgrades by the Initial \nSynchronization Date to the extent necessary to allow for Trial Operation at full \npower output, unless other arrangements are made by the Parties for such Trial \nOperation; or fails to complete the Network Upgrades by the Commercial \nOperation Date, as such dates are reflected in Appendix B, Milestones; \nTransmission Owner shall pay Interconnection Customer liquidated damages in \naccordance with Article 5.3, Liquidated Damages, provided, however, the dates \ndesignated by Interconnection Customer shall be extended day for day for each \nCalendar Day that Transmission Provider refuses to grant clearances to install \nequipment. \n \nTransmission Owner and Interconnection Customer may adopt an incentive"},{"page":438,"startToken":122850,"endToken":123186,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\npayment schedule that is mutually agreeable to encourage Transmission Owner to \nmeet specified accelerated dates.  Such payment by Interconnection Customer is \nnot subject to refund. \n \n \n5.1.3 Option to Build.  Pursuant to Section 7.3.2.5 & 7.3.3.5 of the GIP, Individual or \nMultiple Interconnection Customers shall have the option to assume responsibility \nfor the design, procurement and construction of the Transmission Owner’s \nInterconnection Facilities and Stand Alone Network Upgrades by the dates \noriginally designated by Interconnection Customer under Article 5.1.2, , if the \nrequirements of this Article 5.1.3 are met. When multiple Interconnection \nCustomers exercise this option, multiple Interconnection Customers may agree to \nexercise this option provided (1) all Transmission Owner’s Interconnection \nFacilities and Stand Alone Network Upgrades constructed under this option are \nonly required for Interconnection Customers in a single Cluster and (2) all \nimpacted Interconnection Customers execute and provide to Transmission \nProvider an agreement regarding responsibilities, and payment for, the \nconstruction of Transmission Provider’s Interconnection Facilities and Stand \nAlone Network Upgrades planned to be built under this option.  The Parties must \nagree as to what constitutes Stand Alone Network Upgrades and identify such \nStand Alone Network Upgrades in Appendix A.  Except for Stand Alone Network \nUpgrades, Interconnection Customer shall have no right to construct Network \nUpgrades under this option. \n \n5.1.4 Negotiated Option.  If the dates designated by Interconnection Customer \npursuant to Article 5.1 are not acceptable to Transmission Owner, the Parties shall \nin good faith attempt to negotiate terms and conditions (including revision of the \nspecified dates and liquidated damages, the provision of incentives, or the \nprocurement and construction of all facilities other than Transmission Owner’s \nInterconnection Facilities and Stand Alone Network Upgrades if the \nInterconnection Customer elects to exercise the Option to Build under Article \n5.1.3).  If the Parties are unable to reach agreement on such terms and conditions,"},{"page":439,"startToken":123186,"endToken":123426,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nthen, pursuant to Article 5.1.1 (Standard Option), Transmission Owner shall \nassume responsibility for the design, procurement and construction of all facilities \nother than Transmission Owner’s Interconnection Facilities and Stand Alone \nNetwork Upgrades if Interconnection Customer has elected to exercise the Option \nto Build. \n \nTransmission Owner and Interconnection Customer may adopt an incentive \npayment schedule that is mutually agreeable to encourage Transmission Owner to \nmeet specified accelerated dates.  Such payment by Interconnection Customer is \nnot subject to refund. \n \n5.2 \nGeneral Conditions Applicable to Option to Build.  If Interconnection Customer \nassumes responsibility for the design, procurement and construction of the Transmission \nOwner’s Interconnection Facilities and Stand Alone Network Upgrades after receipt of \nall required approvals from Governmental Authorities necessary to commence \nconstruction, \n \n(1) Interconnection Customer shall engineer, procure equipment, and construct \nthe Transmission Owner’s Interconnection Facilities and Stand Alone Network \nUpgrades (or portions thereof) using Good Utility Practice and using standards \nand specifications provided in advance by Transmission Owner, or as required by \nany Governmental Authority; \n \n(2) Interconnection Customer’s engineering, procurement and construction of the \nTransmission Owner’s Interconnection Facilities and Stand Alone Network \nUpgrades shall comply with all requirements of law or Governmental Authority to \nwhich Transmission Owner would be subject in the engineering, procurement or \nconstruction of the Transmission Owner’s Interconnection Facilities and Stand \nAlone Network Upgrades;"},{"page":440,"startToken":123426,"endToken":123698,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n(3) Transmission Provider, at Transmission Provider’s option, and Transmission \nOwner shall be entitled to review and approve the engineering design, equipment \nacceptance tests(including witnessing of acceptance tests), and the construction \n(including monitoring of construction) of the Transmission Owner’s \nInterconnection Facilities and Stand Alone Network Upgrades, and shall have the \nright to reject any design, procurement, construction or acceptance test of any \nequipment that does not meet the standards and specifications of Transmission \nProvider, Transmission Owner and any Governmental Authority; \n \n(4) prior to commencement of construction, Interconnection Customer shall \nprovide to Transmission Provider and Transmission Owner a schedule for \nconstruction of the Transmission Owner’s Interconnection Facilities and Stand \nAlone Network Upgrades, and shall promptly respond to requests for information \nfrom Transmission Provider and Transmission Owner; \n \n(5) at any time during construction, Transmission Provider and Transmission \nOwner shall have unrestricted access to the construction site for the Transmission \nOwner’s Interconnection Facilities and Stand Alone Network Upgrades and to \nconduct inspections of the same; \n \n(6) at any time during construction, should any phase of the engineering, \nequipment procurement, or construction of the Transmission Owner’s \nInterconnection Facilities and Stand Alone Network Upgrades not meet the \nstandards and specifications provided by Transmission Owner, Interconnection \nCustomer shall be obligated to remedy deficiencies in that portion of the \nTransmission Owner’s Interconnection Facilities and Stand Alone Network \nUpgrades to meet the standards and specifications provided by Transmission \nProvider and Transmission Owner; \n \n(7) Interconnection Customer shall indemnify Transmission Provider and \nTransmission Owner for claims arising from the Interconnection Customer’s"},{"page":441,"startToken":123698,"endToken":123944,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nconstruction of the Transmission Owner’s Interconnection Facilities and Stand \nAlone Network Upgrades under the terms and procedures applicable to \nArticle 18.1, Indemnity; \n \n(8) Interconnection Customer shall transfer control of the Transmission Owner’s \nInterconnection Facilities and Stand Alone Network Upgrades to Transmission \nOwner; \n \n(9) Unless Parties otherwise agree, Interconnection Customer shall transfer \nownership of the Transmission Owner’s Interconnection Facilities and Stand \nAlone Network Upgrades to Transmission Owner in accordance with Appendix \nB; \n \n(10) Transmission Provider, at Transmission Provider’s option, and Transmission \nOwner shall approve and accept for operation and maintenance the Transmission \nOwner’s Interconnection Facilities and Stand Alone Network Upgrades to the \nextent engineered, procured, and constructed in accordance with this Article 5.2 \nonly if the Transmission Owner’s Interconnection Facilities and Stand Alone \nNetwork Upgrades meet the standards and specifications of Transmission \nProvider, Transmission Owner and any Governmental Authority. \n \n(11) Interconnection Customer shall deliver to Transmission Owner “as-built” \ndrawings, information, and any other documents that are reasonably required by \nTransmission Owner to assure that the Interconnection Facilities and Stand-Alone \nNetwork Upgrades are built to the standards and specifications required by \nTransmission Owner. \n \n(12) If Interconnection Customer exercises the Option to Build pursuant to Article \n5.1.3, Interconnection Customer shall pay Transmission Owner the agreed upon \namount of [$ PLACEHOLDER] for Transmission Owner to execute the \nresponsibilities enumerated to Transmission Owner under Article 5.2."},{"page":442,"startToken":123944,"endToken":124317,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nTransmission Owner shall invoice Interconnection Customer for this total amount \nto be divided on a monthly basis pursuant to Article 12. \n \n(13) If Interconnection Customer exercises the Option to Build pursuant to Article \n5.1.3, and the Transmission Owner has elected to fund the costs of Network \nUpgrades pursuant to Article 11.3, then prior to Interconnection Customer \nincurring any construction costs relating to the Option to Build and by the date \nspecified in Appendix B, Interconnection Customer shall invoice the \nTransmission Owner for the estimated amount to be expended by the \nInterconnection Customer to construct any Stand Alone Network Upgrades for \nwhich the Interconnection Customer has exercised its Option to Build in \naccordance with Appendix B.  The Transmission Owner shall be required to \nreimburse Interconnection Customer for the full amount of such invoiced costs by \nthe date specified in Appendix B, which shall be prior to the date by which \nInterconnection Customer must make any construction payment for such Stand \nAlone Network Upgrades.  After completion of the construction of Stand Alone \nNetwork Upgrades by the Interconnection Customer and by the date specified in \nAppendix B for the Interconnection Customer to transfer such Stand Alone \nNetwork Upgrades to the Transmission Owner, Interconnection Customer shall \nprovide an invoice of the final cost of the construction of Stand Alone Upgrades \nand shall set forth such costs in sufficient detail to enable the Transmission Owner \nto compare the actual costs with the estimates and to ascertain deviations, if any, \nfrom the cost estimates.  In the event that the actual costs exceed the estimated \ncosts previously invoiced by Interconnection Customer and paid by Transmission \nOwner, Transmission Owner shall pay to Interconnection Customer the difference \nbetween the amount previously paid and the actual costs within thirty (30) \nCalendar Days after receipt of a final construction invoice from Interconnection \nCustomer.  In the event that the actual costs are less than the estimated costs \npreviously invoiced by Interconnection Customer and paid by Transmission \nOwner, Interconnection Customer shall refund, with interest (calculated in \naccordance with 18 C.F.R. Section 35.19a(a)(2)(iii), to Transmission Owner any"},{"page":443,"startToken":124317,"endToken":124672,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\namount by which the actual payment by Transmission Owner for estimated costs \nexceeds the actual costs of construction within thirty (30) Calendar Days of the \nissuance of such final construction invoice.  Following the transfer of the Stand \nAlone Network Upgrades from the Interconnection Customer to the Transmission \nOwner, the Interconnection Customer shall make payments for such facilities to \nthe Transmission Owner pursuant to an agreement between and among the \nParties. \n \n5.3 \nLiquidated Damages.  The actual damages to Interconnection Customer, in the event the \nTransmission Owner’s Interconnection Facilities or Network Upgrades are not completed \nby the dates designated by Interconnection Customer and accepted by Transmission \nProvider and Transmission Owner pursuant to subparagraphs 5.1.2 or 5.1.4, above, may \ninclude Interconnection Customer’s fixed operation and maintenance costs and lost \nopportunity costs.  Such actual damages are uncertain and impossible to determine at this \ntime.  Because of such uncertainty, any liquidated damages paid by Transmission Owner \nto Interconnection Customer in the event that Transmission Owner does not complete any \nportion of the Transmission Owner’s Interconnection Facilities or Network Upgrades by \nthe applicable dates, shall be an amount equal to ½ of 1 percent per day of the actual cost \nof the Transmission Owner’s Interconnection Facilities and Network Upgrades, in the \naggregate, for which Transmission Owner has assumed responsibility to design, procure \nand construct. \n \nHowever, in no event shall the total liquidated damages exceed 20 percent of the actual \ncost of the Transmission Owner’s Interconnection Facilities and Network Upgrades for \nwhich Transmission Owner has assumed responsibility to design, procure, and construct.  \nThe foregoing payments will be made by Transmission Owner to Interconnection \nCustomer as just compensation for the damages caused to Interconnection Customer, \nwhich actual damages are uncertain and impossible to determine at this time, and as \nreasonable liquidated damages, but not as a penalty or a method to secure performance of \nthis ZGIA.  Liquidated damages, when the Parties agree to them, are the exclusive \nremedy for the Transmission Owner’s failure to meet its schedule."},{"page":444,"startToken":124672,"endToken":125036,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \nNo liquidated damages shall be paid to Interconnection Customer if:  (1) Interconnection \nCustomer is not ready to commence use of the Transmission Owner’s Interconnection \nFacilities or Network Upgrades to take the delivery of power for the Generating Facility’s \nTrial Operation or to export power from the Generating Facility on the specified dates, \nunless Interconnection Customer would have been able to commence use of the \nTransmission Owner’s Interconnection Facilities or Network Upgrades to take the \ndelivery of power for Generating Facility’s Trial Operation or to export power from the \nGenerating Facility, but for Transmission Owner’s delay; (2) the Transmission Owner’s \nfailure to meet the specified dates is the result of the action or inaction of Transmission \nProvider, Interconnection Customer or any other earlier queued Interconnection \nCustomer who has entered into an earlier GIA or ZGIA with Transmission Provider \nand/or a Transmission Owner or with an Affected System Operator, or any cause beyond \nTransmission Owner’s reasonable control or reasonable ability to cure; \n(3) Interconnection Customer has assumed responsibility for the design, procurement and \nconstruction of the Transmission Owner’s Interconnection Facilities and Stand Alone \nNetwork Upgrades; (4) the delay is due to the inability of Transmission Owner to obtain \nall required approvals from Governmental Authorities in a timely manner for the \nconstruction of any element of the Interconnection Facilities, Network Upgrades or Stand \nAlone Network Upgrades, or any other permit or authorization required, or any land \nrights or other private authorizations that may be required, and Transmission Owner has \nexercised Reasonable Efforts in procuring such approvals, permits, rights or \nauthorizations; or (5) the Parties have otherwise agreed. \n \n5.4 \nPower System Stabilizers.  Interconnection Customer shall procure, install, maintain \nand operate power system stabilizers in accordance with the guidelines and procedures \nestablished by the Electric Reliability Organization.  Transmission Provider and \nTransmission Owner reserve the right to reasonably establish minimum acceptable \nsettings for any installed power system stabilizers, subject to the design and operating \nlimitations of the Generating Facility.  If the Generating Facility’s power system \nstabilizers are removed from service or are not capable of automatic operation,"},{"page":445,"startToken":125036,"endToken":125285,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nInterconnection Customer shall immediately notify the Transmission Provider’s system \noperator, or its designated representative.  The requirements of this paragraph shall not \napply to induction generators. \n \n5.5 \nEquipment Procurement.  If responsibility for construction of the Transmission \nOwner’s Interconnection Facilities, Network Upgrades and/or Distribution Upgrades is to \nbe borne by Transmission Owner, then Transmission Owner shall commence design of \nthe Transmission Owner’s Interconnection Facilities, Network Upgrades and/or \nDistribution Upgrades, and procure necessary equipment as soon as practicable after all \nof the following conditions are satisfied, unless the Parties otherwise agree in writing: \n \n5.5.1 Transmission Provider has completed the Interconnection Facilities Study \npursuant to the Interconnection Facilities Study Agreement; and \n \n5.5.2 Where applicable, Interconnection Customer has provided security to \nTransmission Owner in accordance with Article 11.6 by the dates specified in \nAppendix B, Milestones. \n \n5.6 \nConstruction Commencement.  Transmission Owner shall commence construction of \nthe Transmission Owner’s Interconnection Facilities, Network Upgrades, Transmission \nOwner’s System Protection Facilities, Distribution Upgrades, and Generator Upgrades \nfor which it is responsible as soon as practicable after the following additional conditions \nare satisfied: \n \n5.6.1 Approval of the appropriate Governmental Authority has been obtained for any \nfacilities requiring regulatory approval; and \n \n5.6.2 Where applicable, Interconnection Customer has provided security to \nTransmission Owner in accordance with Article 11.6 by the dates specified in \nAppendix B, Milestones."},{"page":446,"startToken":125285,"endToken":125606,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n5.7 \nWork Progress.  Transmission Owner and Interconnection Customer will keep each \nother and Transmission Provider advised periodically as to the progress of their \nrespective design, procurement and construction efforts.  Either Transmission Owner or \nInterconnection Customer may, at any time, request a progress report from the other, with \na copy to be provided to the other Parties.  If, at any time, Interconnection Customer \ndetermines that the completion of the Transmission Owner’s Interconnection Facilities, \nNetwork Upgrades, or Transmission Owner’s System Protection Facilities will not be \nrequired until after the specified In-Service Date, Interconnection Customer will provide \nwritten notice to Transmission Provider and Transmission Owner of such later date upon \nwhich the completion of the Transmission Owner’s Interconnection Facilities, Network \nUpgrades or Transmission Owner’s System Protection Facilities will be required.  \nTransmission Owner may delay the In-Service Date of its facilities accordingly. \n \n5.8 \nInformation Exchange.  As soon as reasonably practicable after the Effective Date, the \nParties shall exchange information regarding the design and compatibility of the \nInterconnection Facilities and compatibility of the Interconnection Facilities with the \nTransmission System or Distribution System, as applicable, and shall work diligently and \nin good faith to make any necessary design changes.  \n \n5.9 \nOther Interconnection Options. \n \n5.9.1 Limited Operation.  If any of the Transmission Owner’s Interconnection \nFacilities, Network Upgrades, or Transmission Owner’s System Protection \nFacilities, Distribution Upgrades or Generator Upgrades are not reasonably \nexpected to be completed prior to the Commercial Operation Date of the \nGenerating Facility, Transmission Provider shall, upon the request and at the \nexpense of Interconnection Customer, perform operating studies on a timely basis \nto determine the extent to which the Generating Facility and the Interconnection \nCustomer’s Interconnection Facilities may operate prior to the completion of the \nTransmission Owner’s Interconnection Facilities, Network Upgrades, \nTransmission Owner’s System Protection Facilities, Distribution Upgrades or"},{"page":447,"startToken":125606,"endToken":125924,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nGenerator Upgrades consistent with Applicable Laws and Regulations, \nApplicable Reliability Standards, Good Utility Practice, and this ZGIA.  \nTransmission Provider and Transmission Owner shall permit Interconnection \nCustomer to operate the Generating Facility and the Interconnection Customer’s \nInterconnection Facilities in accordance with the results of such studies; provided, \nhowever, such studies reveal that such operation may occur without detriment to \nthe Transmission System as then configured and in accordance with the safety \nrequirements of Transmission Owner and any Governmental Authority. \n \nThe maximum permissible output of the Generating Facility will be updated on a \nquarterly basis if the Network Upgrades necessary for the interconnection of the \nGenerating Facility pursuant to this ZGIA are not in service within six (6) months \nfollowing the Commercial Operation Date of the Generating Facility as specified \nin Appendix B of this ZGIA.  These quarterly studies will be performed using the \nsame methodology set forth in Section 11.5 of the GIP.  These quarterly updates \nwill end when all Network Upgrades necessary for the interconnection of the \nGenerating Facility pursuant to this ZGIA are in service. \n \n5.9.2 Provisional Interconnection Service. \nUpon the request of Interconnection Customer, and prior to completion of \nrequisite Interconnection Facilities, Network Upgrades, Distribution Upgrades, or \nSystem Protection Facilities Transmission Provider may execute a Provisional \nGenerator Interconnection Agreement or Interconnection Customer may request \nthe filing of an unexecuted Provisional Generator Interconnection Agreement \nwith the Interconnection Customer for limited interconnection service at the \ndiscretion of Transmission Provider based upon an evaluation that will consider \nthe results of available studies.  Transmission Provider shall determine, through \navailable studies or additional studies as necessary, whether stability, short circuit, \nthermal, and/or voltage issues would arise if Interconnection Customer \ninterconnects without modifications to the Generating Facility or Transmission \nProvider’s system. Transmission Provider shall determine whether any"},{"page":448,"startToken":125924,"endToken":126227,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nInterconnection Facilities, Network Upgrades, Distribution Upgrades, or System \nProtection Facilities that are necessary to meet the requirements of the Electric \nReliability Organization, or any applicable Regional Entity for the interconnection \nof a new, modified and/or expanded Generating Facility are in place prior to the \ncommencement of interconnection service from the Generating Facility. Where \navailable studies indicate that such Interconnection Facilities, Network Upgrades, \nDistribution Upgrades, and/or System Protection Facilities that are required for \nthe interconnection of a new, modified and/or expanded Generating Facility are \nnot currently in place, Transmission Provider will perform a study, at the \nInterconnection Customer’s expense, to confirm the facilities that are required for \nProvisional Interconnection Service. The maximum permissible output of the \nGenerating Facility in the Provisional Generator Interconnection Agreement shall \nbe studied and updated on a quarterly basis. Interconnection Customer assumes all \nrisk and liabilities with respect to changes between the Provisional Generator \nInterconnection Agreement and the Generator Interconnection Agreement, \nincluding changes in output limits and Interconnection Facilities, Network \nUpgrades, Distribution Upgrades, and/or System Protection Facilities cost \nresponsibilities. \n \n5.10 \nInterconnection Customer’s Interconnection Facilities.  Interconnection Customer \nshall, at its expense, design, procure, construct, own or control, and install the ICIF, as set \nforth in Appendix A. \n \n5.10.1 \nInterconnection Customer’s Interconnection Facility Specifications.  \nInterconnection Customer shall submit initial design and specifications for the \nICIF, including Interconnection Customer’s System Protection Facilities, to \nTransmission Provider and Transmission Owner at least one hundred eighty \n(180) Calendar Days prior to the Initial Synchronization Date; and final design \nand specifications for review and comment at least ninety (90) Calendar Days \nprior to the Initial Synchronization Date.  Transmission Provider at \nTransmission Provider’s option, and Transmission Owner shall review such"},{"page":449,"startToken":126227,"endToken":126531,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nspecifications to ensure that the ICIF are compatible with their respective \ntechnical specifications, operational control, and safety requirements and \ncomment on such design and specifications within thirty (30) Calendar Days of \nInterconnection Customer’s submission.  All specifications provided hereunder \nshall be deemed confidential. \n \n5.10.2 \nTransmission Provider’s and Transmission Owner’s Review.  Transmission \nProvider’s and Transmission Owner’s review of Interconnection Customer’s \nfinal specifications shall not be construed as confirming, endorsing, or providing \na warranty as to the design, fitness, safety, durability or reliability of the \nGenerating Facility, or the ICIF.  Interconnection Customer shall make such \nchanges to the ICIF as may reasonably be required by Transmission Provider \nand Transmission Owner, in accordance with Good Utility Practice, to ensure \nthat the ICIF are compatible with the technical specifications, operational \ncontrol and safety requirements of Transmission Provider and Transmission \nOwner. \n \n5.10.3 \nICIF Construction.  The ICIF shall be designed and constructed in accordance \nwith Good Utility Practice.  Within one hundred twenty (120) Calendar Days \nafter the Commercial Operation Date, unless the Parties agree on another \nmutually acceptable deadline, Interconnection Customer shall deliver to \nTransmission Provider and Transmission Owner “as-built” drawings, \ninformation and documents for the ICIF, such as: a one-line diagram, a site plan \nshowing the Generating Facility and the ICIF, plan and elevation drawings \nshowing the layout of the ICIF, a relay functional diagram, relaying AC and DC \nschematic wiring diagrams and relay settings for all facilities associated with the \nInterconnection Customer’s step-up transformers, the facilities connecting the \nGenerating Facility to the step-up transformers and the ICIF, and the \nimpedances (determined by factory tests) for the associated step-up transformers \nand the Generating Facility.  Interconnection Customer shall provide \nTransmission Provider and Transmission Owner with Interconnection"},{"page":450,"startToken":126531,"endToken":126846,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nCustomer’s specifications for the excitation system, automatic voltage regulator, \nGenerating Facility control and protection settings, transformer tap settings, and \ncommunications, if applicable. \n \n5.11 \nTransmission Owner’s Interconnection Facilities Construction. The Transmission \nOwner’s Interconnection Facilities shall be designed and constructed in accordance with \nGood Utility Practice.  Upon request, within one hundred twenty (120) Calendar Days \nafter the Commercial Operation Date, unless the Parties agree on another mutually \nacceptable deadline, Transmission Owner shall deliver to Transmission Provider (if \nrequested) and Interconnection Customer the “as-built” drawings, information and \ndocuments for the Transmission Owner’s Interconnection Facilities specified in \nAppendix C to this ZGIA.   \n \nSuch drawings, information and documents shall be deemed Confidential Information. \n \nUpon completion, the Transmission Owner’s Interconnection Facilities and Stand Alone \nNetwork Upgrades shall be under the control of Transmission Provider or its designated \nrepresentative. \n \n5.12 \nAccess Rights.  Upon reasonable notice by a Party, and subject to any required or \nnecessary regulatory approvals, a Party (“Granting Party”) shall furnish at no cost to the \nother Party (“Access Party”) any rights of use, licenses, rights of way and easements with \nrespect to lands owned or controlled by the Granting Party, its agents (if allowed under \nthe applicable agency agreement), or any Affiliate, that are necessary to enable the \nAccess Party to obtain ingress and egress to construct, operate, maintain, repair, test (or \nwitness testing), inspect, replace or remove facilities and equipment to:  (i) interconnect \nthe Generating Facility with the Transmission System; (ii) operate and maintain the \nGenerating Facility, the Interconnection Facilities and the Transmission System; and \n(iii) disconnect or remove the Access Party’s facilities and equipment upon termination \nof this ZGIA.  In exercising such licenses, rights of way and easements, the Access Party \nshall not unreasonably disrupt or interfere with normal operation of the Granting Party’s"},{"page":451,"startToken":126846,"endToken":127176,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nbusiness and shall adhere to the safety rules and procedures established in advance, as \nmay be changed from time to time, by the Granting Party and provided to the Access \nParty.   \n \n5.13 \nLands of Other Property Owners.  If any part of the Transmission Owner’s \nInterconnection Facilities, Network Upgrades, and/or Distribution Upgrades is to be \ninstalled on property owned by persons other than Interconnection Customer or \nTransmission Owner, Transmission Owner shall at Interconnection Customer’s expense \nuse efforts, similar in nature and extent to those that it typically undertakes on its own \nbehalf or on behalf of its Affiliates, including use of its eminent domain authority to the \nextent permitted and consistent with Applicable Laws and Regulations and, to the extent \nconsistent with such Applicable Laws and Regulations, to procure from such persons any \nrights of use, licenses, rights of way and easements that are necessary to construct, \noperate, maintain, test, inspect, replace or remove the Transmission Owner’s \nInterconnection Facilities, Network Upgrades and/or Distribution Upgrades upon such \nproperty.   \n \n5.14 \nPermits.  Transmission Provider or Transmission Owner and Interconnection Customer \nshall cooperate with each other in good faith in obtaining all permits, licenses and \nauthorizations that are necessary to accomplish the interconnection in compliance with \nApplicable Laws and Regulations.  With respect to this paragraph, Transmission Owner \nshall provide permitting assistance to Interconnection Customer comparable to that \nprovided to the Transmission Owner’s own, or an Affiliate’s, generation to the extent that \nTransmission Owner or its Affiliate owns generation.  \n \n5.15 \nEarly Construction of Base Case Facilities.  (Includes facilities required for all queued \nprojects with interconnection agreements ).Interconnection Customer may request \nTransmission Owner to construct, and Transmission Owner shall construct, using \nReasonable Efforts to accommodate Interconnection Customer’s In-Service Date, all or \nany portion of any Network Upgrades, Transmission Owner’s System Protection \nFacilities or Distribution Upgrades required for Interconnection Customer to be"},{"page":452,"startToken":127176,"endToken":127497,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\ninterconnected to the Transmission or Distribution System, as applicable, which are \nincluded in the Base Case of the Interconnection Facilities Study for Interconnection \nCustomer, and which also are required to be constructed for another Interconnection \nCustomer with a prior ZGIA, but where such construction is not scheduled to be \ncompleted in time to achieve Interconnection Customer’s In-Service Date.  Any such \nNetwork Upgrades, System Protection Facilities or Distribution Upgrades are included in \nthe facilities to be constructed and as set forth in Appendix A to this ZGIA to the extent \nthey are reasonably known. \n \n5.16 \nSuspension.   \n \n5.16.1  Interconnection Customer’s Right to Suspend for Force Majeure Event; \nObligations.  Provided that such suspension is permissible under the \nauthorizations, permits or approvals granted for the construction of such \nInterconnection Facilities, Network Upgrades or Stand Alone Network Upgrades, \nInterconnection Customer will not suspend unless a Force Majeure event occurs. \n \n \nInterconnection Customer must provide written notice of its request for \nsuspension to Transmission Provider and Transmission Owner, and provide a \ndescription of the Force Majeure event that is acceptable to Transmission \nProvider.  Suspension will only apply to Interconnection Customer milestones and \nInterconnection Facilities described in the Appendices of this ZGIA.  Prior to \nsuspension, Interconnection Customer must also provide security acceptable to \nTransmission Owner, equivalent to the higher of $5 million or the total cost of all \nNetwork Upgrades, Transmission Owner’s System Protection Facilities, and \nDistribution Upgrades listed in Appendix A of this ZGIA.  Network Upgrades and \nTransmission Owner’s Interconnection Facilities will be constructed on the \nschedule described in the Appendices of this ZGIA unless:  (1) construction is \nprevented by the order of a Governmental Authority; (2) the Network Upgrades \nare not needed by any other project; or (3) Transmission Owner or Transmission \nProvider determines that a Force Majeure event prevents construction.  In the"},{"page":453,"startToken":127497,"endToken":127836,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nevent of (1), (2), or (3) security shall be released upon the determination that the \nNetwork Upgrades will no longer be constructed.    \n \n \n \nIf suspension occurs, the Transmission or Distribution System, as applicable, shall \nbe left in a safe and reliable condition in accordance with Good Utility Practice \nand the Transmission Provider’s and Transmission Owner’s safety and reliability \ncriteria.  In such event, Interconnection Customer shall be responsible for all \nreasonable and necessary costs which Transmission Provider and Transmission \nOwner (i) have incurred pursuant to this ZGIA prior to the suspension and (ii) \nincur in suspending such work, including any costs incurred to perform such work \nas may be necessary to ensure the safety of persons and property and the integrity \nof the Transmission or Distribution System, as applicable, during such suspension \nand, if applicable, any costs incurred in connection with the cancellation or \nsuspension of material, equipment and labor contracts which Transmission \nProvider and Transmission Owner cannot reasonably avoid; provided, however, \nthat prior to canceling or suspending any such material, equipment or labor \ncontract, Transmission Provider and Transmission Owner shall obtain \nInterconnection Customer’s authorization to do so. \n \nTransmission Provider and Transmission Owner shall each invoice \nInterconnection Customer for such costs pursuant to Article 12 and shall use \nReasonable Efforts to minimize its costs.  In the event Interconnection Customer \nsuspends work by Transmission Owner required under this ZGIA pursuant to this \nArticle 5.16, and has not requested Transmission Owner to recommence the work \nrequired under this ZGIA on or before the expiration of three (3) years following \ncommencement of such suspension, this ZGIA shall be deemed terminated.  The \nthree-year period shall begin on the date the suspension is requested, or the date \nof the written notice to Transmission Provider, if no effective date is specified. \n \n5.16.2 Effect of Missed Interconnection Customer Milestones.  If Interconnection \nCustomer fails to provide notice of suspension pursuant to Article 5.16, and"},{"page":454,"startToken":127836,"endToken":128128,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nInterconnection Customer fails to fulfill or complete any Interconnection \nCustomer Milestone provided in Appendix B (“Milestone”), this constitutes a \nBreach under this ZGIA.  Depending upon the consequences of the Breach and \neffectiveness of the cure pursuant to Article 17, the Transmission Owner’s \nMilestones may be revised, following consultation with Interconnection \nCustomer, consistent with Reasonable Efforts, and in consideration of all relevant \ncircumstances.  Parties shall employ Reasonable Efforts to maintain their \nremaining respective Milestones. \n \n5.16.3 Effect of Suspension; Parties Obligations.  In the event that Interconnection \nCustomer suspends work pursuant to this Article 5.16, no construction duration, \ntimelines and schedules set forth in Appendix B shall be suspended during the \nperiod of suspension unless ordered by a Governmental Authority, with such \norder being the Force Majeure event causing the suspension.  Should \nInterconnection Customer request that work be recommenced, Transmission \nOwner shall be obligated to proceed with Reasonable Efforts and in consideration \nof all relevant circumstances including regional outage schedules, construction \navailability and material procurement in performing the work as described in \nAppendix A and Appendix B.  Transmission Owner will provide Interconnection \nCustomer with a revised schedule for the design, procurement, construction, \ninstallation and testing of the Transmission Owner’s Interconnection Facilities \nand Network Upgrades.  Upon any suspension by Interconnection Customer \npursuant to Article 5.16, Interconnection Customer shall be responsible for only \nthose costs specified in this Article 5.16.   \n \n5.17 \nTaxes. \n \n5.17.1 Interconnection Customer Payments Not Taxable.  The Parties intend that all \npayments or property transfers made by Interconnection Customer to \nTransmission Owner for the installation of the Transmission Owner’s \nInterconnection Facilities, Network Upgrades, Transmission Owner’s System"},{"page":455,"startToken":128128,"endToken":128497,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nProtection Facilities, Distribution Upgrades and Generator Upgrades shall be non-\ntaxable, either as contributions to capital, or as an advance, in accordance with the \nInternal Revenue Code and any applicable state income tax laws and shall not be \ntaxable as contributions in aid of construction or otherwise under the Internal \nRevenue Code and any applicable state income tax laws.  To the extent that \nTransmission Owner is a limited liability company and not a corporation, and has \nelected to be taxed as a partnership, then the following shall apply:  Transmission \nOwner represents, and the Parties acknowledge, that Transmission Owner is a \nlimited liability company and is treated as a partnership for federal income tax \npurposes.  Any payment made by Interconnection Customer to Transmission \nOwner for Network Upgrades is to be treated as an upfront payment in \naccordance with Rev Proc 2005-35.  It is anticipated by the parties that any \namounts paid by Interconnection Customer to Transmission Owner for Network \nUpgrades will be reimbursed to Interconnection Customer in accordance with the \nterms of this ZGIA, provided Interconnection Customer fulfills its obligations \nunder this ZGIA. \n \n5.17.2 \nRepresentations and Covenants.  In accordance with IRS Notice 2016-36, \nInterconnection Customer represents and covenants that (i) ownership of the \nelectricity generated at the Generating Facility will pass to another party prior \nto the transmission of the electricity on the Transmission  System, (ii) for \nincome tax purposes, the amount of any payments and the cost of any property \ntransferred to Transmission Owner for the Transmission Owner’s \nInterconnection Facilities will be capitalized by Interconnection Customer as \nan intangible asset and recovered using the straight-line method over a useful \nlife of twenty (20) years, and (iii) any portion of the Transmission Owner’s \nInterconnection Facilities that is a “dual-use intertie,” within the meaning of \nIRS Notice 2016-36, is reasonably expected to carry only a de minimis amount \nof electricity in the direction of the Generating Facility.  For this purpose, “de \nminimis amount” means no more than 5 percent of the total power flows in \nboth directions, calculated in accordance with the “5 percent test” set forth in"},{"page":456,"startToken":128497,"endToken":128810,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nIRS Notice 2016-36.  This is not intended to be an exclusive list of the relevant \nconditions that must be met to conform to IRS requirements for non-taxable \ntreatment. \n \nAt Transmission Owner’s request, Interconnection Customer shall provide \nTransmission Owner with a report from an independent engineer confirming its \nrepresentation in clause (iii), above, with a copy to Transmission Provider.  \nTransmission Owner represents and covenants that the cost of the Transmission \nOwner’s Interconnection Facilities paid for by Interconnection Customer will \nhave no net effect on the base upon which rates are determined. \n \n5.17.3 \nIndemnification for the Cost Consequences of Current Tax Liability Upon \nTransmission Owner.  Notwithstanding Article 5.17.1 and to the extent \npermitted by law, Interconnection Customer shall protect, indemnify and hold \nharmless Transmission Owner from the cost consequences of any tax liability \nimposed against Transmission Owner as the result of payments or property \ntransfers made by Interconnection Customer to Transmission Owner under this \nZGIA for Interconnection Facilities, as well as any interest and penalties, other \nthan interest and penalties attributable to any delay caused by Transmission \nOwner. \n \nTransmission Owner shall not include a gross-up for the cost consequences of \nany current tax liability in the amounts it charges Interconnection Customer \nunder this ZGIA unless (i) Transmission Owner has determined, in good faith, \nthat the payments or property transfers made by Interconnection Customer to \nTransmission Owner should be reported as income subject to taxation or (ii) any \nGovernmental Authority directs Transmission Owner to report payments or \nproperty as income subject to taxation; provided, however, that Transmission \nOwner may require Interconnection Customer to provide security for \nInterconnection Facilities, in a form reasonably acceptable to Transmission \nOwner (such as a parental guarantee or a letter of credit), in an amount equal to"},{"page":457,"startToken":128810,"endToken":129148,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nthe cost consequences or any current tax liability under this Article 5.17. \nInterconnection Customer shall reimburse Transmission Owner for such costs \non a fully grossed-up basis, in accordance with Article 5.17.4, within thirty (30) \nCalendar Days of receiving written notification from Transmission Owner of the \namount due, including detail about how the amount was calculated. \n \nThe indemnification obligation shall terminate at the earlier of (1) the expiration \nof the ten-year testing period and the applicable statute of limitation, as it may \nbe extended by Transmission Owner upon request of the IRS, to keep these \nyears open for audit or adjustment, or (2) the occurrence of a subsequent taxable \nevent and the payment of any related indemnification obligations as \ncontemplated by this Article 5.17. \n \n5.17.4 \nTax Gross-Up Amount.  Interconnection Customer’s liability for the cost \nconsequences of any current tax liability under this Article 5.17 shall be \ncalculated on a fully grossed-up basis.  Except as may otherwise be agreed to by \nthe parties, this means that Interconnection Customer will pay Transmission \nOwner, in addition to the amount paid for the Interconnection Facilities, \nNetwork Upgrades, Transmission Owner’s System Protection Facilities, and/or \nDistribution Upgrades, an amount equal to (1) the current taxes imposed on \nTransmission Owner (“Current Taxes”) on the excess of (a) the gross income \nrealized by Transmission Owner as a result of payments or property transfers \nmade by Interconnection Customer to Transmission Owner under this ZGIA \n(without regard to any payments under this Article 5.17) (the “Gross Income \nAmount”) over (b) the present value of future tax deductions for depreciation \nthat will be available as a result of such payments or property transfers (the \n“Present Value Depreciation Amount”), plus (2) an additional amount sufficient \nto permit Transmission Owner to receive and retain, after the payment of all \nCurrent Taxes, an amount equal to the net amount described in clause (1)."},{"page":458,"startToken":129148,"endToken":129502,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nFor this purpose, (i) Current Taxes shall be computed based on Transmission \nOwner’s composite federal and state tax rates at the time the payments or \nproperty transfers are received and Transmission Owner will be treated as being \nsubject to tax at the highest marginal rates in effect at that time (the “Current \nTax Rate”), and (ii) the Present Value Depreciation Amount shall be computed \nby discounting Transmission Owner’s anticipated tax depreciation deductions as \na result of such payments or property transfers by Transmission Owner’s current \nweighted average cost of capital.  Thus, the formula for calculating \nInterconnection Customer’s liability to Transmission Owner pursuant to this \nArticle 5.17.4 can be expressed as follows: (Current Tax Rate x (Gross Income \nAmount – Present Value of Tax Depreciation))/(1-Current Tax Rate).  \nInterconnection Customer’s estimated tax liability in the event taxes are \nimposed shall be stated in Appendix A, Interconnection Facilities, Network \nUpgrades and Distribution Upgrades. \n \n5.17.5 \nPrivate Letter Ruling or Change or Clarification of Law.  At Interconnection \nCustomer’s request and expense, Transmission Owner shall file with the IRS a \nrequest for a private letter ruling as to whether any property transferred or sums \npaid, or to be paid, by Interconnection Customer to Transmission Owner under \nthis ZGIA are subject to federal income taxation.  Interconnection Customer \nwill prepare the initial draft of the request for a private letter ruling, and will \ncertify under penalties of perjury that all facts represented in such request are \ntrue and accurate to the best of Interconnection Customer’s knowledge.  \nTransmission Owner and Interconnection Customer shall cooperate in good \nfaith with respect to the submission of such request. \n \nTransmission Owner shall keep Interconnection Customer fully informed of the \nstatus of such request for a private letter ruling and shall execute either a privacy \nact waiver or a limited power of attorney, in a form acceptable to the IRS, that \nauthorizes Interconnection Customer to participate in all discussions with the \nIRS regarding such request for a private letter ruling.  Transmission Owner shall"},{"page":459,"startToken":129502,"endToken":129839,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nallow Interconnection Customer to attend all meetings with IRS officials about \nthe request and shall permit Interconnection Customer to prepare the initial \ndrafts of any follow-up letters in connection with the request.   \n \n5.17.6 \nSubsequent Taxable Events.  If, within 10 years from the date on which the \nrelevant Transmission Owner’s Interconnection Facilities are placed in service, \n(i) Interconnection Customer breaches the covenant contained in Article 5.17.2, \n(ii) a “disqualification event” occurs within the meaning of IRS Notice 88-129, \nor (iii) this ZGIA terminates and Transmission Owner retains ownership of the \nInterconnection Facilities, Network Upgrades, Transmission Owner’s System \nProtection Facilities, and/or Distribution Upgrades, Interconnection Customer \nshall pay a tax gross-up for the cost consequences of any current tax liability \nimposed on Transmission Owner, calculated using the methodology described \nin Article 5.17.4 and in accordance with IRS Notice 90-60. \n \n5.17.7 \nContests.  In the event any Governmental Authority determines that \nTransmission Owner’s receipt of payments or property constitutes income that \nis subject to taxation, Transmission Owner shall notify Interconnection \nCustomer, in writing, within thirty (30) Calendar Days of receiving notification \nof such determination by a Governmental Authority.  Upon the timely written \nrequest by Interconnection Customer and at Interconnection Customer’s sole \nexpense, Transmission Owner may appeal, protest, seek abatement of, or \notherwise oppose such determination.  Upon Interconnection Customer’s written \nrequest and sole expense, Transmission Owner shall file a claim for refund with \nrespect to any taxes paid under this Article 5.17, whether or not it has received \nsuch a determination.  Transmission Owner reserves the right to make all \ndecisions with regard to the prosecution of such appeal, protest, abatement or \nother contest, including the selection of counsel and compromise or settlement \nof the claim, but Transmission Owner shall keep Interconnection Customer \ninformed, shall consider in good faith suggestions from Interconnection \nCustomer about the conduct of the contest, and shall reasonably permit"},{"page":460,"startToken":129839,"endToken":130170,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nInterconnection Customer or an Interconnection Customer representative to \nattend contest proceedings. \n \nInterconnection Customer shall pay to Transmission Owner on a periodic basis, \nas invoiced by Transmission Owner, Transmission Owner’s documented \nreasonable costs of prosecuting such appeal, protest, abatement or other contest.  \nAt any time during the contest, Transmission Owner may agree to a settlement \neither with Interconnection Customer’s consent or after obtaining written advice \nfrom nationally-recognized tax counsel, selected by Transmission Owner, but \nreasonably acceptable to Interconnection Customer, that the proposed settlement \nrepresents a reasonable settlement given the hazards of litigation.  \nInterconnection Customer’s obligation shall be based on the amount of the \nsettlement agreed to by Interconnection Customer, or if a higher amount, so \nmuch of the settlement that is supported by the written advice from nationally-\nrecognized tax counsel selected under the terms of the preceding sentence.  The \nsettlement amount shall be calculated on a fully grossed-up basis to cover any \nrelated cost consequences of the current tax liability.  Any settlement without \nInterconnection Customer’s consent or such written advice will relieve \nInterconnection Customer from any obligation to indemnify Transmission \nOwner for the tax at issue in the contest. \n \n5.17.8 \nRefund.  In the event that (a) a private letter ruling is issued to Transmission \nOwner which holds that any amount paid or the value of any property \ntransferred by Interconnection Customer to Transmission Owner under the \nterms of this ZGIA is not subject to federal income taxation, (b) any legislative \nchange or administrative announcement, notice, ruling or other determination \nmakes it reasonably clear to Transmission Owner in good faith that any amount \npaid or the value of any property transferred by Interconnection Customer to \nTransmission Owner under the terms of this ZGIA is not taxable to \nTransmission Owner, (c) any abatement, appeal, protest, or other contest results \nin a determination that any payments or transfers made by Interconnection"},{"page":461,"startToken":130170,"endToken":130459,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nCustomer to Transmission Owner are not subject to federal income tax, or (d) if \nTransmission Owner receives a refund from any taxing authority for any \noverpayment of tax attributable to any payment or property transfer made by \nInterconnection Customer to Transmission Owner pursuant to this ZGIA, \nTransmission Owner shall promptly refund to Interconnection Customer the \nfollowing: \n \nany payment made by Interconnection Customer under this Article 5.17 \nfor taxes that is attributable to the amount determined to be non-taxable, \ntogether with interest thereon, \n \n(ii) interest on any amounts paid by Interconnection Customer to \nTransmission Owner for such taxes which Transmission Owner did not \nsubmit to the taxing authority, calculated in accordance with the \nmethodology set forth in 18 C.F.R. Section 35.19a(a)(2)(iii) from the date \npayment was made by Interconnection Customer to the date Transmission \nOwner refunds such payment to Interconnection Customer, and \n \n(iii) with respect to any such taxes paid by Transmission Owner, any \nrefund or credit Transmission Owner receives or to which it may be \nentitled from any Governmental Authority, interest (or that portion thereof \nattributable to the payment described in clause (i), above) owed to \nTransmission Owner for such overpayment of taxes (including any \nreduction in interest otherwise payable by Transmission Owner to any \nGovernmental Authority resulting from an offset or credit); provided, \nhowever, that Transmission Owner will remit such amount promptly to \nInterconnection Customer only after and to the extent that Transmission \nOwner has received a tax refund, credit or offset from any Governmental \nAuthority for any applicable overpayment of income tax related to the \nTransmission Owner’s Interconnection Facilities."},{"page":462,"startToken":130459,"endToken":130776,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nThe intent of this provision is to leave both parties, to the extent \npracticable, in the event that no taxes are due with respect to any payment \nfor Interconnection Facilities and Network Upgrades hereunder, in the \nsame position they would have been in had no such tax payments been \nmade. \n \n5.17.9 \nTaxes Other Than Income Taxes.  Upon the timely request by Interconnection \nCustomer, and at Interconnection Customer’s sole expense, Transmission \nOwner shall appeal, protest, seek abatement of, or otherwise contest any tax \n(other than federal or state income tax) asserted or assessed against \nTransmission Owner for which Interconnection Customer may be required to \nreimburse Transmission Owner under the terms of this ZGIA.  Interconnection \nCustomer shall pay to Transmission Owner on a periodic basis, as invoiced by \nTransmission Owner, Transmission Owner’s documented reasonable costs of \nprosecuting such appeal, protest, abatement, or other contest.  Interconnection \nCustomer and Transmission Owner shall cooperate in good faith with respect to \nany such contest.  Unless the payment of such taxes is a prerequisite to an \nappeal or abatement or cannot be deferred, no amount shall be payable by \nInterconnection Customer to Transmission Owner for such taxes until they are \nassessed by a final, non-appealable order by any court or agency of competent \njurisdiction.  In the event that a tax payment is withheld and ultimately due and \npayable after appeal, Interconnection Customer will be responsible for all taxes, \ninterest and penalties, other than penalties attributable to any delay caused by \nTransmission Owner. \n \n5.18 \nTax Status.  Each Party shall cooperate with the other Parties to maintain each Party’s \ntax status.  Nothing in this ZGIA is intended to adversely affect any Party’s tax-exempt \nstatus with respect to the issuance of bonds including, but not limited to, Local \nFurnishing Bonds. \n \n5.19 \nModification."},{"page":463,"startToken":130776,"endToken":131087,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \n5.19.1 General.  Either Party may undertake modifications to its facilities.  If a Party \nplans to undertake a modification that reasonably may be expected to affect \nanother Party’s facilities, that Party shall provide to the other Parties sufficient \ninformation regarding such modification so that the other Parties may evaluate \nthe potential impact of such modification prior to commencement of the work.  \nSuch information shall be deemed to be Confidential Information hereunder and \nshall include information concerning the timing of such modifications and \nwhether such modifications are expected to interrupt the flow of electricity from \nthe Generating Facility.  The Party desiring to perform such work shall provide \nthe relevant drawings, plans, and specifications to the other Parties at least ninety \n(90) Calendar Days in advance of the commencement of the work or such shorter \nperiod upon which the Parties may agree, which agreement shall not \nunreasonably be withheld, conditioned or delayed. \n \nIn the case of Generating Facility modifications that do not require \nInterconnection Customer to submit an Interconnection Request, Transmission \nProvider shall provide, within thirty (30) Calendar Days (or such other time as \nthe Parties may agree), an estimate of any additional modifications to the \nTransmission or Distribution System as applicable, Transmission Owner’s \nInterconnection Facilities, Network Upgrades, Transmission Owner’s System \nProtection Facilities, and/or Distribution Upgrades necessitated by such \nInterconnection Customer modification and a good faith estimate of the costs \nthereof which shall be the responsibility of Interconnection Customer. \n \n5.19.2 Standards.  Any additions, modifications, or replacements made to a Party’s \nfacilities shall be designed, constructed and operated in accordance with this \nZGIA and Good Utility Practice.  \n \n \n5.19.3 \nModification Costs.  Interconnection Customer shall not be directly assigned \nthe costs of any additions, modifications, or replacements that Transmission"},{"page":464,"startToken":131087,"endToken":131388,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nOwner makes to the Transmission Owner’s Interconnection Facilities, Network \nUpgrades, Transmission Owner’s System Protection Facilities, Distribution \nUpgrades, or the Transmission or Distribution System, as applicable, to \nfacilitate the interconnection of a third party to the Transmission Owner’s \nInterconnection Facilities or the Transmission or Distribution System, as \napplicable, or to provide transmission service to a third party under the Tariff.  \nInterconnection Customer shall be responsible for the costs of any additions, \nmodifications, or replacements to the Interconnection Customer’s \nInterconnection Facilities that may be necessary to maintain or upgrade such \nInterconnection Customer’s Interconnection Facilities consistent with \nApplicable Laws and Regulations, Applicable Reliability Standards or Good \nUtility Practice. \n \n5.19.4 \nSole Interconnection: During the term of this ZGIA, Interconnection Customer \nshall not connect the Generating Facilities described in Appendix A of this \nZGIA to the transmission facilities of any transmission provider other than the \nTransmission Provider, or a successor to the Transmission Provider, except as \nexpressly allowed by the Transmission Provider’s Tariff.  Any connection that \nviolates this Article 5.19.4 shall be deemed a breach of this ZGIA subject to \ndefault and termination pursuant to Articles 17 and 2 of this ZGIA.  In the event \nInterconnection Customer proposes to connect the Generating Facilities to the \ntransmission system of another transmission provider, all Interconnection \nService under this agreement shall terminate no later than the date on which \nsuch Generating Facilities achieve commercial operation over its connection to \nthe other transmission provider.  Interconnection Customer shall adhere to the \nrequirements of Attachment Y to the Tariff as applicable.  \n \nARTICLE 6.  TESTING AND INSPECTION \n \n6.1 \nPre-Commercial Operation Date Testing and Modifications.  Prior to the Commercial \nOperation Date, Transmission Owner shall test the Transmission Owner’s"},{"page":465,"startToken":131388,"endToken":131744,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nInterconnection Facilities, Network Upgrades, Transmission Owner’s System Protection \nFacilities and Distribution Upgrades, and Interconnection Customer shall test each \nelectric production device at the Generating Facility, Interconnection Customer’s System \nProtection Facilities, including control equipment to limit injection at the POI to the level \nof Interconnection Service set forth in Appendix A and the Interconnection Customer’s \nInterconnection Facilities to ensure their safe and reliable operation.  Similar testing may \nbe required after initial operation.  Transmission Owner and Interconnection Customer \nshall make any modifications to their respective facilities that are found to be necessary \nas a result of such testing.  Interconnection Customer shall bear the cost of all such \ntesting and modifications.  Interconnection Customer shall generate test energy at the \nGenerating Facility only if it has arranged for the delivery of such test energy. \n \n6.2 \nPost-Commercial Operation Date Testing and Modifications.  Each Party shall at its \nown expense perform routine inspection and testing of its facilities and equipment in \naccordance with Good Utility Practice as may be necessary to ensure the continued \ninterconnection of the Generating Facility with the Transmission or Distribution System, \nas applicable, in a safe and reliable manner.  Each Party shall have the right, upon \nadvance written notice, to require reasonable additional testing of the Interconnection \nFacilities, at the requesting Party’s expense, as may be in accordance with Good Utility \nPractice. \n \n6.3 \nRight to Observe Testing.  Each Party shall notify the other Parties in advance of its \nperformance of tests of its Interconnection Facilities.  The other Parties shall each have \nthe right, at its own expense, to observe such testing. \n \n6.4 \nRight to Inspect.  Each Party shall have the right, but shall have no obligation to: \n(i) observe Transmission Owner’s and Interconnection Customer’s tests and/or inspection \nof any of their respective System Protection Facilities and other protective equipment, \nincluding power system stabilizers and control equipment; (ii) review the settings of the \nSystem Protection Facilities and other protective equipment; and (iii) review the \nmaintenance records relative to the Interconnection Facilities, the System Protection"},{"page":466,"startToken":131744,"endToken":132107,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nFacilities and other protective equipment.  A Party may exercise these rights from time to \ntime as it deems necessary upon reasonable notice to the other Parties.  The exercise or \nnon-exercise by a Party of any such rights shall not be construed as an endorsement or \nconfirmation of any element or condition of the Interconnection Facilities or the System \nProtection Facilities or other protective equipment or the operation thereof, or as a \nwarranty as to the fitness, safety, desirability, or reliability of same.  Any information that \na Party obtains through the exercise of any of its rights under this Article 6.4 shall be \ndeemed to be Confidential Information and treated pursuant to Article 22 of this ZGIA. \n \nARTICLE 7.  METERING \n \n7.1 \nGeneral.  Each Party shall comply with the Electric Reliability Organization \nrequirements.  Unless the Interconnection Customer is utilizing shared Interconnection \nCustomer Interconnection Facilities, or unless otherwise agreed by the Parties, \nTransmission Owner, at its election, or otherwise Interconnection Customer, shall install \nMetering Equipment (the “Metering Party”) at the Point of Interconnection prior to any \noperation of the Generating Facility.  Transmission Owner, at its election, or otherwise \nInterconnection Customer shall own, operate, test and maintain such Metering \nEquipment.  Power flows to and from the Generating Facility shall be measured at or, at \nthe Metering Party’s option, compensated to, the Point of Interconnection.  If \nInterconnection Customer will share Interconnection Facilities with any other projects, \nInterconnection Customer shall install Metering Equipment either on its own Generating \nFacility or its own non-shared facilities sufficient to measure the output of such \nInterconnection Customer’s Generating Facility separately from any other Generating \nFacilities with which it will share Interconnection Facilities.   The Metering Party shall \nprovide metering quantities, in analog and/or digital form, to the other Parties upon \nrequest.  Interconnection Customer shall bear all reasonable documented costs associated \nwith the purchase, installation, operation, testing and maintenance of the Metering \nEquipment.  Interconnection customer with a Generating Facility granted ZG \nInterconnection Service shall install and meter for its Generating Facility separate from \nany metering used for the ZG Associated Load."},{"page":467,"startToken":132107,"endToken":132455,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \n7.1.1: \nMarket Registration:  An Interconnection customer with a Generating Facility \ngranted ZG Interconnection Service greater than 5 MW shall submit a \ncompleted Market Participant Application pursuant to Section 38.2 et seq. of the \nTariff (Module C) not later than thirty (30) Calendar Days after the executing or \nrequesting the unexecuted filing of this Agreement  Interconnection Customer \nwith ZG Interconnection Service shall take all steps required by the MISO \nTariff and applicable Business Practices Manual to complete registration as a \nGeneration Resource, Energy Storage Resource, or Dispatchable Intermittent \nResource based on its applicable operating characteristics prior to its \nCommercial Operation Date and shall maintain such registration for the \nduration of its ZG Interconnection Service. \n \n7.2 \nCheck Meters.  Interconnection Customer, at its option and expense, may install and \noperate, on its premises and on its side of the Point of Interconnection, one or more check \nmeters to check the Metering Equipment owned by the Metering Party.  Such check \nmeters shall be for check purposes only and shall not be used for the measurement of \npower flows for purposes of this ZGIA, except as provided in Article 7.4 below.  The \ncheck meters shall be subject at all reasonable times to inspection and examination by \nTransmission Provider, Transmission Owner or their designees.  The installation, \noperation and maintenance thereof shall be performed entirely by Interconnection \nCustomer in accordance with Good Utility Practice. \n \n7.3 \nStandards.  The Metering Party shall install, calibrate, and test revenue quality Metering \nEquipment in accordance with applicable ANSI standards. \n \n7.4 \nTesting of Metering Equipment.  The Metering Party shall inspect and test Metering \nEquipment upon installation and at least once every two (2) years thereafter.  If requested \nto do so by a Party, the Metering Party shall, at the requesting Party’s expense, inspect or \ntest Metering Equipment more frequently than every two (2) years.  The Metering Party \nshall give reasonable notice to the other Parties of the time when any inspection or test"},{"page":468,"startToken":132455,"endToken":132804,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nshall take place, and the other Parties may have representatives present at the test or \ninspection.  If at any time Metering Equipment is found to be inaccurate or defective, it \nshall be adjusted, repaired or replaced at Interconnection Customer’s expense, in order to \nprovide accurate metering, unless the inaccuracy or defect is due to the Metering Party’s \nfailure to maintain, then the Metering Party shall pay.  If Metering Equipment fails to \nregister, or if the measurement made by Metering Equipment during a test varies by more \nthan two percent (2%) from the measurement made by the standard meter used in the test, \nthe Metering Party shall adjust the measurements by correcting all measurements for the \nperiod during which Metering Equipment was in error by using Interconnection \nCustomer’s check meters, if installed.  If no such check meters are installed or if the \nperiod cannot be reasonably ascertained, the adjustment shall be for the period \nimmediately preceding the test of the Metering Equipment equal to one-half the time \nfrom the date of the previous test of the Metering Equipment. \n \n7.5 \nMetering Data.  At Interconnection Customer’s expense, the metered data shall be \ntelemetered to one or more locations designated by Transmission Provider and \nTransmission Owner and one or more locations designated by Interconnection Customer.  \nSuch telemetered data shall be used, under normal operating conditions, as the official \nmeasurement of the amount of energy delivered from the Generating Facility to the Point \nof Interconnection. \n \nARTICLE 8.  COMMUNICATIONS \n \n8.1 \nInterconnection Customer Obligations.  Interconnection Customer shall maintain \nsatisfactory operating communications with Transmission Provider’s Transmission \nSystem dispatcher or representative designated by Transmission Provider.  \nInterconnection Customer shall provide standard voice line, dedicated voice line and \nfacsimile communications at its Generating Facility control room or central dispatch \nfacility through use of either the public telephone system, or a voice communications \nsystem that does not rely on the public telephone system.  Interconnection Customer shall \nalso provide the dedicated data circuit(s) necessary to provide Interconnection Customer"},{"page":469,"startToken":132804,"endToken":133140,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\ndata to Transmission Provider as set forth in Appendix D, Security Arrangements Details.  \nThe data circuit(s) shall extend from the Generating Facility to the location(s) specified \nby Transmission Provider.  Any required maintenance of such communications \nequipment shall be performed by and at the cost of Interconnection Customer.  \nOperational communications shall be activated and maintained under, but not be limited \nto, the following events:  system paralleling or separation, scheduled and unscheduled \nshutdowns, equipment clearances, and hourly and daily load data. \n \n \nUnless the Generating Facility is an Intermittent Resource not relying on wind or solar as \na fuel source, Interconnection Customer shall install communication and control \nequipment such that the Generating Facility can receive and respond to the appropriate \ndispatch signals while operating under the Tariff. Where applicable, the requirements of \nthe communication and control equipment will be enumerated in Appendix C to this \nZGIA. \n \n8.2 \nRemote Terminal Unit (RTU).  Prior to the Initial Synchronization Date of the \nGenerating Facility, a remote terminal unit, or equivalent data collection and transfer \nequipment acceptable to both Parties, shall be installed by Interconnection Customer, or \nby Transmission Owner at Interconnection Customer’s expense, to gather accumulated \nand instantaneous data to be telemetered to the location(s) designated by Transmission \nOwner and Transmission Provider through use of a dedicated point-to-point data \ncircuit(s) as indicated in Article 8.1.  The communication protocol for the data circuit(s) \nshall be specified by Transmission Owner and Transmission Provider.  Instantaneous bi-\ndirectional analog real power and reactive power flow information must be telemetered \ndirectly to the location(s) specified by Transmission Provider and Transmission Owner. \n \n \nEach Party will promptly advise the other Parties if it detects or otherwise learns of any \nmetering, telemetry or communications equipment errors or malfunctions that require the \nattention and/or correction.  The Party owning such equipment shall correct such error or \nmalfunction as soon as reasonably feasible."},{"page":470,"startToken":133140,"endToken":133501,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n8.3 \nNo Annexation.  Any and all equipment placed on the premises of a Party shall be and \nremain the property of the Party providing such equipment regardless of the mode and \nmanner of annexation or attachment to real property, unless otherwise mutually agreed by \nthe Parties. \n \n8.4 \nProvision of Data from a Variable Energy Resource.  Interconnection Customer \nwhose Generating Facility contains at least one Variable Energy Resource shall provide \nmeteorological and forced outage data to the Transmission Provider to the extent \nnecessary for the Transmission Provider’s development and deployment of power \nproduction forecasts for that class of Variable Energy Resources.  Interconnection \nCustomer with a Variable Energy Resource having wind as the energy source will, upon \nrequest by the Transmission Provider, be required to provide Transmission Provider with \nsite-specific meteorological data including:  temperature, wind speed, wind direction, and \natmospheric pressure.  Interconnection Customer with a Variable Energy Resource \nhaving solar as the energy source will, upon request by the Transmission Provider, be \nrequired to provide the Transmission Provider with site-specific meteorological data \nincluding:  temperature, atmospheric pressure, and irradiance.  Transmission Provider \nand Interconnection Customer whose Generating Facility contains a Variable Energy \nResource shall mutually agree to any additional meteorological data that are required for \nthe development and deployment of a power production forecast.  Interconnection \nCustomer whose Generating Facility contains a Variable Energy Resource also shall \nsubmit data to Transmission Provider regarding all forced outages to the extent necessary \nfor Transmission Provider’s development and deployment of power production forecasts \nfor that class of Variable Energy Resources.  The exact specifications of the \nmeteorological and forced outage data to be provided by Interconnection Customer to \nTransmission Provider, including the frequency and timing of data submittals, shall be \nmade taking into account the size and configuration of the Variable Energy Resource, its \ncharacteristics, location, and its importance in maintaining generation resource adequacy \nand transmission system reliability in its area.  All requirements for meteorological and \nforced outage data must be commensurate with the power production forecasting \nemployed by Transmission Provider.  Data requirements for meteorological and forced"},{"page":471,"startToken":133501,"endToken":133817,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\noutage data will be negotiated by Transmission Provider and Interconnection Customer, \nand will be set forth in Appendix C, Interconnection Details, of this ZGIA. \n \nARTICLE 9.  OPERATIONS \n \n9.1 \nGeneral.  Each Party shall comply with the Electric Reliability Organization \nrequirements.  Each Party shall provide to any Party all information that may reasonably \nbe required by that Party to comply with Applicable Laws and Regulations and \nApplicable Reliability Standards.  \n \n9.2 \nLocal Balancing Authority Notification.  At least three (3) months before Initial \nSynchronization Date, Interconnection Customer shall notify Transmission Provider and \nTransmission Owner in writing of the Local Balancing Authority in which the Generating \nFacility will be located.  If Interconnection Customer elects to locate the Generating \nFacility through dynamic metering/scheduling in a Local Balancing Authority other than \nthe Local Balancing Authority in which the Generating Facility is physically located, and \nif permitted to do so by the relevant transmission tariffs, all necessary arrangements, \nincluding but not limited to those set forth in Article 7 and Article 8 of this ZGIA, and \nremote Local Balancing Authority generator interchange agreements, if applicable, and \nthe appropriate measures under such agreements, shall be executed and implemented \nprior to the placement of the Generating Facility in the other Local Balancing Authority. \n \n9.3 \nTransmission Provider and Transmission Owner Obligations.  Transmission Provider \nshall cause the Transmission System and the Transmission Owner’s Interconnection \nFacilities to be operated, maintained and controlled in a safe and reliable manner in \naccordance with this ZGIA.  Transmission Provider, or its designee, may provide \noperating instructions to Interconnection Customer consistent with this ZGIA and the \nTariff and, if applicable, Transmission Owner’s operating protocols and procedures as \nthey may change from time to time.  Transmission Provider will consider changes to its \noperating protocols and procedures proposed by Interconnection Customer."},{"page":472,"startToken":133817,"endToken":134125,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n9.4 \nInterconnection Customer Obligations.  Interconnection Customer shall at its own \nexpense operate, maintain and control the Generating Facility and the Interconnection \nCustomer’s Interconnection Facilities in a safe and reliable manner and in accordance \nwith this ZGIA.  The Generating Facility must be operated in accordance with the \noperating limits, if any, in the Interconnection Facilities Study and specified in Appendix \nC of this ZGIA.  Interconnection Customer shall operate the Generating Facility and the \nInterconnection Customer’s Interconnection Facilities in accordance with all applicable \nrequirements of Transmission Provider or its designated Local Balancing Authority \nOperator of which the Generating Facility is part, as such requirements are set forth in \nAppendix C, Interconnection Details, of this ZGIA.  Appendix C, Interconnection \nDetails, will be modified to reflect changes to the requirements as they may change from \ntime to time.  Any Party may request that a Party provide copies of the requirements set \nforth in Appendix C, Interconnection Details, of this ZGIA. \n \n9.5 \nStart-Up and Synchronization.  Consistent with the Parties’ mutually acceptable \nprocedures, Interconnection Customer is responsible for the proper synchronization of the \nGenerating Facility to the Transmission or Distribution System, as applicable.  \n \n9.6 \nReactive Power and Primary Frequency Response. \n \n9.6.1 Power Factor Design Criteria. \n \n9.6.1.1 Synchronous Generation.  Interconnection Customer shall design the \nGenerating Facility to be capable of maintaining a composite power delivery at \ncontinuous rated power output at the Point of Interconnection at all power factors \nover 0.95 leading to 0.95 lagging, unless the Transmission Provider has \nestablished different requirements that apply to all synchronous generators in the \nLocal Balancing Authority on a comparable basis.  The applicable Local \nBalancing Authority power factor requirements are listed on the Transmission \nProvider’s website at"},{"page":473,"startToken":134125,"endToken":134450,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nhttps://cdn.misoenergy.org/Reactive_Generator_Requirements108137.pdf \n \nand may be referenced in the Appendices to this ZGIA.  The Generating Facility \nshall be capable of continuous dynamic operation throughout the power factor \ndesign range as measured at the Point of Interconnection.  Such operation shall \naccount for the net effect of all energy production devices on the Interconnection \nCustomer’s side of the Point of Interconnection.   \n \n9.6.1.2 Inverter-Based Resource Plants.  Interconnection Customer shall design \nthe Generating Facility to be capable of maintaining a composite power delivery \nat continuous rated power output at the high-side of the generator substation at all \npower factors over 0.95 leading to 0.95 lagging, unless the Transmission Provider \nhas established different requirements that apply to all inverter-based resource \nplants in the Local Balancing Authority on a comparable basis.  The applicable \nLocal Balancing Authority power factor requirements are listed on the \nTransmission Provider’s website at  \n \nhttps://cdn.misoenergy.org/Reactive_Generator_Requirements108137.pdf \n \nand may be referenced in the Appendices to this ZGIA.  This power factor range \nstandard shall be dynamic and can be met using, for example, power electronics \ndesigned to supply this level of reactive capability (taking into account any \nlimitations due to voltage level, real power output, etc.) or fixed and switched \ncapacitors, or a combination of the two.  This requirement shall only apply to \nnewly interconnecting inverter-based resource plants that have not yet completed \na System Impact Study as of the effective date of the Final Rule establishing this \nrequirement (Order No. 827).  These requirements apply to existing inverter-\nbased resource plants making upgrades that require a new Generator \nInterconnection Agreement only where the Transmission Provider’s System \nImpact Study shows the need for reactive power as a result of an upgrade.  If \napplicable, these requirements will be memorialized in Appendix C to this ZGIA."},{"page":474,"startToken":134450,"endToken":134754,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \nAdditional reactive power requirements for inverter-based resource plants are \nprovided in Appendix G of this ZGIA. \n \n \n9.6.2 Voltage Schedules.  Once Interconnection Customer has synchronized the \nGenerating Facility with the Transmission System, Transmission Provider shall \nrequire Interconnection Customer to operate the Generating Facility to produce or \nabsorb reactive power within the design limitations of the Generating Facility set \nforth in Article 9.6.1 (Power Factor Design Criteria), to maintain the output \nvoltage or power factor at the Point of Interconnection as specified by \nTransmission Provider.  Transmission Provider’s voltage schedules shall treat all \nsources of reactive power in the Local Balancing Authority in an equitable and \nnot unduly discriminatory manner.  Transmission Provider shall exercise \nReasonable Efforts to provide Interconnection Customer with such schedules at \nleast one (1) Calendar Day in advance, and may make changes to such schedules \nas necessary to maintain the reliability of the Transmission or Distribution System \nas applicable.  Interconnection Customer shall operate the Generating Facility to \nmaintain the specified output voltage or power factor at the Point of \nInterconnection within the design limitations of the Generating Facility set forth \nin Article 9.6.1 (Power Factor Design Criteria).  If Interconnection Customer is \nunable to maintain the specified voltage or power factor, it shall promptly notify \nTransmission Provider’s system operator, or its designated representative. \n \n9.6.2.1 Voltage Regulators.  Whenever the Generating Facility is operated in \nparallel with the Transmission or Distribution System as applicable and \nvoltage regulators are capable of operation, Interconnection Customer \nshall operate the Generating Facility with its speed governors and \nvoltage regulators in automatic operation.  If the Generating Facility’s \nvoltage regulators are not capable of such automatic operation, \nInterconnection Customer shall immediately notify Transmission"},{"page":475,"startToken":134754,"endToken":135070,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nProvider’s system operator, or its designated representative, and ensure \nthat such Generating Facility’s reactive power production or absorption \n(measured in MVARs) are within the design capability of the Generating \nFacility’s generating unit(s) and steady state stability limits.  \nInterconnection Customer shall not cause its Generating Facility to \ndisconnect automatically or instantaneously from the Transmission or \nDistribution System, as applicable, or trip any generating unit \ncomprising the Generating Facility for an under or over frequency \ncondition unless the abnormal frequency condition persists for a time \nperiod beyond the limits set forth in ANSI/IEEE Standard C37.106, or \nsuch other standard as applied to other generators in the Local Balancing \nAuthority on a comparable basis. \n \n9.6.3 Payment for Reactive Power.  Payments for reactive power shall be pursuant to \nany tariff or rate schedule filed by Transmission Provider and approved by the \nFERC.  \n \n9.6.4  Primary Frequency Response. This Section 9.6.4 shall only apply in the event \nthat the Interconnection Request for the Generating Facility completed Definitive \nPlanning Phase Interconnection Customer Decision Point 2 after May 15, 2018. \n \n \nInterconnection Customer shall ensure the primary frequency response capability \nof its Generating Facility by installing, maintaining, and operating a functioning \ngovernor or equivalent controls. The term “functioning governor or equivalent \ncontrols” as used herein shall mean the required hardware and/or software that \nprovides frequency responsive real power control with the ability to sense \nchanges in system frequency and autonomously adjust the Generating Facility’s \nreal power output in accordance with the droop and deadband parameters and in \nthe direction needed to correct frequency deviations. Interconnection Customer is \nrequired to install a governor or equivalent controls with the capability of \noperating: (1) with a maximum 5 percent droop and ±0.036 Hz deadband; or (2)"},{"page":476,"startToken":135070,"endToken":135420,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nin accordance with the relevant droop, deadband, and timely and sustained \nresponse settings from an approved Reliability Organization reliability standard \nproviding for equivalent or more stringent parameters.  The droop characteristic \nshall be: (1) based on the nameplate capacity of the Generating Facility, and shall \nbe linear in the range of frequencies between 59 to 61 Hz that are outside of the \ndeadband parameter; or (2) based on an approved Electric Reliability \nOrganization reliability standard providing for an equivalent or more stringent \nparameter.  The deadband parameter shall be: the range of frequencies above and \nbelow nominal (60 Hz) in which the governor or equivalent controls is not \nexpected to adjust the Generating Facility’s real power output in response to \nfrequency deviations.  The deadband shall be implemented: (1) without a step to \nthe droop curve, that is, once the frequency deviation exceeds the deadband \nparameter, the expected change in the Generating Facility’s real power output in \nresponse to frequency deviations shall start from zero and then increase (for \nunder-frequency deviations) or decrease (for over-frequency deviations) linearly \nin proportion to the magnitude of the frequency deviation; or (2) in accordance \nwith an approved Electric Reliability Organization Reliability Standard providing \nfor an equivalent or more stringent parameter. Interconnection Customer shall \nnotify Transmission Provider that the primary frequency response capability of \nthe Generating Facility has been tested and confirmed during commissioning. \nOnce Interconnection Customer has synchronized the Generating Facility with the \nTransmission System, Interconnection Customer shall operate the Generating \nFacility consistent with the provisions specified in Articles 9.6.4.1 and 9.6.4.2 of \nthis ZGIA. The primary frequency response requirements contained herein shall \napply to both synchronous and inverter-based resource plant Generating Facilities. \n \n9.6.4.1  Governor or Equivalent Controls. Whenever the Generating Facility is \noperated in parallel with the Transmission System, Interconnection \nCustomer shall operate the Generating Facility with its governor or \nequivalent controls in service and responsive to frequency. \nInterconnection Customer shall: (1) in coordination with Transmission"},{"page":477,"startToken":135420,"endToken":135740,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nProvider and/or the relevant balancing authority, set the deadband \nparameter to: (a) a maximum of ±0.036 Hz and set the droop parameter \nto a maximum of 5 percent; or (b) implement the relevant droop and \ndeadband settings from an approved Regional Reliability Organization \nreliability standard that provides for equivalent or more stringent \nparameters. Interconnection Customer shall be required to provide the \nstatus and settings of the governor or equivalent controls to \nTransmission Provider and/or the relevant balancing authority upon \nrequest. If Interconnection Customer needs to operate the Generating \nFacility with its governor or equivalent controls not in service, \nInterconnection Customer shall immediately notify Transmission \nProvider and the relevant balancing authority, and provide both with the \nfollowing information: (1) the operating status of the governor or \nequivalent controls (i.e., whether it is currently out of service or when it \nwill be taken out of service); (2) the reasons for removing the governor \nor equivalent controls from service; and (3) a reasonable estimate of \nwhen the governor or equivalent controls will be returned to service. \nInterconnection Customer shall make Reasonable Efforts to return its \ngovernor or equivalent controls into service as soon as practicable. \nInterconnection Customer shall make Reasonable Efforts to keep \noutages of the Generating Facility’s governor or equivalent controls to a \nminimum whenever the Generating Facility is operated in parallel with \nthe Transmission System. \n \n9.6.4.2  Timely and Sustained Response. Interconnection Customer shall \nensure that the Generating Facility’s real power response to sustained \nfrequency deviations outside of the deadband setting is automatically \nprovided and shall begin immediately after frequency deviates outside of \nthe deadband, and to the extent the Generating Facility has operating \ncapability in the direction needed to correct the frequency deviation. \nInterconnection Customer shall not block or otherwise inhibit the ability"},{"page":478,"startToken":135740,"endToken":136081,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nof the governor or equivalent controls to respond and shall ensure that \nthe response is not inhibited, except under certain operational constraints \nincluding, but not limited to, ambient temperature limitations, physical \nenergy limitations, outages of mechanical equipment, or regulatory \nrequirements. The Generating Facility shall sustain the real power \nresponse at least until system frequency returns to a value within the \ndeadband setting of the governor or equivalent controls. A Commission-\napproved reliability standard with equivalent or more stringent \nrequirements shall supersede the above requirements. \n \n9.6.4.3  Exemptions. Generating Facilities that are regulated by the United \nStates Nuclear Regulatory Commission shall be exempt from Articles \n9.6.4, 9.6.4.1, and 9.6.4.2 of this ZGIA. Generating Facilities that are \nbehind the meter generation that is sized-to-load (i.e., the thermal load \nand the generation are near-balanced in real-time operation and the \ngeneration is primarily controlled to maintain the unique thermal, \nchemical, or mechanical output necessary for the operating requirements \nof its host facility) shall be required to install primary frequency \nresponse capability in accordance with the droop and deadband \ncapability requirements specified in Article 9.6.4, but shall be otherwise \nexempt from the operating requirements in Articles 9.6.4, 9.6.4.1, \n9.6.4.2, and 9.6.4.4 of this ZGIA.   \n \n9.6.4.4  Electric Storage Resources. Interconnection Customer interconnecting \nan electric storage resource shall establish an operating range in \nAppendix C that specifies a minimum state of charge and a maximum \nstate of charge between which the electric storage resource will be \nrequired to provide primary frequency response consistent with the \nconditions set forth in Articles 9.6.4, 9.6.4.1, 9.6.4.2 and 9.6.4.3 of this \nZGIA. Appendix C shall specify whether the operating range is static or \ndynamic, and shall consider (1) the expected magnitude of frequency"},{"page":479,"startToken":136081,"endToken":136326,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\ndeviations in the interconnection; (2) the expected duration that system \nfrequency will remain outside of the deadband parameter in the \ninterconnection; (3) the expected incidence of frequency deviations \noutside of the deadband parameter in the interconnection; (4) the \nphysical capabilities of the electric storage resource; (5) operational \nlimitations of the electric storage resource due to manufacturer \nspecifications; and (6) any other relevant factors agreed to by \nTransmission Provider and Interconnection Customer, and in \nconsultation with the relevant transmission owner or balancing authority \nas appropriate. If the operating range is dynamic, then Appendix C must \nestablish how frequently the operating range will be reevaluated and the \nfactors that may be considered during its reevaluation. \n \n \nInterconnection Customer’s electric storage resource is required to \nprovide timely and sustained primary frequency response consistent with \nArticle 9.6.4.2 of this ZGIA when it is online and dispatched to inject \nelectricity to the Transmission System and/or receive electricity from the \nTransmission System. This excludes circumstances when the electric \nstorage resource is not dispatched to inject electricity to the \nTransmission System and/or dispatched to receive electricity from the \nTransmission System. \n \n9.6.4.5 Inverter-Based Resource Plants. Additional primary frequency \nresponse requirements for inverter-based resource plants, including \nelectric storage resources, are provided in Appendix G of this ZGIA. \n \n9.7 \nOutages and Interruptions. \n \n9.7.1 Outages."},{"page":480,"startToken":136326,"endToken":136626,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n9.7.1.1 Outage Authority and Coordination.  Interconnection Customer and \nTransmission Owner may each in accordance with Good Utility Practice \nin coordination with the other Party and Transmission Provider remove \nfrom service any of its respective Interconnection Facilities, System \nProtection Facilities, Network Upgrades, System Protection Facilities or \nDistribution Upgrades that may impact the other Party’s facilities as \nnecessary to perform maintenance or testing or to install or replace \nequipment.  Absent an Emergency Condition, the Party scheduling a \nremoval of such facility(ies) from service will use Reasonable Efforts to \nnotify one another and schedule such removal on a date and time \nmutually acceptable to the Parties.  In all circumstances, any Party \nplanning to remove such facility(ies) from service shall use Reasonable \nEfforts to minimize the effect on the other Parties of such removal.  \n \n9.7.1.2 Outage Schedules.  Transmission Provider shall post scheduled outages \nof transmission facilities on the OASIS.  Interconnection Customer shall \nsubmit its planned maintenance schedules for the Generating Facility to \nTransmission Provider and Transmission Owner for a minimum of a \nrolling twenty-four (24) month period in accordance with the \nTransmission Provider’s procedures.  Interconnection Customer shall \nupdate its planned maintenance schedules as necessary.  Transmission \nProvider may request Interconnection Customer to reschedule its \nmaintenance as necessary to maintain the reliability of the Transmission \nSystem; provided, however, adequacy of generation supply shall not be a \ncriterion in determining Transmission System reliability. \n \n \nTransmission Provider shall compensate, pursuant to applicable \nTransmission Provider tariff or rate schedule, Interconnection Customer \nfor any additional direct costs that Interconnection Customer incurs as a \nresult of having to reschedule maintenance, including any additional \novertime, breaking of maintenance contracts or other costs above and"},{"page":481,"startToken":136626,"endToken":136927,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nbeyond the cost Interconnection Customer would have incurred absent \nthe Transmission Provider’s request to reschedule maintenance.  \nInterconnection Customer will not be eligible to receive compensation, if \nduring the twelve (12) months prior to the date of the scheduled \nmaintenance, Interconnection Customer had modified its schedule of \nmaintenance activities. \n \nCosts shall be determined by negotiation between Transmission Provider \nand Interconnection Customer prior to implementation of the voluntary \nchange in outage schedules, or if such request is made by or on behalf of \na Transmission Customer requesting firm service, costs and recovery of \ncosts shall be determined through a bilateral agreement between the \nTransmission Customer and Interconnection Customer.  Voluntary \nchanges to outage schedules under this Article 9.7.1.2 are separate from \nactions and compensation required under Article 13 and for which costs \nare recovered in accordance with Transmission Provider’s applicable \ntariff or rate schedule. \n \n9.7.1.3 Outage Restoration.  If an outage on either the Interconnection \nCustomer’s or Transmission Owner’s Interconnection Facilities, \nNetwork Upgrades, System Protection Facilities or Distribution \nUpgrades adversely affects a Party’s operations or facilities, the Party \nthat owns or controls the facility that is out of service shall use \nReasonable Efforts to promptly restore such facility(ies) to a normal \noperating condition consistent with the nature of the outage.  The Party \nthat owns or controls the facility that is out of service shall provide the \nother Parties, to the extent such information is known, information on \nthe nature of the Emergency Condition, an estimated time of restoration, \nand any corrective actions required.  Initial verbal notice shall be \nfollowed up as soon as practicable with written notice to the other \nParties explaining the nature of the outage."},{"page":482,"startToken":136927,"endToken":137201,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \n9.7.2 Interruption of Service.  If required by Good Utility Practice to do so, \nTransmission Provider may require Interconnection Customer to interrupt or \nreduce deliveries of electricity if such delivery of electricity could adversely \naffect Transmission Provider’s ability to perform such activities as are necessary \nto safely and reliably operate and maintain the Transmission System.  The \nfollowing provisions shall apply to any interruption or reduction permitted under \nthis Article 9.7.2: \n \n9.7.2.1 The interruption or reduction shall continue only for so long as \nreasonably necessary under Good Utility Practice; \n \n9.7.2.2 Any such interruption or reduction shall be made on an equitable, non-\ndiscriminatory basis with respect to all generating facilities directly \nconnected to the Transmission or Distribution System, as applicable; \n \n9.7.2.3 When the interruption or reduction must be made under circumstances \nwhich do not allow for advance notice, Transmission Provider shall \nnotify Interconnection Customer by telephone as soon as practicable of \nthe reasons for the curtailment, interruption, or reduction, and, if known, \nits expected duration.  Telephone notification shall be followed by \nwritten notification as soon as practicable; \n \n9.7.2.4 Except during the existence of an Emergency Condition, when the \ninterruption or reduction can be scheduled without advance notice, \nTransmission Provider shall notify Interconnection Customer in advance \nregarding the timing of such scheduling and further notify \nInterconnection Customer of the expected duration.  Transmission \nProvider shall coordinate with Interconnection Customer using Good \nUtility Practice to schedule the interruption or reduction during periods"},{"page":483,"startToken":137201,"endToken":137511,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nof least impact to Interconnection Customer, Transmission Owner and \nTransmission Provider; \n \n9.7.2.5 The Parties shall cooperate and coordinate with each other to the extent \nnecessary in order to restore the Generating Facility, Interconnection \nFacilities, and the Transmission or Distribution System, as applicable to \ntheir normal operating state, consistent with system conditions and Good \nUtility Practice. \n \n9.7.3  Ride Through Capability and Performance.  The Transmission System is \ndesigned to automatically activate a load-shed program as required by the Electric \nReliability Organization in the event of an underfrequency system disturbance.  \nInterconnection Customer shall implement under-frequency and over-frequency \nrelay set points for the Generating Facility as required by the Electric Reliability \nOrganization to ensure frequency “ride through” capability of the Transmission \nSystem.  Generating Facility response to frequency deviations of pre-determined \nmagnitudes, both under-frequency and over-frequency deviations, shall be studied \nand coordinated with Transmission Provider in accordance with Good Utility \nPractice.  Interconnection Customer shall also implement under-voltage and over-\nvoltage relay set points, or equivalent electronic controls, as required by the \nElectric Reliability Organization to ensure voltage “ride through” capability of the \nTransmission System.  The term “ride through” as used herein shall mean the \nability of a Generating Facility to stay connected to and synchronized with the \nTransmission System during system disturbances within a range of under-\nfrequency, over-frequency, under-voltage, and over-voltage conditions, in \naccordance with Good Utility Practice and consistent with any standards and \nguidelines that are applied to other Generating Facilities in the Balancing \nAuthority Area on a comparable basis.  For abnormal frequency conditions and \nvoltage conditions within the “no trip zone” defined by Reliability Standard PRC-\n024-3 or successor mandatory ride through reliability standards, the non-\nsynchronous Generating Facility must ensure that, within any physical limitations"},{"page":484,"startToken":137511,"endToken":137772,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nof the Generating Facility, its control and protection settings are configured or set \nto (1) continue active power production during disturbance and post disturbance \nperiods at pre-disturbance levels, unless providing primary frequency response or \nfast frequency response; (2) minimize reductions in active power and remain \nwithin dynamic voltage and current limits, if reactive power priority mode is \nenabled, unless providing primary frequency response or fast frequency response; \n(3) not artificially limit dynamic reactive power capability during disturbances; \nand (4) return to pre-disturbance active power levels without artificial ramp rate \nlimits if active power is reduced, unless providing primary frequency response or \nfast frequency response. \n \n9.7.4 System Protection and Other Control Requirements. \n \n9.7.4.1 System Protection Facilities.  Interconnection Customer shall, at its \nexpense, install, operate and maintain its System Protection Facilities as \na part of the Generating Facility or the Interconnection Customer’s \nInterconnection Facilities.  Transmission Owner shall install at \nInterconnection Customer’s expense any Transmission Owner’s System \nProtection Facilities that may be required on the Transmission Owner’s \nInterconnection Facilities or the Transmission Owner’s transmission or \ndistribution facilities as a result of the interconnection of the Generating \nFacility and the Interconnection Customer’s Interconnection Facilities. \n \n9.7.4.2 Interconnection Customer’s and Transmission Owner’s System \nProtection Facilities shall be designed and coordinated with Affected \nSystems in accordance with Good Utility Practice. \n \n9.7.4.3 Each Party shall be responsible for protection of its facilities consistent \nwith Good Utility Practice."},{"page":485,"startToken":137772,"endToken":138059,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n9.7.4.4 Each Party’s protective relay design shall incorporate the necessary test \nswitches to perform the tests required in Article 6. The required test \nswitches will be placed such that they allow operation of lockout relays \nwhile preventing breaker failure schemes from operating and causing \nunnecessary breaker operations and/or the tripping of the Generating \nFacility. \n \n9.7.4.5 Each Party will test, operate and maintain their respective System \nProtection Facilities in accordance with Good Utility Practice.  \n \n9.7.4.6 Prior to the In-Service Date, and again prior to the Commercial \nOperation Date, Interconnection Customer or Transmission Owner, or \ntheir respective agents, shall perform a complete calibration test and \nfunctional trip test of the System Protection Facilities.  At intervals \nsuggested by Good Utility Practice and following any apparent \nmalfunction of the System Protection Facilities, Interconnection \nCustomer or Transmission Owner shall each perform both calibration \nand functional trip tests of their respective System Protection Facilities.  \nThese tests do not require the tripping of any in-service generating unit.  \nThese tests do, however, require that all protective relays and lockout \ncontacts be activated. \n \n9.7.4.7  Obligation of a Generating Facility with ZG Interconnection Services to \nReduce Production of Energy Under Certain Conditions.  A Generating \nFacility with ZG Interconnection Service shall: \na.  Install communications and monitoring equipment to enable it to \nmonitor the Demand of the ZG Associated Load. \nb. Install equipment to enable the Generating Facility with ZG \nInterconnection service to reduce its injections to a level that does \nnot exceed the Demand of the ZG Associated Load within the \nTransient Tolerance Window."},{"page":486,"startToken":138059,"endToken":138382,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nc. Cease all injection of Energy onto the Transmission System within \nthe time permitted by the Transient Tolerance Window in the event \nthat any Transmission Facility over which Energy must flow in order \nto reach the point of interconnection or Point of Withdrawal of the  \nZG Associated Load trips offline.  \nThe equipment to be used by the Generating Facility with ZG \nInterconnection Service to comply with the requirements of this 9.7.4.7 \nshall be identified in Appendix A of this ZGIA.  Appendix A of this \nZGIA shall include a one line diagram showing the Generating Facility \nand associated electrical equipment with appropriate rating and \nimpedance information and all the ZG Associated loads including all \nPoint(s) of Withdrawal and the Point of Interconnection of the \nGenerating Facility to the Transmission System for the Interconnection \nRequest. \n \n9.7.5 Requirements for Protection.  In compliance with Good Utility Practice, \nInterconnection Customer shall provide, install, own, and maintain relays, circuit \nbreakers and all other devices necessary to remove any fault contribution of the \nGenerating Facility to any short circuit occurring on the Transmission or \nDistribution System, as applicable, not otherwise isolated by Transmission \nOwner’s equipment, such that the removal of the fault contribution shall be \ncoordinated with the protective requirements of the Transmission or Distribution \nSystem, as applicable.  Such protective equipment shall include, without \nlimitation, a disconnecting device or switch with load-interrupting capability \nlocated between the Generating Facility and the Transmission or Distribution \nSystem, as applicable, at a site selected upon mutual agreement (not to be \nunreasonably withheld, conditioned or delayed) of the Parties.  Interconnection \nCustomer shall be responsible for protection of the Generating Facility and \nInterconnection Customer’s other equipment from such conditions as negative \nsequence currents, over- or under-frequency, sudden load rejection, over- or \nunder-voltage, and generator loss-of-field.  Interconnection Customer shall be"},{"page":487,"startToken":138382,"endToken":138697,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nsolely responsible to disconnect the Generating Facility and Interconnection \nCustomer’s other equipment if conditions on the Transmission or Distribution \nSystem, as applicable, could adversely affect the Generating Facility.  For a \nGenerating Facility with ZG Interconnection Service the restriction on Energy \ninjection in this paragraph shall not apply to transient, limited injections \nassociated with a reduction or loss of Load by the ZG Associated Load provided \nthese remain within the Transient Tolerance Window as may be further described \nin the Business Practices Manual for Large Load.   \n \n9.7.6 Power Quality.  Neither Party’s facilities shall cause excessive voltage flicker \nnor introduce excessive distortion to the sinusoidal voltage or current waves as \ndefined by ANSI Standard C84.1, in accordance with IEEE Standard 519, or any \napplicable superseding electric industry standard.  In the event of a conflict \nbetween ANSI Standard C84.1, and any applicable superseding electric industry \nstandard, the applicable superseding electric industry standard shall control. \n \n9.8 \nSwitching and Tagging Rules.  Prior to the Initial Synchronization Date, each Party \nshall provide the other Parties a copy of its switching and tagging rules that are applicable \nto the other Parties’ activities.  Such switching and tagging rules shall be developed on a \nnon-discriminatory basis.  The Parties shall comply with applicable switching and \ntagging rules, as amended from time to time, in obtaining clearances for work or for \nswitching operations on equipment. \n \n9.9 \nUse of Interconnection Facilities by Other Parties. \n \n9.9.1 Purpose of Interconnection Facilities.  Except as may be required by Applicable \nLaws and Regulations, or as otherwise agreed to among the Parties, the \nInterconnection Facilities shall be constructed for the sole purpose of \ninterconnecting the Generating Facility to the Transmission or Distribution \nSystem, as applicable, and shall be used for no other purpose."},{"page":488,"startToken":138697,"endToken":139000,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n9.9.2 Other Users.  If required by Applicable Laws and Regulations or if the Parties \nmutually agree, such agreement not to be unreasonably withheld or delayed, to \nallow one or more Parties to use the Transmission Owner’s Interconnection \nFacilities, or any part thereof, Interconnection Customer will be entitled to \ncompensation for the capital expenses it incurred in connection with the \nInterconnection Facilities based upon the pro rata use of the Interconnection \nFacilities by Transmission Owner, all non-Party users, and Interconnection \nCustomer, in accordance with Applicable Laws and Regulations or upon some \nother mutually-agreed upon methodology.  In addition, cost responsibility for \nongoing costs, including operation and maintenance costs associated with the \nInterconnection Facilities, will be allocated between Interconnection Customer \nand any non-Party users based upon the pro rata use of the Interconnection \nFacilities by Transmission Owner, all non-Party users, and Interconnection \nCustomer, in accordance with Applicable Laws and Regulations or upon some \nother mutually agreed upon methodology.  If the issue of such compensation or \nallocation cannot be resolved through such negotiations, it shall be submitted to \nDispute Resolution pursuant to Section 12 of the Tariff. \n \n9.10 \nDisturbance Analysis Data Exchange.  The Parties will cooperate with one another in \nthe analysis of disturbances to either the Generating Facility or the Transmission System \nby gathering and providing access to any information relating to any disturbance, \nincluding information from oscillography, protective relay targets, breaker operations and \nsequence of events records, and any disturbance information required by Good Utility \nPractice. \n \nARTICLE 10.  MAINTENANCE \n \n10.1 \nTransmission Owner Obligations.  Transmission Owner shall maintain the \nTransmission Owner’s Interconnection Facilities in a safe and reliable manner and in \naccordance with this ZGIA and all Applicable Laws and Regulations."},{"page":489,"startToken":139000,"endToken":139291,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n10.2 \nInterconnection Customer Obligations.  Interconnection Customer shall maintain the \nGenerating Facility and the Interconnection Customer’s Interconnection Facilities in a \nsafe and reliable manner and in accordance with this ZGIA and all Applicable Laws and \nRegulations. \n \n10.3 \nCoordination.  The Parties shall confer regularly to coordinate the planning, scheduling \nand performance of preventive and corrective maintenance on the Generating Facility and \nthe Interconnection Facilities.   \n \n10.4 \nSecondary Systems.  Each Party shall cooperate with the other in the inspection, \nmaintenance, and testing of control or power circuits that operate below 600 volts, AC or \nDC, including, but not limited to, any hardware, control or protective devices, cables, \nconductors, electric raceways, secondary equipment panels, transducers, batteries, \nchargers, and voltage and current transformers that directly affect the operation of a \nParty’s facilities and equipment which may reasonably be expected to impact another \nParty.  Each Party shall provide advance notice to the other Parties before undertaking \nany work on such circuits, especially on electrical circuits involving circuit breaker trip \nand close contacts, current transformers, or potential transformers. \n \n10.5 \nOperating and Maintenance Expenses.  Subject to the provisions herein addressing the \nuse of facilities by others, and except for operations and maintenance expenses associated \nwith modifications made for providing Interconnection Service or Transmission Service \nto a non-Party and such non-Party pays for such expenses, Interconnection Customer \nshall be responsible for all reasonable expenses including overheads, associated with:  \n(1) owning, operating, maintaining, repairing, and replacing Interconnection Customer’s \nInterconnection Facilities; and (2) operation, maintenance, repair and replacement of \nTransmission Owner’s Interconnection Facilities to the extent required by Transmission \nOwner on a comparable basis. \n \nARTICLE 11.  PERFORMANCE OBLIGATION"},{"page":490,"startToken":139291,"endToken":139613,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n11.1 \nInterconnection Customer’s Interconnection Facilities.  Interconnection Customer \nshall design, procure, construct, install, own and/or control the Interconnection \nCustomer’s Interconnection Facilities described in Appendix A at its sole expense. \n \n11.2 \nTransmission Owner’s Interconnection Facilities.  Transmission Owner shall design, \nprocure, construct, install, own and/or control the Transmission Owner’s Interconnection \nFacilities described in Appendix A at the sole expense of Interconnection Customer. \n \n11.3 \nNetwork Upgrades, System Protection Facilities and Distribution Upgrades.  \nTransmission Owner shall design, procure, construct, install, and own the Network \nUpgrades, Transmission Owner’s System Protection Facilities and Distribution Upgrades \ndescribed in Appendix A.  Interconnection Customer shall be responsible for all costs \nrelated to Distribution Upgrades and/or Generator Upgrades. As required by Section \n7.3.2.1 and 7.3.3.1 of Attachment X, Transmission Owner shall have provided \nTransmission Provider with written notice if Transmission Owner elects to fund the \ncapital for the Network Upgrades and Transmission Owner’s System Protection \nFacilities; otherwise, such facilities, if any, shall be solely funded by Interconnection \nCustomer. In the event that the Transmission Owner elects to fund the capital costs of the \nNetwork Upgrades and/or Transmission Owner’s System Protection Facilities, then the \nParties shall enter into a Facilities Service Agreement.  The Facilities Service Agreement \nshall take the form of the pro forma Facilities Service Agreement that is included as \nAppendix 14 of Attachment X to the MISO Tariff.  Any Generating Facility with ZG \nInterconnection Service must have a Point of Interconnection that is located at the same \nvoltage level of the same interconnection substation as the Point(s) of Withdrawal for the \nZG Associated Load it will serve.   \n \nA Generating Facility with ZG Interconnection Service must not require the construction \nof Network Upgrades beyond the substation where the Point of Interconnection is located \nother than System Protection Facilities."},{"page":491,"startToken":139613,"endToken":139972,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n11.3.1 Contingencies Affecting Network Upgrades, System Protection Facilities and \nDistribution Upgrades.  Network Upgrades, System Protection Facilities and \nDistribution Upgrades that are required to accommodate the Generating Facility \nmay be modified because (1) a higher queued Interconnection Request withdrew \nor was deemed to have withdrawn, (2) the interconnection agreement associated \nwith a higher queued Interconnection Request was terminated prior to the \nproject’s In-Service Date, (3) the Commercial Operation Date for a higher queued \nInterconnection Request is delayed, or the project itself is delayed (including due \nto suspension) such that facilities required to accommodate lower queued projects \nor the project itself may be altered, (4) the queue position is reinstated for a \nhigher-queued Interconnection Request whose queue position was subject to \ndispute resolution, (5) changes occur in Transmission Provider or Transmission \nOwner equipment design standards or reliability criteria giving rise to the need for \nrestudy, (6) the facilities required to accommodate a higher queued \nInterconnection Request were modified constituting a Material Modification \npursuant to Section 4.4 of the GIP, (7) a ZGIA with an effective date prior to this \nZGIA is terminated, (8) when ordered to restudy by FERC, or (9) the Network \nUpgrade Facilities Study for a Network Upgrade, which is to be included in this \nZGIA, is completed after execution of this ZGIA.  The higher queued \nInterconnection Requests that could impact the Network Upgrades, System \nProtection Facilities and Distribution Upgrades required to accommodate the \nGenerating Facility, and possible Modifications that may result from the above \nlisted events affecting the higher queued Interconnection Requests, to the extent \nsuch modifications are reasonably known and can be determined, and estimates of \nthe costs associated with such required Network Upgrades, System Protection \nFacilities and Distribution Upgrades, are provided in Appendix A.   \n \n11.3.2 Agreement to Restudy and Cost Reallocation.  In the event that one of the \ncontingencies listed in Article 11.3.1 occurs, at any time before the Network \nUpgrades, Common Use Upgrades, Shared Network Upgrades, System Protection \nFacilities and/or Distribution Upgrades associated with higher queued"},{"page":492,"startToken":139972,"endToken":140311,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nInterconnection Requests with ZGIA in effect prior to this ZGIA are completed, \nTransmission Provider may determine, in its discretion, that a restudy is required.  \nIf a restudy is required, Transmission Provider will provide notice to \nInterconnection Customer and Interconnection Customer agrees to enter into an \nInterconnection Study Agreement for such restudy.  Transmission Provider will \nreevaluate the need for any Common Use Upgrade(s) and/or Shared Network \nUpgrade(s), and if still required, reallocate the cost and responsibility for any \nCommon Use Upgrade and/or Shared Network Upgrade, without a restudy when \npossible, or with a restudy if the Transmission Provider deems it necessary in \norder to ensure reliability of the Transmission System.  The Parties agree to \namend Appendix A to this ZGIA in accordance with Article 30.10 to reflect the \nresults of any cost reallocation required under this Article 11.3.2.   \n \n11.3.3 Agreement to Fund Shared Network Upgrades.  Interconnection Customer \nagrees to fund Shared Network Upgrades, as determined by Transmission \nProvider.  Where applicable, payments to fund Shared Network Upgrade(s) that \nare made to Transmission Provider by Interconnection Customer will be disbursed \nby Transmission Provider to the appropriate entities that funded the Shared \nNetwork Upgrades in accordance with Attachment X and Attachment FF of the \nTariff.  In the event that Interconnection Customer fails to meet its obligation to \nfund Shared Network Upgrades, Transmission Owner and Transmission Provider \nshall not be responsible for the Interconnection Customer’s funding obligation.   \n \n11.4 \nTransmission Credits.   \n \n11.4.1 \nRepayment of Amounts Advanced for Network Upgrades.  Interconnection \nCustomer shall be entitled to a cash repayment by Transmission Owner(s)  and \nthe Affected System Owner(s) that own the Network Upgrades, of the amount \npaid respectively to Transmission Owner and Affected System Operator, if any, \nfor the Network Upgrades, as provided under Attachment FF of this Tariff and \nincluding any tax gross-up or other tax-related payments associated with the"},{"page":493,"startToken":140311,"endToken":140655,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nrepayable portion of the Network Upgrades, and not repaid to Interconnection \nCustomer pursuant to Article 5.17.8 or otherwise, to be paid to Interconnection \nCustomer on a dollar-for-dollar basis for the non-usage sensitive portion of \ntransmission charges, as payments are made under the Tariff and Affected \nSystem’s Tariff for Transmission Services with respect to the Generating \nFacility.  Any repayment shall include interest calculated in accordance with the \nmethodology set forth in FERC’s regulations at 18 C.F.R. § 35.19 (a)(2)(iii) \nfrom the date of any payment for Network Upgrades through the date on which \nInterconnection Customer receives a repayment of such payment pursuant to \nthis subparagraph.  Interest shall not accrue during periods in which \nInterconnection Customer has suspended construction pursuant to Article 11 or \nthe Network Upgrades have been determined not to be needed pursuant to this \nArticle 11.4.1.  Interconnection Customer may assign such repayment rights to \nany person.   \n \nIf the Generating Facility is designated a Network Resource under the Tariff, or \nif there are otherwise no incremental payments for Transmission Service \nresulting from the use of the Generating Facility by Transmission Customer, and \nin the absence of another mutually agreeable payment schedule any repayments \nprovided under Attachment FF shall be established equal to the applicable rate \nfor Firm Point-To-Point Transmission Service for the pricing zone where the \nNetwork Load is located multiplied by the portion of the demonstrated output of \nthe Generating Facility designated as a Network Resource by the Network \nCustomer(s) or in the absence of such designation, equal to the monthly firm \nsingle system-wide rate defined under Schedule 7 of the Tariff multiplied by the \nportion of the demonstrated output of the Generating Facility under contract to \nNetwork Customer(s) and consistent with studies pursuant to Section 3.2.2.2 of \nthe GIP. \n \nNotwithstanding the foregoing, as applicable and consistent with the provisions \nof Attachment FF of this Tariff, Interconnection Customer, Transmission"},{"page":494,"startToken":140655,"endToken":140989,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nProvider, Transmission Owner, and Affected System Operator may adopt any \nalternative payment schedule that is mutually agreeable so long as Transmission \nOwner and Affected System Operator take one of the following actions no later \nthan five (5) years from the Commercial Operation Date:  (1) return to \nInterconnection Customer any amounts advanced for Network Upgrades not \npreviously repaid, or (2) declare in writing that Transmission Owner or Affected \nSystem Operator will continue to provide payments to Interconnection \nCustomer on a dollar-for-dollar basis for the non-usage sensitive portion of \ntransmission charges, or develop an alternative schedule that is mutually \nagreeable and provides for the return of all amounts advanced for Network \nUpgrades not previously repaid; however, full reimbursement shall not extend \nbeyond twenty (20) years from the Commercial Operation Date. \n \nIf the Generating Facility is installed in phases, the amount eligible for refund as \neach phase achieves Commercial Operation will be reduced by the proportional \namount of generation capacity not yet installed.  However, all facilities in \nAppendix A other than the Generating Facility shall be built without \nconsideration for the phasing of the Generating Facility as though the entire \nGenerating Facility will be placed in Commercial Operation for the full output \nor increased output of the Generating Facility constructed by Interconnection \nCustomer under this ZGIA. \n \nIf the Generating Facility fails to achieve Commercial Operation, but it or \nanother generating facility is later constructed and makes use of the Network \nUpgrades, Transmission Owner and Affected System Operator shall at that time \nreimburse Interconnection Customer for the remaining applicable amounts that \nmay be refundable pursuant to Attachment FF of this Tariff that were advanced \nfor the Network Upgrades on their respective systems as described above.  \nBefore any such reimbursement can occur, Interconnection Customer, or the \nentity that ultimately constructs the Generating Facility, if different, is \nresponsible for identifying the entity to which the reimbursement must be made."},{"page":495,"startToken":140989,"endToken":141295,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \n11.4.2 \nSpecial Provisions for Transmission Provider as an Affected System to be \ncovered under Separate Agreements.  When the Transmission Owner’s \nTransmission or Distribution System (including for this Article 11.4.2 \nindependent distribution systems connected to the Transmission System) is an \nAffected System for an interconnection in another electric system, Transmission \nProvider will coordinate the performance of Interconnection Studies with the \nother system.  Transmission Provider will determine if any Network Upgrades \nor Distribution Upgrades, which may be required on the Transmission System \nas a result of the interconnection, would not have been needed but for the \ninterconnection.  Unless Transmission Owner provides, under the \ninterconnection agreement between Interconnection Customer and the other \nsystem, for the repayment of amounts advanced to Transmission Provider or an \nimpacted Transmission Owner for Network Upgrades, Interconnection \nCustomer, Transmission Provider, and the impacted  Transmission Owner(s) \nshall enter into an agreement that provides for such repayment by Transmission \nOwner(s) as directed by Transmission Provider.  The agreement shall specify \nthe terms governing payments to be made by Interconnection Customer to the \nAffected System Operator as well as the payment of refunds by the Affected \nSystem Operator. \n \n11.4.3 \nNotwithstanding any other provision of this ZGIA, nothing herein shall be \nconstrued as relinquishing or foreclosing any rights, including but not limited to \nfirm transmission rights, capacity rights, transmission congestion rights, or \ntransmission credits, that Interconnection Customer, shall be entitled to, now or \nin the future under any other agreement or tariff as a result of, or otherwise \nassociated with, the transmission capacity, if any, created by the Network \nUpgrades, including the right to obtain cash reimbursement or transmission \ncredits for transmission service that is not associated with the Generating \nFacility."},{"page":496,"startToken":141295,"endToken":141702,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n11.5 \nInitial Payment.  For upgrades that the Transmission Owner has elected to self-fund, the \nInterconnection Customer is responsible for making the initial payment for the total cost \nof Network Upgrades (excluding JTIQ Upgrades) or Transmission Owner’s System \nProtection Facilities in the form of security pursuant to Article 11.6.  For upgrades where \nthe Transmission Owner did not elect to self-fund, the Interconnection Customer shall \nelect (and provide its election to the Transmission Provider within five days of the \ncommencement of negotiation of the ZGIA pursuant to Section 11.2 of the GIP) to make \neither 1) an initial payment equal to twenty (20) percent of the total cost of Network \nUpgrades (excluding JTIQ Upgrades), Transmission Owner Interconnection Facilities, \nTransmission Owner’s System Protection Facilities, Distribution Upgrades and/or \nGenerator Upgrades (if the In-Service Date is less than or equal to five (5) years of the \ninitial payment date); or 2) an initial payment equal to ten (10) percent of the total cost of \nNetwork Upgrades (excluding JTIQ Upgrades), Transmission Owner Interconnection \nFacilities, Transmission Owner’s System Protection Facilities, Distribution Upgrades \nand/or Generator Upgrades (if the In-Service Date exceeds the initial payment date by \nmore than five (5) years); or 3) the total cost of Network Upgrades (excluding JTIQ \nUpgrades), Transmission Owner Interconnection Facilities, Transmission Owner’s \nSystem Protection Facilities, Distribution Upgrades and/or Generator Upgrades in the \nform of security pursuant to Article 11.6.  The initial payment shall be provided to \nTransmission Owner by Interconnection Customer pursuant to this Article 11.5 within the \nlater of a) forty-five (45) Calendar Days of the execution of the ZGIA by all Parties, or b) \nforty-five (45) Calendar Days of acceptance by FERC if the ZGIA is filed unexecuted \nand the payment is being protested by Interconnection Customer, or c) forty-five (45) \nCalendar Days of the filing if the ZGIA is filed unexecuted and the initial payment is not \nbeing protested by Interconnection Customer.  If the Interconnection Customer made its \nmilestone payments in the form of cash and the Interconnection Customer elects a cash \ninitial payment, then the Transmission Provider shall transfer those funds to the \nTransmission Owner on the Interconnection Customer’s behalf. \n \n11.6 \nProvision of Security.  Unless a milestone cash payment schedule is  provided in \nAppendix B, Interconnection Customer shall, at least forty-five (45) Calendar Days prior"},{"page":497,"startToken":141702,"endToken":142027,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nto the commencement of the design, procurement, installation, or construction of a \ndiscrete portion of a facility, not otherwise funded under Article 11.5, provide additional \nsecurity.  Additionally, the Interconnection Customer will be required to provide security \nmore than forty-five (45) Calendar Days in advance if requested by Transmission Owner \nbecause regulatory approvals are required for the construction of such facilities.  \nInterconnection Customer shall provide Transmission Owner, at Interconnection \nCustomer’s selection, a guarantee, a surety bond, letter of credit or other form of security \nthat is reasonably acceptable to Transmission Owner and is consistent with the Uniform \nCommercial Code of the jurisdiction identified in Article 14.2.1.  Such security for \npayment, as specified in Appendix B of this ZGIA, shall be in an amount sufficient to \ncover the applicable costs and cost commitments, in addition to those funded under \nArticle 11.5,  required of the Party responsible for building the facilities pursuant to the \nconstruction schedule developed in Appendix B for designing, engineering, seeking \nregulatory approval from any Governmental Authority, constructing, procuring and \ninstalling the applicable portion of the Transmission Owner’s Interconnection Facilities, \nTransmission Owner’s System Protection Facilities, Network Upgrades, Distribution \nUpgrades or Stand-Alone Network Upgrades and shall be reduced on a dollar-for-dollar \nbasis for payments made to Transmission Owner for these purposes.  Transmission \nOwner must use the milestone payments required under the GIP before requiring \nInterconnection Customer to submit additional security.  Transmission Owner must \nspecify, in Appendix B of this ZGIA, the dates for which Interconnection Customer must \nprovide additional security for construction of each discrete portion of Transmission \nOwner's Interconnection Facilities, Network Upgrades, or Distribution Upgrades and \nInterconnection Customer must provide such additional security.  \n \n \nIn addition: \n \n11.6.1 \nThe guarantee must be made by an entity that meets the creditworthiness \nrequirements of Transmission Owner, and contain terms and conditions that"},{"page":498,"startToken":142027,"endToken":142344,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nguarantee payment of any amount that may be due from Interconnection \nCustomer, up to an agreed-to maximum amount.  \n \n11.6.2 \nThe letter of credit must be issued by a financial institution reasonably \nacceptable to Transmission Owner and must specify a reasonable expiration \ndate.   \n \n11.6.3 \nThe surety bond must be issued by an insurer reasonably acceptable to \nTransmission Owner and must specify a reasonable expiration date.  \n \n11.6.4 \nIf the Shared Network Upgrade is not in service, Interconnection Customer will \nnot be required to make a payment under Schedule 26-B until the Shared \nNetwork Upgrade is in service, but Interconnection Customer will provide, as \napplicable, an Irrevocable Letter of Credit to fund any Shared Network Upgrade \npursuant to Attachment FF of the Tariff.  The Irrevocable Letter of Credit shall \nbe in an amount sufficient to cover the Interconnection Customer’s share of the \napplicable costs and cost commitments associated with the Shared Network \nUpgrades.  Transmission Provider may periodically adjust the Interconnection \nCustomer’s share of the applicable costs and cost commitment of Shared \nNetwork Upgrades and may require Interconnection Customer to adjust the \namount of the Irrevocable Letter of Credit accordingly.   \n \n11.7 \nInterconnection Customer Compensation.  If Transmission Provider requests or directs \nInterconnection Customer to provide a service pursuant to Article 13.4 of this ZGIA, \nTransmission Provider shall compensate Interconnection Customer in accordance with \nany tariff or rate schedule filed by Transmission Provider and approved by the FERC. \n \n11.8  Provision of Security for JTIQ Upgrades. If the Transmission Provider determines that \nthe Interconnection Request meets the distribution factor and impact criteria specified in \nSection 9.4.2(d)((ii) of Rate Schedule 6 (MISO SPP JOA) and is included in the JTIQ \nParticipation Group, Interconnection Customer shall be required to provide security in"},{"page":499,"startToken":142344,"endToken":142692,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\naccordance with Attachment X, Appendix 18 (MISO JTIQ Commitment Agreement) and \nSPP’s JTIQ Service Agreement. \n \nARTICLE 12.  INVOICE \n \n12.1 \nGeneral.  Each Party shall submit to the other Party, on a monthly basis, invoices of \namounts due, if any, for the preceding month.  Each invoice shall state the month to \nwhich the invoice applies and fully describe the services and equipment provided.  The \nParties may discharge mutual debts and payment obligations due and owing to each other \non the same date through netting, in which case all amounts a Party owes to the other \nParty under this ZGIA, including interest payments or credits, shall be netted so that only \nthe net amount remaining due shall be paid by the owing Party. \n \n12.2 \nFinal Invoice.  Within six (6) months after completion of the construction of the \nTransmission Owner’s Interconnection Facilities, Transmission Owner’s System \nProtection Facilities, Distribution Upgrades and the Network Upgrades, Transmission \nOwner shall provide an invoice of the final cost of the construction of the Transmission \nOwner’s Interconnection Facilities, Transmission Owner’s System Protection Facilities, \nDistribution Upgrades and the Network Upgrades and shall set forth such costs in \nsufficient detail to enable Interconnection Customer to compare the actual costs with the \nestimates and to ascertain deviations, if any, from the cost estimates.  Transmission \nOwner shall refund, with interest (calculated in accordance with 18 C.F.R. Section \n35.19a(a)(2)(iii), to Interconnection Customer any amount by which the actual payment \nby Interconnection Customer for estimated costs exceeds the actual costs of construction \nwithin thirty (30) Calendar Days of the issuance of such final construction invoice.  \n \n12.3 \nPayment.  Invoices shall be rendered to the paying Party at the address specified in \nAppendix F.  The Party receiving the invoice shall pay the invoice within thirty (30) \nCalendar Days of receipt.  All payments shall be made in immediately available funds \npayable to the other Party, or by wire transfer to a bank named and account designated by"},{"page":500,"startToken":142692,"endToken":142996,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nthe invoicing Party.  Payment of invoices by a Party will not constitute a waiver of any \nrights or claims that Party may have under this ZGIA.  \n \n12.4 \nDisputes.  In the event of a billing dispute among the Parties, Transmission Provider \nshall continue to provide Interconnection Service under this ZGIA as long as \nInterconnection Customer:  (i) continues to make all payments not in dispute; and (ii) \npays to Transmission Provider or Transmission Owner or into an independent escrow \naccount the portion of the invoice in dispute, pending resolution of such dispute.  If \nInterconnection Customer fails to meet these two requirements for continuation of \nservice, then Transmission Provider may or, at Transmission Owner’s request upon \nInterconnection Customer’s failure to pay, Transmission Owner, shall provide notice to \nInterconnection Customer of a Default pursuant to Article 17.  Within thirty (30) \nCalendar Days after the resolution of the dispute, the Party that owes money to another \nParty shall pay the amount due with interest calculated in accord with the methodology \nset forth in 18 C.F.R. § 35.19a(a)(2)(iii). \n \nARTICLE 13.  EMERGENCIES \n \n13.1 \nObligations.  Each Party shall comply with the Emergency Condition procedures of \nTransmission Provider,  the Electric Reliability Organization, and Applicable Laws and \nRegulations. \n \n13.2 \nNotice.  Transmission Provider or Transmission Owner shall notify the other Parties \npromptly when it becomes aware of an Emergency Condition that affects the \nTransmission Owner’s Interconnection Facilities or the Transmission or Distribution \nSystem, as applicable, that may reasonably be expected to affect Interconnection \nCustomer’s operation of the Generating Facility or the Interconnection Customer’s \nInterconnection Facilities.   \n \nInterconnection Customer shall notify Transmission Provider and Transmission Owner, \nwhich includes by definition if applicable, the operator of a Distribution System,"},{"page":501,"startToken":142996,"endToken":143295,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\npromptly when it becomes aware of an Emergency Condition that affects the Generating \nFacility or the Interconnection Customer’s Interconnection Facilities that may reasonably \nbe expected to affect the Transmission or Distribution System, as applicable, or the \nTransmission Owner’s Interconnection Facilities.   \n \nTo the extent information is known, the notification shall describe the Emergency \nCondition, the extent of the damage or deficiency, the expected effect on the operation of \nInterconnection Customer’s or Transmission Provider’s or Transmission Owner’s \nfacilities and operations, its anticipated duration and the corrective action taken and/or to \nbe taken.  The initial notice shall be followed as soon as practicable with written notice. \n \n13.3 \nImmediate Action.  Unless, in a Party’s reasonable judgment, immediate action is \nrequired, the Party exercising such judgment shall notify and obtain the consent of the \nother Parties, such consent to not be unreasonably withheld, prior to performing any \nmanual switching operations at the Generating Facility or the Interconnection Customer’s \nInterconnection Facilities in response to an Emergency Condition either declared by \nTransmission Provider or otherwise regarding the Transmission or Distribution System, \nas applicable. \n \n13.4 \nTransmission Provider and Transmission Owner Authority. \n \n13.4.1 \nGeneral.  Transmission Provider or Transmission Owner may take whatever \nactions or inactions with regard to the Transmission System or the Transmission \nOwner’s Interconnection Facilities it deems necessary during an Emergency \nCondition in order to (i) preserve public health and safety, (ii) preserve the \nreliability of the Transmission System or the Transmission Owner’s \nInterconnection Facilities, (iii) limit or prevent damage, and (iv) expedite \nrestoration of service. \n \nTransmission Provider or Transmission Owner shall use Reasonable Efforts to \nminimize the effect of such actions or inactions on the Generating Facility or the"},{"page":502,"startToken":143295,"endToken":143620,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nInterconnection Customer’s Interconnection Facilities.  Transmission Provider \nor Transmission Owner may, on the basis of technical considerations, require \nthe Generating Facility to mitigate an Emergency Condition by taking actions \nnecessary and limited in scope to remedy the Emergency Condition, including, \nbut not limited to, directing Interconnection Customer to shut-down, start-up, \nincrease or decrease the real or reactive power output of the Generating Facility; \nimplementing a reduction or disconnection pursuant to Article 13.4.2; directing \nInterconnection Customer to assist with blackstart (if available) or restoration \nefforts; or altering the outage schedules of the Generating Facility and the \nInterconnection Customer’s Interconnection Facilities.  Interconnection \nCustomer shall comply with all of Transmission Provider’s or Transmission \nOwner’s operating instructions concerning Generating Facility real power and \nreactive power output within the manufacturer’s design limitations of the \nGenerating Facility’s equipment that is in service and physically available for \noperation at the time, in compliance with Applicable Laws and Regulations. \n \n13.4.2 \nReduction and Disconnection.  Transmission Provider or Transmission Owner \nmay reduce Interconnection Service or disconnect the Generating Facility or the \nInterconnection Customer’s Interconnection Facilities, when such reduction or \ndisconnection is necessary under Good Utility Practice due to Emergency \nConditions.  These rights are separate and distinct from any right of curtailment \nof Transmission Provider pursuant to the Tariff.  When Transmission Provider \ncan schedule the reduction or disconnection in advance, Transmission Provider \nshall notify Interconnection Customer of the reasons, timing and expected \nduration of the reduction or disconnection. Transmission Provider shall \ncoordinate with Interconnection Customer and Transmission Owner using Good \nUtility Practice to schedule the reduction or disconnection during periods of \nleast impact to Interconnection Customer, Transmission Owner and \nTransmission Provider.  Any reduction or disconnection shall continue only for \nso long as reasonably necessary pursuant to Good Utility Practice.  The Parties \nshall cooperate with each other to restore the Generating Facility, the"},{"page":503,"startToken":143620,"endToken":143943,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nInterconnection Facilities, and the Transmission System to their normal \noperating state as soon as practicable consistent with Good Utility Practice. \n \n13.5 \nInterconnection Customer Authority.  Consistent with Good Utility Practice and this \nZGIA and the GIP, Interconnection Customer may take whatever actions or inactions \nwith regard to the Generating Facility or the Interconnection Customer’s Interconnection \nFacilities during an Emergency Condition in order to (i) preserve public health and \nsafety, (ii) preserve the reliability of the Generating Facility or the Interconnection \nCustomer’s Interconnection Facilities, (iii) limit or prevent damage, and (iv) expedite \nrestoration of service.  Interconnection Customer shall use Reasonable Efforts to \nminimize the effect of such actions or inactions on the Transmission System and the \nTransmission Owner’s Interconnection Facilities.  Transmission Provider and \nTransmission Owner shall use Reasonable Efforts to assist Interconnection Customer in \nsuch actions.   \n \n13.6 \nLimited Liability.  Except as otherwise provided in Article 11.6 of this ZGIA, no Party \nshall be liable to any other for any action it takes in responding to an Emergency \nCondition so long as such action is made in good faith and is consistent with Good Utility \nPractice. \n \n13.7 Audit.  In accordance with Article 25.3, any Party may audit the performance of another \nParty when that Party declared an Emergency Condition. \n \nARTICLE 14.  REGULATORY REQUIREMENTS AND GOVERNING LAW \n \n14.1 \nRegulatory Requirements.  Each Party’s obligations under this ZGIA shall be subject to \nits receipt of any required approval or certificate from one or more Governmental \nAuthorities in the form and substance satisfactory to the applying Party, or the Party \nmaking any required filings with, or providing notice to, such Governmental Authorities, \nand the expiration of any time period associated therewith.  Each Party shall in good faith \nseek, and if necessary assist the other Party and use its Reasonable Efforts to obtain such"},{"page":504,"startToken":143943,"endToken":144240,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nother approvals.  Nothing in this ZGIA shall require Interconnection Customer to take \nany action that could result in its inability to obtain, or its loss of, status or exemption \nunder the Federal Power Act, the Public Utility Holding Company Act of 2005, as \namended, or the Public Utility Regulatory Policies Act of 1978. \n \n14.2 \nGoverning Law. \n \n14.2.1 \nThe validity, interpretation and performance of this ZGIA and each of its \nprovisions shall be governed by the laws of the state where the Point of \nInterconnection is located, without regard to its conflicts of law principles.  \n \n14.2.2 \nThis ZGIA is subject to all Applicable Laws and Regulations.  \n \n14.2.3 \nEach Party expressly reserves the right to seek changes in, appeal, or otherwise \ncontest any laws, orders, rules, or regulations of a Governmental Authority. \n \nARTICLE 15.  NOTICES \n \n15.1 \nGeneral.  Unless otherwise provided in this ZGIA, any notice, demand or request \nrequired or permitted to be given by any Party to the other Parties and any instrument \nrequired or permitted to be tendered or delivered by a Party in writing to the other Parties \nshall be effective when delivered and may be so given, tendered or delivered, by \nrecognized national courier, or by depositing the same with the United States Postal \nService with postage prepaid, for delivery by certified or registered mail, addressed to the \nParty, or personally delivered to the Party, at the address set out in Appendix F, \nAddresses for Delivery of Notices and Billings. \n \nEither Party may change the notice information in this ZGIA by giving five (5) Business \nDays written notice prior to the effective date of the change."},{"page":505,"startToken":144240,"endToken":144563,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n15.2 \nBillings and Payments.  Billings and payments shall be sent to the addresses set out in \nAppendix F. \n \n15.3 \nAlternative Forms of Notice.  Any notice or request required or permitted to be given by \nany Party to the other and not required by this ZGIA to be given in writing may be so \ngiven by telephone, facsimile or email to the telephone numbers and email addresses set \nout in Appendix F. \n \n15.4 \nOperations and Maintenance Notice.  Each Party shall notify the other Parties in \nwriting of the identity of the person(s) that it designates as the point(s) of contact with \nrespect to the implementation of Articles 9 and 10. \n \nARTICLE 16.  FORCE MAJEURE \n \n16.1 \nForce Majeure.   \n \n16.1.1 \nEconomic hardship is not considered a Force Majeure event. \n \n16.1.2 \nA Party shall not be considered to be in Default with respect to any obligation \nhereunder, (including obligations under Article 4 and 5), other than the \nobligation to pay money when due, if prevented from fulfilling such obligation \nby Force Majeure.  A Party unable to fulfill any obligation hereunder (other than \nan obligation to pay money when due) by reason of Force Majeure shall give \nnotice and the full particulars of such Force Majeure to the other Parties in \nwriting or by telephone as soon as reasonably possible after the occurrence of \nthe cause relied upon.  Telephone, facsimile or email notices given pursuant to \nthis Article shall be confirmed in writing as soon as reasonably possible and \nshall specifically state full particulars of the Force Majeure, the time and date \nwhen the Force Majeure occurred and when the Force Majeure is reasonably \nexpected to cease.  The Party affected shall exercise Reasonable Efforts to \nremove such disability with reasonable dispatch, but shall not be required to"},{"page":506,"startToken":144563,"endToken":144909,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\naccede or agree to any provision not satisfactory to it in order to settle and \nterminate a strike or other labor disturbance. \n \nARTICLE 17.  DEFAULT \n \n17.1 \nDefault \n \n17.1.1 \nGeneral.  No Default shall exist where such failure to discharge an obligation \n(other than the payment of money) is the result of Force Majeure as defined in \nthis ZGIA or the result of an act or omission of another Party.  Upon a Breach, \nthe non-Breaching Party or Parties shall give written notice of such Breach to \nthe Breaching Party with a copy to the other Party if one Party gives notice of \nsuch Breach.  Except as provided in Article 17.1.2, the Breaching Party shall \nhave thirty (30) Calendar Days from receipt of the Breach notice within which \nto cure such Breach; provided however, if such Breach is not capable of cure \nwithin thirty (30) Calendar Days, the Breaching Party shall commence such cure \nwithin thirty (30) Calendar Days after notice and continuously and diligently \ncomplete such cure within ninety (90) Calendar Days from receipt of the Breach \nnotice; and, if cured within such time, the Breach specified in such notice shall \ncease to exist. \n \n17.1.2 \nTermination.  If a Breach is not cured as provided in this Article, or if a Breach \nis not capable of being cured within the period provided for herein, the non-\nBreaching Party or Parties shall terminate this ZGIA, subject to Article 2.3.2 of \nthis ZGIA, by written notice to the Breaching Party, with a copy to the other \nParty if one Party gives notice of termination, and be relieved of any further \nobligation hereunder and, whether or not that Party(ies) terminates this ZGIA, to \nrecover from the Breaching Party all amounts due hereunder, plus all other \ndamages and remedies to which it is (they are) entitled at law or in equity.  The \nprovisions of this Article will survive termination of this ZGIA."},{"page":507,"startToken":144909,"endToken":145278,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n17.1.3 \nCross-Default.  Pursuant to Article 11.3 of this ZGIA, the Parties shall enter into \na Facilities Service Agreement if the Transmission Owner has elected to fund \nthe capital for the Network Upgrades and/or Transmission Owner’s System \nProtection Facilities.  Notwithstanding anything to the contrary contained in this \nZGIA, a breach by Interconnection Customer of any provision, covenant, or \nother term or condition contained in the Facilities Service Agreement shall be \nconsidered a breach under this ZGIA.  Such breach shall be subject to the terms \nof Article 17 of this ZGIA.  If a default under this ZGIA results from the \nInterconnection Customer’s breach of the Facilities Service Agreement and \nsubsequent failure to cure, the Transmission Owner and Transmission Provider \nshall be entitled, but in no event required, to apply all rights and remedies \navailable by reason of default under the Facilities Service Agreement and this \nZGIA. \n \n \nPursuant to Section 11.3 of the GIP, an Interconnection Customer included in a \nJTIQ Participation Group shall execute or request the unexecuted filing both of \nthe Transmission Provider’s JTIQ Commitment Agreement and the JTIQ \nService Agreement included in SPP’s tariff. Notwithstanding anything to the \ncontrary contained in this ZGIA, a breach by Interconnection Customer of any \nprovision, covenant, or other term or condition contained in the JTIQ \nCommitment Agreement or SPP’s JTIQ Service Agreement shall be considered \na breach under this ZGIA.  Such breach shall be subject to the terms of Article \n17 of this ZGIA provided, however, that the manner and timing of cure of such \nbreach shall adhere to the requirements of the applicable agreement and cure in \naccordance with the provisions of such agreement shall also cure the breach of \nthis GI.  If a default under this ZGIA results from the Interconnection \nCustomer’s breach of the JTIQ Commitment Agreement or SPP JTIQ Service \nAgreement and subsequent failure to cure, the Transmission Owner and \nTransmission Provider shall be entitled, but in no event required, to apply all \nrights and remedies available by reason of default under the JTIQ Commitment \nAgreement, SPP JTIQ Service Agreement, and this ZGIA."},{"page":508,"startToken":145278,"endToken":145600,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \n17.2 \nViolation of Operating Assumptions for Generating Facilities.  If Transmission \nProvider requires Interconnection Customer to memorialize the operating assumptions for \nthe charging behavior of the Generating Facility that includes at least one electric storage \nresource in Appendix A of this ZGIA, Transmission Provider may consider \nInterconnection Customer to be in Breach of the ZGIA if Interconnection Customer fails \nto operate the Generating Facility in accordance with those operating assumptions for \ncharging behavior.  However, if Interconnection Customer operates contrary to the \noperating assumptions for charging behavior specified in Appendix A of this ZGIA at the \ndirection of Transmission Provider, Transmission Provider shall not consider \nInterconnection Customer in Breach of this ZGIA.  \n \n \nARTICLE 18.  LIMITATION OF LIABILITY, INDEMNITY, CONSEQUENTIAL \nDAMAGES AND INSURANCE \n \n18.1 \nLimitation of Liability.  A Party shall not be liable to another Party or to any third party \nor other person for any damages arising out of actions under this ZGIA, including, but \nnot limited to, any act or omission that results in an interruption, deficiency or \nimperfection of Interconnection Service, except as provided in this Tariff.  The provisions \nset forth in the Tariff shall be additionally applicable to any Party acting in good faith to \nimplement or comply with its obligations under this ZGIA, regardless of whether the \nobligation is preceded by a specific directive. \n \n18.2 \nIndemnity.  To the extent permitted by law, an Indemnifying Party shall at all times \nindemnify, defend and hold the other Parties harmless from Loss. \n \n18.2.1 \nIndemnified Party.  If an Indemnified Party is entitled to indemnification under \nthis Article 18 as a result of a claim by a non-Party, and the Indemnifying Party \nfails, after notice and reasonable opportunity to proceed under Article 18.2, to \nassume the defense of such claim, such Indemnified Party may at the expense of"},{"page":509,"startToken":145600,"endToken":145940,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nthe Indemnifying Party contest, settle or consent to the entry of any judgment \nwith respect to, or pay in full, such claim. \n \n18.2.2 \nIndemnifying Party.  If an Indemnifying Party is obligated to indemnify and \nhold any Indemnified Party harmless under this Article 18, the amount owing to \nthe Indemnified Party shall be the amount of such Indemnified Party’s actual \nLoss, net of any insurance or other recovery. \n \n18.2.3 \nIndemnity Procedures.  Promptly after receipt by an Indemnified Party of any \nclaim or notice of the commencement of any action or administrative or legal \nproceeding or investigation as to which the indemnity provided for in \nArticle 18.2 may apply, the Indemnified Party shall notify the Indemnifying \nParty of such fact.  Any failure of or delay in such notification shall not affect a \nParty’s indemnification obligation unless such failure or delay is materially \nprejudicial to the Indemnifying Party. \n \nThe Indemnifying Party shall have the right to assume the defense thereof with \ncounsel designated by such Indemnifying Party and reasonably satisfactory to \nthe Indemnified Party.  If the defendants in any such action include one or more \nIndemnified Parties and the Indemnifying Party and if the Indemnified Party \nreasonably concludes that there may be legal defenses available to it and/or \nother Indemnified Parties which are different from or additional to those \navailable to the Indemnifying Party, the Indemnified Party shall have the right to \nselect separate counsel to assert such legal defenses and to otherwise participate \nin the defense of such action on its own behalf.  In such instances, the \nIndemnifying Party shall only be required to pay the fees and expenses of one \nadditional attorney to represent an Indemnified Party or Indemnified Parties \nhaving such differing or additional legal defenses. \n \nThe Indemnified Party shall be entitled, at its expense, to participate in any such \naction, suit or proceeding, the defense of which has been assumed by the"},{"page":510,"startToken":145940,"endToken":146295,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nIndemnifying Party.  Notwithstanding the foregoing, the Indemnifying Party \n(i) shall not be entitled to assume and control the defense of any such action, \nsuit or proceedings if and to the extent that, in the opinion of the Indemnified \nParty and its counsel, such action, suit or proceeding involves the potential \nimposition of criminal liability on the Indemnified Party, or there exists a \nconflict or adversity of interest between the Indemnified Party and the \nIndemnifying Party, in such event the Indemnifying Party shall pay the \nreasonable expenses of the Indemnified Party, and (ii) shall not settle or consent \nto the entry of any judgment in any action, suit or proceeding without the \nconsent of the Indemnified Party, which shall not be reasonably withheld, \nconditioned or delayed. \n \n18.3 Consequential Damages.  Other than the Liquidated Damages heretofore described, in \nno event shall either Party be liable under any provision of this ZGIA for any losses, \ndamages, costs or expenses for any special, indirect, incidental, consequential, or punitive \ndamages, including but not limited to loss of profit or revenue, loss of the use of \nequipment, cost of capital, cost of temporary equipment or services, whether based in \nwhole or in part in contract, in tort, including negligence, strict liability, or any other \ntheory of liability; provided; however, that damages for which a Party may be liable to the \nother Party under another agreement will not be considered to be special, indirect, \nincidental, or consequential damages hereunder. \n \n18.4 \nInsurance.  Transmission Owner and Interconnection Customer shall, at their own \nexpense, maintain in force throughout the period of this ZGIA pursuant to 18.4.9, and \nuntil released by the other Party, the following minimum insurance coverages, with \ninsurers authorized to do business or an approved surplus lines carrier in the state where \nthe Point of Interconnection is located: \n \n18.4.1 \nEmployers’ Liability and Workers’ Compensation Insurance providing statutory \nbenefits in accordance with the laws and regulations of the state in which the \nPoint of Interconnection is located."},{"page":511,"startToken":146295,"endToken":146595,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \n18.4.2 \nCommercial General Liability Insurance including premises and operations, \npersonal injury, broad form property damage, broad form blanket contractual \nliability coverage (including coverage for the contractual indemnification) \nproducts and completed operations coverage, coverage for explosion, collapse \nand underground hazards, independent contractors coverage, coverage for \npollution to the extent normally available and punitive damages to the extent \nnormally available and a cross liability endorsement, with minimum limits of \nOne Million Dollars ($1,000,000) per occurrence/One Million Dollars \n($1,000,000) aggregate  combined single limit for personal injury, bodily injury, \nincluding death and property damage. \n \n18.4.3 \nComprehensive Automobile Liability Insurance, for coverage of owned and \nnon-owned and hired vehicles, trailers or semi-trailers licensed for travel on \npublic roads, with a minimum combined single limit of One Million Dollars \n($1,000,000) each occurrence for bodily injury, including death, and property \ndamage. \n \n18.4.4 \nExcess Public Liability Insurance over and above the Employer’s Liability, \nCommercial General Liability and Comprehensive Automobile Liability \nInsurance coverage, with a minimum combined single limit of Twenty Million \nDollars ($20,000,000) per occurrence/Twenty Million Dollars ($20,000,000) \naggregate for generators not eligible for the Fast Track Process in GIP Section \n14.  The requirement for generators eligible for the Fast Track Process in GIP \nSection 14 is a minimum combined single limit of Five Million Dollars \n($5,000,000) per occurrence/Five Million Dollars ($5,000,000) aggregate.. \n \n18.4.5 \nThe Commercial General Liability Insurance, Comprehensive Automobile \nInsurance and Excess Public Liability Insurance policies shall name the other \nParties, their parents, associated and Affiliate companies and their respective \ndirectors, officers, agents, servants and employees (“Other Party Group”) as"},{"page":512,"startToken":146595,"endToken":146921,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nadditional insured.  All policies shall contain provisions whereby the insurers \nwaive all rights of subrogation in accordance with the provisions of this ZGIA \nagainst the Other Party Groups and provide thirty (30) Calendar Days’ advance \nwritten notice to the Other Party Groups prior to anniversary date of \ncancellation or any material change in coverage or condition. \n \n \n18.4.6 \nThe Commercial General Liability Insurance, Comprehensive Automobile \nLiability Insurance and Excess Public Liability Insurance policies shall contain \nprovisions that specify that the policies are primary and shall apply to such \nextent without consideration for other policies separately carried and shall state \nthat each insured is provided coverage as though a separate policy had been \nissued to each, except the insurer’s liability shall not be increased beyond the \namount for which the insurer would have been liable had only one insured been \ncovered.  Each Party shall be responsible for its respective deductibles or \nretentions. \n \n18.4.7 \nThe Commercial General Liability Insurance, Comprehensive Automobile \nLiability Insurance and Excess Public Liability Insurance policies, if written on \na Claims First Made Basis, shall be maintained in full force and effect for two \n(2) years after termination of this ZGIA, which coverage may be in the form of \ntail coverage or extended reporting period coverage if agreed by Transmission \nOwner and Interconnection Customer. \n \n18.4.8 \nThe requirements contained herein as to the types and limits of all insurance to \nbe maintained by Transmission Owner and Interconnection Customer are not \nintended to and shall not in any manner, limit or qualify the liabilities and \nobligations assumed by Transmission Owner and Interconnection Customer \nunder this ZGIA. \n \n18.4.9 \nAs of the date set forth in Appendix B, Milestones, and as soon as practicable \nafter the end of each fiscal year or at the renewal of the insurance policy and in"},{"page":513,"startToken":146921,"endToken":147251,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nany event within ninety (90) Calendar Days thereafter, Interconnection \nCustomer and Transmission Owner shall provide the other Party with \ncertification of all insurance required in this ZGIA, executed by each insurer or \nby an authorized representative of each insurer.   \n \n18.4.10  Notwithstanding the foregoing, Transmission Owner or Interconnection \nCustomer may self-insure to meet the minimum insurance requirements of \nArticles 18.4.1 through 18.4.8, to the extent it maintains a self-insurance \nprogram; provided that, Transmission Owner’s or Interconnection Customer’s \nsenior secured debt is rated at investment grade, or better, by Standard & Poor’s \nand that its self-insurance program meets minimum insurance requirements \nunder Articles 18.4.1 through 18.4.8.  For any period of time that a \nTransmission Owner’s or Interconnection Customer’s senior secured debt is \nunrated by Standard & Poor’s or is rated at less than investment grade by \nStandard & Poor’s, such Party shall comply with the insurance requirements \napplicable to it under Articles 18.4.1 through 18.4.9.  In the event that \nTransmission Owner or Interconnection Customer is permitted to self-insure \npursuant to this article, it shall notify the other Party that it meets the \nrequirements to self-insure and that its self-insurance program meets the \nminimum insurance requirements in a manner consistent with that specified in \nArticle 18.4.9. \n \n18.4.11 Transmission Owner and Interconnection Customer agree to report to each other \nin writing as soon as practical all accidents or occurrences resulting in injuries to \nany person, including death, and any property damage arising out of this ZGIA. \n \nARTICLE 19.  ASSIGNMENT \n \n19.1 \nAssignment.  This ZGIA may be assigned by any Party only with the written consent of \nthe other Parties; provided that a Party may assign this ZGIA without the consent of the \nother Parties to any Affiliate of the assigning Party with an equal or greater credit rating"},{"page":514,"startToken":147251,"endToken":147607,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nand with the legal authority and operational ability to satisfy the obligations of the \nassigning Party under this ZGIA; and provided further that Interconnection Customer \nshall have the right to assign this ZGIA, without the consent of either Transmission \nProvider or Transmission Owner, for collateral security purposes to aid in providing \nfinancing for the Generating Facility, provided that Interconnection Customer will \npromptly notify Transmission Provider of any such assignment.  Any financing \narrangement entered into by Interconnection Customer pursuant to this Article will \nprovide that prior to or upon the exercise of the secured party’s, trustee’s or mortgagee’s \nassignment rights pursuant to said arrangement, the secured creditor, the trustee or \nmortgagee will notify Transmission Provider of the  date and particulars of any such \nexercise of assignment right(s), including providing Transmission Provider and \nTransmission Owner with proof that it meets the requirements of Article 11.5 and 18.4.  \nAny attempted assignment that violates this Article is void and ineffective.  Any \nassignment under this ZGIA shall not relieve a Party of its obligations, nor shall a Party’s \nobligations be enlarged, in whole or in part, by reason thereof.  Where required, consent \nto assignment will not be unreasonably withheld, conditioned or delayed. \n \nARTICLE 20.  SEVERABILITY \n \n20.1 \nSeverability.  If any provision in this ZGIA is finally determined to be invalid, void or \nunenforceable by any court or other Governmental Authority having jurisdiction, such \ndetermination shall not invalidate, void or make unenforceable any other provision, \nagreement or covenant of this ZGIA; provided that if Interconnection Customer (or any \nnon-Party, but only if such non-Party is not acting at the direction of either Transmission \nProvider or Transmission Owner) seeks and obtains such a final determination with \nrespect to any provision of the Alternate Option (Article 5.1.2), or the Negotiated Option \n(Article 5.1.4), then none of these provisions shall thereafter have any force or effect and \nthe Parties’ rights and obligations shall be governed solely by the Standard Option \n(Article 5.1.1).  \n \nARTICLE 21.  COMPARABILITY"},{"page":515,"startToken":147607,"endToken":147910,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \n21.1 \nComparability.  The Parties will comply with all applicable comparability and code of \nconduct laws, rules and regulations including such laws, rules and regulations of \nGovernmental Authorities establishing standards of conduct, as amended from time to \ntime. \n \nARTICLE 22.  CONFIDENTIALITY \n \n22.1 \nConfidentiality.  Confidential Information shall include, without limitation, all \ninformation relating to a Party’s technology, research and development, business affairs, \nand pricing, and any information supplied by a Party to another Party prior to the \nexecution of this ZGIA. \n \nInformation is Confidential Information only if it is clearly designated or marked in \nwriting as confidential on the face of the document, or, if the information is conveyed \norally or by inspection, if the Party providing the information orally informs the Party \nreceiving the information that the information is confidential.  The Parties shall maintain \nas confidential any information that is provided and identified by a Party as Critical \nEnergy Infrastructure Information (CEII), as that term is defined in 18 C.F.R. \nSection 388.113(c).  Such confidentiality will be maintained in accordance with this \nArticle 22. \n \nIf requested by the receiving Party, the disclosing Party shall provide in writing, the basis \nfor asserting that the information referred to in this Article warrants confidential \ntreatment, and the requesting Party may disclose such writing to the appropriate \nGovernmental Authority.  Each Party shall be responsible for the costs associated with \naffording confidential treatment to its information. \n \n22.1.1 \nTerm.  During the term of this ZGIA, and for a period of three (3) years after the \nexpiration or termination of this ZGIA, except as otherwise provided in this \nArticle 22 or with regard to CEII, each Party shall hold in confidence and shall"},{"page":516,"startToken":147910,"endToken":148258,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nnot disclose to any person Confidential Information.  CEII shall be treated in \naccordance with Commission policy and regulations. \n \n22.1.2 \nScope.  Confidential Information shall not include information that the receiving \nParty can demonstrate:  (1) is generally available to the public other than as a \nresult of a disclosure by the receiving Party; (2) was in the lawful possession of \nthe receiving Party on a non-confidential basis before receiving it from the \ndisclosing Party; (3) was supplied to the receiving Party without restriction by a \nnon-Party, who, to the knowledge of the receiving Party after due inquiry, was \nunder no obligation to the disclosing Party to keep such information \nconfidential; (4) was independently developed by the receiving Party without \nreference to Confidential Information of the disclosing Party; (5) is, or becomes, \npublicly known, through no wrongful act or omission of the receiving Party or \nBreach of this ZGIA; or (6) is required, in accordance with Article 22.1.7 of this \nZGIA, Order of Disclosure, to be disclosed by any Governmental Authority or \nis otherwise required to be disclosed by law or subpoena, or is necessary in any \nlegal proceeding establishing rights and obligations under this ZGIA.  \nInformation designated as Confidential Information will no longer be deemed \nconfidential if the Party that designated the information as confidential notifies \nthe receiving Party that it no longer is confidential. \n \n22.1.3 \nRelease of Confidential Information.  No Party shall release or disclose \nConfidential Information to any other person, except to its Affiliates (limited by \nthe Standards of Conduct requirements), subcontractors, employees, agents, \nconsultants, or to non-parties who may be or are considering providing \nfinancing to or equity participation with Interconnection Customer, or to \npotential purchasers or assignees of Interconnection Customer, on a need-to-\nknow basis in connection with this ZGIA, unless such person has first been \nadvised of the confidentiality provisions of this Article 22 and has agreed to \ncomply with such provisions.  Notwithstanding the foregoing, a Party providing"},{"page":517,"startToken":148258,"endToken":148591,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nConfidential Information to any person shall remain primarily responsible for \nany release of Confidential Information in contravention of this Article 22. \n \n22.1.4 \nRights.  Each Party retains all rights, title, and interest in the Confidential \nInformation that it discloses to the receiving Party.  The disclosure by a Party to \nthe receiving Party of Confidential Information shall not be deemed a waiver by \nthe disclosing Party or any other person or entity of the right to protect the \nConfidential Information from public disclosure. \n \n22.1.5 \nNo Warranties.  By providing Confidential Information, no Party makes any \nwarranties or representations as to its accuracy or completeness.  In addition, by \nsupplying Confidential Information, no Party obligates itself to provide any \nparticular information or Confidential Information to another Party nor to enter \ninto any further agreements or proceed with any other relationship or joint \nventure. \n \n22.1.6 \nStandard of Care.  Each Party shall use at least the same standard of care to \nprotect Confidential Information it receives as it uses to protect its own \nConfidential Information from unauthorized disclosure, publication or \ndissemination.  Each Party may use Confidential Information solely to fulfill its \nobligations to another Party under this ZGIA or its regulatory requirements. \n \n22.1.7 \nOrder of Disclosure.  If a court or a Governmental Authority or entity with the \nright, power, and apparent authority to do so requests or requires any Party, by \nsubpoena, oral deposition, interrogatories, requests for production of documents, \nadministrative order, or otherwise, to disclose Confidential Information, that \nParty shall provide the disclosing Party with prompt notice of such request(s) or \nrequirement(s) so that the disclosing Party may seek an appropriate protective \norder or waive compliance with the terms of this ZGIA.  Notwithstanding the \nabsence of a protective order or waiver, the Party may disclose such \nConfidential Information which, in the opinion of its counsel, the Party is"},{"page":518,"startToken":148591,"endToken":148953,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nlegally compelled to disclose.  Each Party will use Reasonable Efforts to obtain \nreliable assurance that confidential treatment will be accorded any Confidential \nInformation so furnished. \n \n22.1.8 \nTermination of Agreement.  Upon termination of this ZGIA for any reason, each \nParty shall, within ten (10) Calendar Days of receipt of a written request from \nanother Party, use Reasonable Efforts to destroy, erase, or delete (with such \ndestruction, erasure, and deletion certified in writing to the requesting Party) or \nreturn to the requesting Party, without retaining copies thereof, any and all \nwritten or electronic Confidential Information received from the requesting \nParty, except that each Party may keep one copy for archival purposes, provided \nthat the obligation to treat it as Confidential Information in accordance with this \nArticle 22 shall survive such termination. \n \n22.1.9 \nRemedies.  The Parties agree that monetary damages would be inadequate to \ncompensate a Party for another Party’s Breach of its obligations under this \nArticle 22.  Each Party accordingly agrees that the disclosing Party shall be \nentitled to equitable relief, by way of injunction or otherwise, if the receiving \nParty Breaches or threatens to Breach its obligations under this Article 22, \nwhich equitable relief shall be granted without bond or proof of damages, and \nthe Breaching Party shall not plead in defense that there would be an adequate \nremedy at law.  Such remedy shall not be deemed an exclusive remedy for the \nBreach of this Article 22, but shall be in addition to all other remedies available \nat law or in equity.  The Parties further acknowledge and agree that the \ncovenants contained herein are necessary for the protection of legitimate \nbusiness interests and are reasonable in scope.  No Party, however, shall be \nliable for indirect, incidental, or consequential or punitive damages of any \nnature or kind resulting from or arising in connection with this Article 22. \n \n22.1.10  Disclosure to FERC, its Staff or a State.  Notwithstanding anything in this \nArticle 22 to the contrary, and pursuant to 18 CFR § 1b.20, if FERC or its staff,"},{"page":519,"startToken":148953,"endToken":149349,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nduring the course of an investigation or otherwise, requests information from a \nParty that is otherwise required to be maintained in confidence pursuant to this \nZGIA, the Party shall provide the requested information to FERC or its staff, \nwithin the time provided for in the request for information.  In providing the \ninformation to FERC or its staff, the Party must, consistent with 18 CFR \n§ 388.112, request that the information be treated as confidential and non-public \nby FERC and its staff and that the information be withheld from public \ndisclosure.  Parties are prohibited from notifying the other Parties to this ZGIA \nprior to the release of the Confidential Information to FERC or its staff.  The \nParty shall notify the other Parties to this ZGIA when it is notified by FERC or \nits staff that a request to release Confidential Information has been received by \nFERC, at which time any of the Parties may respond before such information \nwould be made public, pursuant to 18 CFR § 388.112.  Requests from a state \nregulatory body conducting a confidential investigation shall be treated in a \nsimilar manner if consistent with the applicable state rules and regulations.  \n \n22.1.11 Subject to the exception in Article 22.1.10, any information that a disclosing \nParty claims is competitively sensitive, commercial or financial information \nunder this ZGIA shall not be disclosed by the receiving Party to any person not \nemployed or retained by the receiving Party, except to the extent disclosure is (i) \nrequired by law; (ii) reasonably deemed by the receiving Party to be required to \nbe disclosed in connection with a dispute between or among the Parties, or the \ndefense of litigation or dispute; (iii) otherwise permitted by consent of the \ndisclosing Party, such consent not to be unreasonably withheld; or (iv) \nnecessary to fulfill its obligations under this ZGIA or as the Regional \nTransmission Organization or a Local Balancing Authority operator including \ndisclosing the Confidential Information to a regional or national reliability \norganization.  The Party asserting confidentiality shall notify the receiving Party \nin writing of the information that Party claims is confidential.  Prior to any \ndisclosures of that Party’s Confidential Information under this subparagraph, or \nif any non-Party or Governmental Authority makes any request or demand for"},{"page":520,"startToken":149349,"endToken":149641,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nany of the information described in this subparagraph, the Party who received \nthe Confidential Information from the disclosing Party agrees to promptly notify \nthe disclosing Party in writing and agrees to assert confidentiality and cooperate \nwith the disclosing Party in seeking to protect the Confidential Information from \npublic disclosure by confidentiality agreement, protective order or other \nreasonable measures. \n \nARTICLE 23.  ENVIRONMENTAL RELEASES \n \n23.1 \nEach Party shall notify the other Parties, first orally and then in writing, of the release of \nany Hazardous Substances, any asbestos or lead abatement activities, or any type of \nremediation activities related to the Generating Facility or the Interconnection Facilities, \neach of which may reasonably be expected to affect another Party.  The notifying Party \nshall:  (i) provide the notice as soon as practicable, provided such Party makes a good \nfaith effort to provide the notice no later than twenty-four hours after such Party becomes \naware of the occurrence; and (ii) promptly furnish to the other Parties copies of any \npublicly available reports filed with any Governmental Authorities addressing such \nevents. \n \nARTICLE 24.  INFORMATION REQUIREMENTS \n \n24.1 \nInformation Acquisition.  Transmission Provider, Transmission Owner and \nInterconnection Customer shall submit specific information regarding the electrical \ncharacteristics of their respective facilities to each other as described below and in \naccordance with Applicable Reliability Standards. \n \n24.2 \nInformation Submission by Transmission Provider and Transmission Owner   The \ninitial information submission by Transmission Provider to Interconnection Customer, \nwith copy provided to Transmission Owner, shall occur no later than one hundred eighty \n(180) Calendar Days prior to Trial Operation and shall include Transmission or \nDistribution System information, as applicable and available, necessary to allow"},{"page":521,"startToken":149641,"endToken":149969,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nInterconnection Customer to select equipment and meet any system protection and \nstability requirements, unless otherwise mutually agreed to by the Parties.  On a monthly \nbasis, Transmission Owner shall provide Interconnection Customer a status report on the \nconstruction and installation of Transmission Owner’s Interconnection Facilities, \nTransmission Owner’s System Protection Facilities, Distribution Upgrades and Network \nUpgrades, including, but not limited to, the following information: (1) progress to date; \n(2) a description of the activities since the last report (3) a description of the action items \nfor the next period; and (4) the delivery status of equipment ordered. \n \n24.3 \nUpdated Information Submission by Interconnection Customer.  The updated \ninformation submission by Interconnection Customer to Transmission Provider, with \ncopy to Transmission Owner, including manufacturer information, shall occur no later \nthan one hundred eighty (180) Calendar Days prior to the Trial Operation.  \nInterconnection Customer shall submit to Transmission Provider and Transmission \nOwner a completed copy of the Generating Facility data requirements contained in \nAppendix 1 to the GIP.  It shall also include any additional information provided to \nTransmission Provider for the Interconnection Facilities Study.  Information in this \nsubmission shall be the most current Generating Facility design or expected performance \ndata.  Information submitted for stability models shall be compatible with Transmission \nProvider standard models.  If there is no compatible model, Interconnection Customer \nwill work with a consultant mutually agreed to by Transmission Provider and \nInterconnection Customer to develop and supply a standard model and associated \ninformation. \n \nIf the Interconnection Customer’s data is materially different from what was originally \nprovided to Transmission Provider pursuant to the Interconnection Study Agreement \nbetween Transmission Provider and Interconnection Customer, then Transmission \nProvider will conduct appropriate studies to determine the impact on the Transmission \nSystem based on the actual data submitted pursuant to this Article 24.3.  Interconnection \nCustomer shall not begin Trial Operation until such studies are completed."},{"page":522,"startToken":149969,"endToken":150307,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n24.4 \nInformation Supplementation.  Prior to the Commercial Operation Date, the Parties \nshall supplement their information submissions described above in this Article 24 with \nany and all “as-built” Generating Facility information or “as-tested” performance \ninformation that differs from the initial submissions or, alternatively, written \nconfirmation that no such differences exist.  Interconnection Customer shall conduct tests \non the Generating Facility as required by Good Utility Practice, such as an open circuit \n“step voltage” test on the Generating Facility to verify proper operation of the Generating \nFacility’s automatic voltage regulator.   \n \nUnless otherwise agreed, the test conditions shall include:  (1) Generating Facility at \nsynchronous speed; (2) automatic voltage regulator on and in voltage control mode; and \n(3) a five percent (5 %) change in Generating Facility terminal voltage initiated by a \nchange in the voltage regulators reference voltage.  Interconnection Customer shall \nprovide validated test recordings showing the responses in Generating Facility terminal \nand field voltages.  In the event that direct recordings of these voltages is impractical, \nrecordings of other voltages or currents that mirror the response of the Generating \nFacility’s terminal or field voltage are acceptable if information necessary to translate \nthese alternate quantities to actual Generating Facility terminal or field voltages is \nprovided.  Generating Facility testing shall be conducted and results provided to \nTransmission Provider and Transmission Owner for each individual generating unit in a \nstation.  \n \nSubsequent to the Commercial Operation Date, Interconnection Customer shall provide \nTransmission Provider and Transmission Owner any information changes due to \nequipment replacement, repair, or adjustment.  Transmission Owner shall provide \nInterconnection Customer, with copy to Transmission Provider, any information changes \ndue to equipment replacement, repair or adjustment in the directly connected substation \nor any adjacent Transmission Owner substation that may affect the Interconnection \nCustomer’s Interconnection Facilities equipment ratings, protection or operating \nrequirements.  The Parties shall provide such information no later than thirty (30) \nCalendar Days after the date of the equipment replacement, repair or adjustment."},{"page":523,"startToken":150307,"endToken":150688,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \nARTICLE 25.  INFORMATION ACCESS AND AUDIT RIGHTS \n \n25.1 \nInformation Access.  Each Party (the “disclosing Party”) shall make available to the \nother Parties information that is in the possession of the disclosing Party and is necessary \nin order for the other Parties to:  (i) verify the costs incurred by the disclosing Party for \nwhich another Party is responsible under this ZGIA; and (ii) carry out its obligations and \nresponsibilities under this ZGIA.  The Parties shall not use such information for purposes \nother than those set forth in this Article 25.1 and to enforce their rights under this ZGIA. \n \n25.2 \nReporting of Non-Force Majeure Events.  A Party (the “notifying Party”) shall notify \nthe other Parties when the notifying Party becomes aware of its inability to comply with \nthe provisions of this ZGIA for a reason other than a Force Majeure event.  The Parties \nagree to cooperate with each other and provide necessary information regarding such \ninability to comply, including the date, duration, reason for the inability to comply, and \ncorrective actions taken or planned to be taken with respect to such inability to comply.  \nNotwithstanding the foregoing, notification, cooperation or information provided under \nthis Article shall not entitle any Party receiving such notification to allege a cause for \nanticipatory breach of this ZGIA.  \n \n25.3 \nAudit Rights.  Subject to the requirements of confidentiality under Article 22 of this \nZGIA, each Party shall have the right, during normal business hours, and upon prior \nreasonable notice to the other Parties, to audit at its own expense the other Parties’ \naccounts and records pertaining to the Parties’ performance or the Parties’ satisfaction of \nobligations under this ZGIA.  Such audit rights shall include audits of the other Parties’ \ncosts, calculation of invoiced amounts, the Transmission Provider’s efforts to allocate \nresponsibility for the provision of reactive support to the Transmission or Distribution \nSystem, as applicable, the Transmission Provider’s efforts to allocate responsibility for \ninterruption or reduction of generation, and each Party’s actions in an Emergency \nCondition.  Any audit authorized by this Article shall be performed at the offices where \nsuch accounts and records are maintained and shall be limited to those portions of such"},{"page":524,"startToken":150688,"endToken":150975,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\naccounts and records that relate to each Party’s performance and satisfaction of \nobligations under this ZGIA.  Each Party shall keep such accounts and records for a \nperiod equivalent to the audit rights periods described in Article 25.4.  \n \n25.4 \nAudit Rights Periods. \n \n25.4.1 \nAudit Rights Period for Construction-Related Accounts and Records.  \nAccounts and records related to the design, engineering, procurement, and \nconstruction of the Transmission Owner’s Interconnection Facilities, \nTransmission Owner’s System Protection Facilities, Distribution Upgrades and \nNetwork Upgrades shall be subject to audit for a period of twenty-four months \nfollowing Transmission Owner’s issuance of a final invoice in accordance with \nArticle 12.2. \n \n25.4.2 \nAudit Rights Period for All Other Accounts and Records.  Accounts and \nrecords related to a Party’s performance or satisfaction of all obligations under \nthis ZGIA other than those described in Article 25.4.1 shall be subject to audit \nas follows:  (i) for an audit relating to cost obligations, the applicable audit \nrights period shall be twenty-four (24) months after the auditing Party’s receipt \nof an invoice giving rise to such cost obligations; and (ii) for an audit relating to \nall other obligations, the applicable audit rights period shall be twenty-four (24) \nmonths after the event for which the audit is sought.   \n \n25.5 \nAudit Results.  If an audit by a Party determines that an overpayment or an \nunderpayment has occurred, a notice of such overpayment or underpayment shall be \ngiven to the Party or from whom the overpayment or underpayment is owed together with \nthose records from the audit which support such determination.   \n \nARTICLE 26.  SUBCONTRACTORS"},{"page":525,"startToken":150975,"endToken":151332,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n26.1 \nGeneral.  Nothing in this ZGIA shall prevent a Party from utilizing the services of any \nsubcontractor as it deems appropriate to perform its obligations under this ZGIA; \nprovided, however, that each Party shall require its subcontractors to comply with all \napplicable terms and conditions of this ZGIA in providing such services and each Party \nshall remain primarily liable to the other Parties for the performance of such \nsubcontractor. \n \n26.2 \nResponsibility of Principal.  The creation of any subcontract relationship shall not \nrelieve the hiring Party of any of its obligations under this ZGIA.  The hiring Party shall \nbe fully responsible to the other Parties for the acts or omissions of any subcontractor the \nhiring Party hires as if no subcontract had been made; provided, however, that in no event \nshall Transmission Provider or Transmission Owner be liable for the actions or inactions \nof Interconnection Customer or its subcontractors with respect to obligations of \nInterconnection Customer under Article 5 of this ZGIA.  Any applicable obligation \nimposed by this ZGIA upon the hiring Party shall be equally binding upon, and shall be \nconstrued as having application to, any subcontractor of such Party. \n \n26.3 \nNo Limitation by Insurance.  The obligations under this Article 26 will not be limited in \nany way by any limitation of subcontractor’s insurance. \n \nARTICLE 27.  DISPUTES \n \n27.1 \nSubmission.  In the event any Party has a dispute, or asserts a claim, that arises out of or \nin connection with this ZGIA or its performance, such Party (the “disputing Party”) shall \nprovide the other Parties with written notice of the dispute or claim (“Notice of \nDispute”).  Such dispute or claim shall be referred to a designated senior representative of \neach Party for resolution on an informal basis as promptly as practicable after receipt of \nthe Notice of Dispute by the non-disputing Parties.  In the event the designated \nrepresentatives are unable to resolve the claim or dispute through unassisted or assisted \nnegotiations within thirty (30) Calendar Days of the non-disputing Parties’ receipt of the"},{"page":526,"startToken":151332,"endToken":151654,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nNotice of Dispute, such claim or dispute shall be submitted for resolution in accordance \nwith the dispute resolution procedures of the Tariff. \n \nARTICLE 28.  REPRESENTATIONS, WARRANTIES AND COVENANTS \n \n28.1 \nGeneral.  Each Party makes the following representations, warranties and covenants:  \n \n28.1.1 \nGood Standing.  Such Party is duly organized, validly existing and in good \nstanding under the laws of the state in which it is organized, formed, or \nincorporated, as applicable; that it is qualified to do business in the state or \nstates in which the Generating Facility, Interconnection Facilities and Network \nUpgrades owned by such Party, as applicable, are located; and that it has the \ncorporate power and authority to own its properties, to carry on its business as \nnow being conducted and to enter into this ZGIA and carry out the transactions \ncontemplated hereby and perform and carry out all covenants and obligations on \nits part to be performed under and pursuant to this ZGIA.  \n \n28.1.2 \nAuthority.  Such Party has the right, power and authority to enter into this \nZGIA, to become a Party hereto and to perform its obligations hereunder.  This \nZGIA is a legal, valid and binding obligation of such Party, enforceable against \nsuch Party in accordance with its terms, except as the enforceability thereof may \nbe limited by applicable bankruptcy, insolvency, reorganization or other similar \nlaws affecting creditors’ rights generally and by general equitable principles \n(regardless of whether enforceability is sought in a proceeding in equity or at \nlaw). \n \n28.1.3 \nNo Conflict.  The execution, delivery and performance of this ZGIA does not \nviolate or conflict with the organizational or formation documents, or bylaws or \noperating agreement, of such Party, or any judgment, license, permit, order, \nmaterial agreement or instrument applicable to or binding upon such Party or \nany of its assets."},{"page":527,"startToken":151654,"endToken":151963,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \n28.1.4 \nConsent and Approval.  Such Party has sought or obtained, or, in accordance \nwith this ZGIA will seek or obtain, each consent, approval, authorization, order, \nor acceptance by any Governmental Authority in connection with the execution, \ndelivery and performance of this ZGIA, and it will provide to any Governmental \nAuthority notice of any actions under this ZGIA that are required by Applicable \nLaws and Regulations. \n \nARTICLE 29.  {RESERVED} \n \nARTICLE 30.  MISCELLANEOUS \n \n30.1 \nBinding Effect.  This ZGIA and the rights and obligations hereof, shall be binding upon \nand shall inure to the benefit of the successors and assigns of the Parties hereto. \n \n30.1.1 Reversion.  If offered pursuant to an Agency Agreement under which this ZGIA \nis executed by Transmission Provider as agent for the relevant Transmission \nOwner, in the event that the relevant Agency Agreement terminates, any HVDC \nService offered by Transmission Provider under this ZGIA shall revert to the \nrelevant Transmission Owner and Transmission Provider shall be released from \nall obligations and responsibilities under this ZGIA. \n \n30.2 \nConflicts.  In the event of a conflict between the body of this ZGIA and any attachment, \nappendices or exhibits hereto, the terms and provisions of the body of this ZGIA shall \nprevail and be deemed the final intent of the Parties.   \n \n30.3 \nRules of Interpretation.  This ZGIA, unless a clear contrary intention appears, shall be \nconstrued and interpreted as follows:  (1) the singular number includes the plural number \nand vice versa; (2) reference to any person includes such person’s successors and assigns \nbut, in the case of a Party, only if such successors and assigns are permitted by this \nZGIA, and reference to a person in a particular capacity excludes such person in any"},{"page":528,"startToken":151963,"endToken":152330,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nother capacity or individually; (3) reference to any agreement (including this ZGIA), \ndocument, instrument or tariff means such agreement, document, instrument, or tariff as \namended or modified and in effect from time to time in accordance with the terms thereof \nand, if applicable, the terms hereof; (4) reference to any Applicable Laws and \nRegulations means such Applicable Laws and Regulations as amended, modified, \ncodified, or reenacted, in whole or in part, and in effect from time to time, including, if \napplicable, rules and regulations promulgated thereunder; (5) unless expressly stated \notherwise, reference to any Article, Section or Appendix means such Article of this ZGIA \nor such Appendix to this ZGIA, or such Section to the GIP or such Appendix to the GIP, \nas the case may be; (6) “hereunder”, “hereof”, “herein”, “hereto” and words of similar \nimport shall be deemed references to this ZGIA as a whole and not to any particular \nArticle or other provision hereof or thereof; (7) “including” (and with correlative \nmeaning “include”) means including without limiting the generality of any description \npreceding such term; and (8) relative to the determination of any period of time, “from” \nmeans “from and including”, “to” means “to but excluding” and “through” means \n“through and including.” \n \n30.4 \nEntire Agreement.  This ZGIA, including all Appendices and attachments hereto, \nconstitutes the entire agreement between the Parties with reference to the subject matter \nhereof, and supersedes all prior and contemporaneous understandings or agreements, oral \nor written, between the Parties with respect to the subject matter of this ZGIA.  There are \nno other agreements, representations, warranties, or covenants, which constitute any part \nof the consideration for, or any condition to, any Party’s compliance with its obligations \nunder this ZGIA. \n \n30.5 \nNo Third Party Beneficiaries.  This ZGIA is not intended to and does not create rights, \nremedies, or benefits of any character whatsoever in favor of any persons, corporations, \nassociations, or entities other than the Parties, and the obligations herein assumed are \nsolely for the use and benefit of the Parties, their successors in interest and, where \npermitted, their assigns."},{"page":529,"startToken":152330,"endToken":152668,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n30.6 \nWaiver.  The failure of a Party to this ZGIA to insist, on any occasion, upon strict \nperformance of any provision of this ZGIA will not be considered a waiver of any \nobligation, right, or duty of, or imposed upon, such Party.  \n \nAny waiver at any time by any Party of its rights with respect to this ZGIA shall not be \ndeemed a continuing waiver or a waiver with respect to any other failure to comply with \nany other obligation, right, duty of this ZGIA.  Termination or Default of this ZGIA for \nany reason by Interconnection Customer shall not constitute a waiver of the \nInterconnection Customer’s legal rights to obtain Interconnection Service from \nTransmission Provider.  Any waiver of this ZGIA shall, if requested, be provided in \nwriting. \n \n30.7 \nHeadings.  The descriptive headings of the various Articles of this ZGIA have been \ninserted for convenience of reference only and are of no significance in the interpretation \nor construction of this ZGIA.   \n \n30.8 \nMultiple Counterparts.  This ZGIA may be executed in two or more counterparts, each \nof which is deemed an original but all constitute one and the same instrument.  \n \n30.9 \nAmendment. The Parties may by mutual agreement amend this ZGIA by a written \ninstrument duly executed by all of the Parties. \n \n30.10 Modification by the Parties.  The Parties may by mutual agreement amend the \nAppendices to this ZGIA by a written instrument duly executed by all of the Parties.  \nSuch amendment shall become effective and a part of this ZGIA upon satisfaction of all \nApplicable Laws and Regulations. \n \n30.11 Reservation of Rights. Transmission Provider shall have the right to make a unilateral \nfiling with FERC to modify this ZGIA with respect to any rates, terms and conditions, \ncharges, classifications of service, rule or regulation under Section 205 or any other \napplicable provision of the Federal Power Act and FERC’s rules and regulations"},{"page":530,"startToken":152668,"endToken":152882,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nthereunder, and Transmission Owner and Interconnection Customer shall have the right \nto make a unilateral filing with FERC to modify this ZGIA pursuant to Section 206 or \nany other applicable provision of the Federal Power Act and FERC’s rules and \nregulations thereunder; provided that each Party shall have the right to protest any such \nfiling and to participate fully in any proceeding before FERC in which such \nmodifications may be considered.  Nothing in this ZGIA shall limit the rights of the \nParties or of FERC under Sections 205 or 206 of the Federal Power Act and FERC’s \nrules and regulations thereunder, except to the extent that the Parties otherwise mutually \nagree as provided herein.  \n \n30.12 No Partnership.  This ZGIA shall not be interpreted or construed to create an \nassociation, joint venture, agency relationship, or partnership among or between the \nParties or to impose any partnership obligation or partnership liability upon any Party.  \nNo Party shall have any right, power or authority to enter into any agreement or \nundertaking for, or act on behalf of, or to act as or be an agent or representative of, or to \notherwise bind, the other Parties."},{"page":531,"startToken":152882,"endToken":152960,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nIN WITNESS WHEREOF, the Parties have executed this ZGIA in multiple originals; \neach of which shall constitute and be an original ZGIA among the Parties. \n \n \nTransmission Provider \nMidcontinent Independent System Operator, Inc. \n \nBy:  \n \n \n \n \n \n \n \nName:  \n \n \n \n \n \n \nTitle:  \n \n \n \n \n \n \n \n \nTransmission Owner \n[Insert name of Transmission Owner] \n \nBy:  \n \n \n \n \n \n \n \nName:  \n \n \n \n \n \n \nTitle:  \n \n \n \n \n \n \n \n \nInterconnection Customer \n[Insert name of Interconnection Customer] \n \nBy:  \n \n \n \n \n \n \n \nName:  \n \n \n \n \n \n \nTitle:  \n \n \n \n \n \n \n \nProject No. _____"},{"page":532,"startToken":152960,"endToken":153054,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nAPPENDICES TO ZGIA \n \nAppendix A Interconnection Facilities,  System Protection Facilities, Distribution \nUpgrades, Generator Upgrades and Network Upgrades \nAppendix B Milestones \nAppendix B-1 Pre-Certification Generation Test Notification Form \nAppendix C Interconnection Details \nAppendix D Security Arrangements Details \nAppendix E Commercial Operation Date \nAppendix F Addresses for Delivery of Notices and Billings \nAppendix G Interconnection Requirements for Inverter-Based Resource Plants \nAppendix H Interconnection Requirements for Provisional ZGIA \nAppendix I \nRequirements Applicable to Surplus Interconnection Service"},{"page":533,"startToken":153054,"endToken":153329,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nAppendix A to ZGIA \n \nInterconnection Facilities, System Protection Facilities, Distribution Upgrades, Generator \nUpgrades and Network Upgrades \n \n1. \nDescription of Generating Facility \n \n \nInterconnection Customer shall install a [_____________] MVA facility, rated at [____] \nMW gross and [_____] MW net, with all studies performed at or below these outputs.  The \nGenerating Facility is composed of [__] units in a [insert description – combined cycle, single \ncoal-fired, wind farm, etc.] rated at [________] each.  Describe the interconnection service \nprovided under this agreement [insert description – Network Resource or Energy Resource] and \nlevel of service [     ] MW.  [Insert operating assumptions that reflect the charging behavior of \nthe Generating Facility that includes at least one electric storage resource] \n \n \nInterconnection Customer shall install a switchyard with the appropriate protection \nequipment coordinated per Appendix C to this ZGIA.  The Switchyard shall contain [____] \ngenerator step-up transformer(s), [_______] circuit breakers connected in [_______] fashion \n[describe or point to a single-line diagram]. \n \n2. \nDescription of ZG Associated Load and Injection Limiting Equipment \n \nThis ZG Interconnection Service is provided to serve ___ MWs with a Point of \nWithdrawal ___ with a Commercial Operations need-by-date of _________.  The equipment \nand/or configuration that prevent the Generating Facility from injecting Energy onto the \nTransmission System beyond the substation identified as the Point of Interconnection (other than \ntransient, limited injections associated with a reduction or loss of Load by the ZG Associated \nLoad within the Transient Tolerance Window are described below.   \n[describe and include a single-line diagram illustrating the connections between the \nGenerating Facility, ZG Associated Load, and the Transmissions System and identifying \nall relevant equipment utilized to limit injections]"},{"page":534,"startToken":153329,"endToken":153529,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \n3. \nInterconnection Facilities \n \n(a) \nPoint of Interconnection.  The Point of Interconnection shall be at the point \nwhere _____________________________________________.  See Exhibit \nA1___ Drawing No. _____________ dated _____________, which drawing is \nattached hereto and made a part hereof.  If not located at the Point of \nInterconnection, the metering point(s) shall be located at \n \n(b) \nInterconnection Facilities (including metering equipment) to be constructed \nby Interconnection Customer.  Interconnection Customer shall construct \n_________________________ and are detailed in Exhibit A1____.  These \nfacilities are estimated to cost $_______ and are detailed in Exhibit A1____. \n \n(c) \nTransmission Owner Interconnection Facilities (including metering \nequipment) to be constructed by Transmission Owner.  Transmission Owner \nshall construct _____________________and are detailed in Exhibit A1___.  \nThese facilities are estimated to cost $_______ and are detailed in Exhibit A1___. \n \n4. \nNetwork Upgrades \n \n(a) \nStand-Alone Network Upgrades to be installed by ____________________.  \nTransmission Owner shall install _______________________, detailed in Exhibit \nA2___.  These facilities are estimated to cost $_____________ and are detailed in \nExhibit A2___. \n \n(b) \nNetwork Upgrades to be installed by Transmission Owner.  Transmission \nOwner shall install _____________________________, detailed in Exhibit \nA2___.  These facilities are estimated to cost $_____________ and are detailed in \nExhibit A2___."},{"page":535,"startToken":153529,"endToken":153830,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n(c) \nShared Network Upgrade(s) to be funded by Interconnection Customer.  \nAlternatively, where Transmission Provider determines that Interconnection \nCustomer benefits from one or more prior Network Upgrades or Common Use \nUpgrades, those Network Upgrades and/or Common Use Upgrades will be \nclassified by Transmission Provider as Shared Network Upgrades under this \nZGIA, and Interconnection Customer is responsible for costs as detailed below.  \nInterconnection Customer may later be eligible for refund and/or contribution if \nsubsequent Interconnection Customers are identified as also benefitting from the \nShared Network Upgrade(s).  Interconnection Customer shall fund those Shared \nNetwork Upgrade(s) detailed in Exhibit A5.  Interconnection Customer’s cost \nshare of the Share Network Upgrade(s) is estimated at $____________, as \ndetailed in Exhibit A5.  Interconnection Customer’s cost share of the Shared \nNetwork Upgrade(s) may be reduced if later interconnection projects are \ndetermined to also benefit from the Shared Network Upgrade(s).  Interconnection \nCustomer’s cost share of the Shared Network Upgrade(s) may also increase from \nthis estimate where other projects are determined to adversely impact \nInterconnection Customer’s cost share of the Shared Network Upgrade(s).i) If a \nShared Network Upgrade is not yet in service as of the date of execution of this \nZGIA, if applicable, Interconnection Customer shall post an Irrevocable Letter of \nCredit in the amount of its estimated proportionate share of the estimated cost of \nthat Shared Network Upgrade in accordance with Article 11.6.4 as of the date set \nforth in Appendix B to this ZGIA. \n \n(d) \nSubstation Network Upgrades to be installed by ____________________.  \nTransmission Owner shall install _______________________, detailed in Exhibit \nA2 ___.  These facilities are estimated to cost $_____________ and are detailed \nin Exhibit A2 ___. \n \n5. \nSystem Protection Facilities"},{"page":536,"startToken":153830,"endToken":154059,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n(a) \nSystem Protection Facilities not listed in Section 2 or 3 to be constructed by \nInterconnection Customer.  Interconnection Customer shall construct \n__________________________ detailed in Exhibit A3___.  These facilities are \nestimated to cost $________ and are detailed in Exhibit A3___. \n \n(b) \nSystem Protection Facilities not listed in 2 or 3 to be constructed by \nTransmission Owner.  Transmission Owner shall construct \n_____________________ and detailed in Exhibit A3___.  These facilities are \nestimated to cost $____________ and are detailed in Exhibit A3___. \n \n6. \nDistribution Upgrades \n \n(a) \nDistribution Upgrades to be constructed by (Transmission/Distribution) \nOwner (select one for final version).  (Transmission/Distribution) Owner shall \nconstruct __________________________ detailed in Exhibit A4___.  These \nfacilities are estimated to cost $________ and are detailed in Exhibit A4___. \n \n7. \nContingency List [include higher queued Interconnection Requests with ZGIAs prior to \nthis ZGIA and contingency Network Upgrades, System Protection Facilities or \nDistribution Upgrades of higher queued Interconnection Request with ZGIAs prior to this \nZGIA pursuant to Article 11.3.1 that are subject to restudy in accordance with Article \n11.3.2] \n \n(a) \nContingency List of MTEP Appendix B projects and contingent actions should \nAppendix B projects not proceed by listed date to Appendix A. \n \n8. \nAffected System Upgrades List (include higher queued Interconnection Requests with \nZGIAs prior to this ZGIA) \n \n9. \nJTIQ Upgrades"},{"page":537,"startToken":154059,"endToken":154140,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \n[To be included in ZGIA if Interconnection Customer is responsible for a portion of a \nportfolio of JTIQ Upgrades] Interconnection Customer is subject to the JTIQ Generator \nCharge in accordance with Attachment JJJ of the MISO Tariff and Appendix 18 of the \nGenerator Interconnection Procedures. \nInitial JTIQ Security amount:  \nA. \nConstructing MISO Transmission Owner \n \n1. ______________ \n2. ______________ \n3. ______________ \n4. ______________ \n \n \nB. \nSPP:"},{"page":538,"startToken":154140,"endToken":154311,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nAppendix B to ZGIA \nMilestones \n \n1. \nSelected Option pursuant to Article 5.1:  Interconnection Customer selects the \n[_____________] Option as described in Article 5.1.[ ], 5.1.[ ] and 5.1.[ ] shall not apply to this \nZGIA. \n \n2. \nMilestones:  The description and date entries listed in the following tables are provided \nsolely for the convenience of the Parties in establishing their applicable Milestones consistent \nwith the provisions of this ZGIA and the GIP. \n \nA. \nInterconnection Customer Milestones \n \n \n \n \n \n \nNo. \nDescription \nDate \n1a. \nProvide initial payment to Transmission Owner (ZGIA \n11.5) \nWithin the later of a) 45 \nCalendar Days of the \nexecution of the ZGIA by all \nParties, or b) 45 Calendar \nDays of acceptance by \nFERC if the ZGIA is filed \nunexecuted and the payment \nis being protested by \nInterconnection Customer, or \nc) 45 Calendar Days of the \nfiling if the ZGIA is filed \nunexecuted and the initial \npayment is not being"},{"page":539,"startToken":154311,"endToken":154624,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nprotested by Interconnection \nCustomer. \n1b. \nProvide security, i.e., a guarantee, surety bond, letter of \ncredit or other reasonably acceptable form of security \nto Transmission Owner (ZGIA 11.6). \n45 Calendar Days prior to \ndesign, procurement and \nconstruction. \n1c. \nEnter into a Facilities Service Agreement (“FSA”) as \nmay be applicable, with Transmission Owner for the \nNetwork Upgrades associated with this ZGIA. \nWithin 90 Calendar Days of \nthe Effective Date of the \nZGIA and prior to in-service \ndate of Network Upgrades \nassociated with this ZGIA. \n1d. \nEnter into amendment of this ZGIA, if required, for \nInterconnection Requests that did not elect optional \nnegotiation period adjustment for Interconnection \nFacilities Study pursuant to ZGIA Section 11.3.1. \nWithin 90 days of the \nposting of the final \nInterconnection Facilities \nreport. \n1e. \nDemonstrate 100% Site Control (if not provided earlier \ndue to qualifying regulatory limitations) or the ZGIA \nmay be terminated per Article 2 of this ZGIA and the \nInterconnection Customer may be subject to \nWithdrawal Penalties per Section 7.6.2.1.1 of the GIP \n(Calculation of the Automatic Withdrawal Penalty). \nWithin 180 Calendar Days  \nof the Effective Date. \n1f. \nEnter into SPP JTIQ Service Agreement (if included in \nJTIQ Participation Group) pursuant to GIP Section \n11.1. \nWithin 15 Calendar Days \nafter tender. \n1g.  \nEnter into any agreement required by an Affected \nSystem for the study, construction, or funding of a \nnetwork upgrade to mitigate impacts (for \nInterconnection Requests processed through ERAS) \npursuant to GIP Section 3.5.2.  \nWithin 15 Calendar Days \nafter tender.  \n1h. \nFor ZGIAs that grant ZG Interconnection Service, \ngreater than 5 MW, submit a completed Market \nParticipant Application pursuant to Section 38.2 et seq. \nWithin 30 Calendar Days \nafter execution or requesting \nan unexecuted filing of this"},{"page":540,"startToken":154624,"endToken":154876,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nof the Tariff (Module C). (ZGIA 7.1.1) \nAgreement. \n2. \nProvide Certificate of Insurance (ZGIA 18.4.9). \nThe earlier of the \nconstruction work \ncommencement date or the \nmilestone date; thereafter, \nwithin 90 Calendar Days of \nend of fiscal year or \ninsurance renewal date. \n3. \nProvide evidence of one or more of the following \nmilestones being achieved: (1) execution of \ncontract for (a) fuel supply or transport; (b) cooling \nwater supply; (c) engineering procurement of major \nequipment or construction; (d) execution of a \ncontract for the sale of electric energy or capacity \nfrom the Generating Facility, or a statement signed \nby an officer or authorized agent of Interconnection \nCustomer attesting that the Generating Facility is \nincluded in an applicable state resource adequacy \nplan; or other information that Transmission \nProvider deems to be reasonable evidence that the \nGenerating Facility will qualify as a designated \nnetwork resource; or (2) documentation of \napplication for state or local air, water, land, or \nfederal nuclear or hydroelectric permits and that the \napplication is proceeding per regulations (GIP \n11.3). \nWithin 180 Calendar Days \nof Effective Date. \n4. \nProvide security in the amount of $_______ to \nTransmission Owner to commence design, equipment \nprocurement and construction for Interconnection \nFacilities (ZGIA 5.5 and 5.6). \nAs may be agreed to by the \nParties. \n5. \nInvoice Transmission Owner for the estimated amount \nAs may be agreed to by the"},{"page":541,"startToken":154876,"endToken":155171,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nto be expended by the Interconnection Customer to \nconstruct any Stand Alone Network Upgrades for \nwhich the Interconnection Customer has exercised its \nOption to Build if the Transmission Owner has elected \nto Self Fund (ZGIA 5.2.13). \nParties, but in no event later \nthan 45 Calendar Days prior \nto the date the \nInterconnection Customer \nmust make any construction \npayment. \n6. \nPre-construction meeting. \nAs may be agreed to by the \nParties. \n7. \nProvide initial design and specifications for \nInterconnection Customer’s Interconnection Facilities \nto Transmission Owner and Transmission Provider for \ncomment (ZGIA 5.10.1). \n180 Calendar Days prior to \ninitial synchronization date. \n8. \nProvide final design and specifications for \nInterconnection Customer’s Interconnection Facilities \nto Transmission Owner and Transmission Provider for \ncomment (ZGIA 5.10.1). \n90 Calendar Days prior to \ninitial synchronization date. \n9. \nDeliver to Transmission Owner and Transmission \nProvider “as-built” drawings, information and \ndocuments regarding Interconnection Customer’s \nInterconnection Facilities (ZGIA 5.10.3). \nWithin 120 Calendar Days \nof Commercial Operation \nDate. \n10. \nProvide Transmission Owner final cost invoices to \nconstruct Stand Alone Network Upgrades for which the \nInterconnection Customer has exercised its Option to \nBuild if the Transmission Owner has elected to Self \nFund (ZGIA 5.2.13). \nWithin six (6) months of \ncompletion. \n10a. \nTransfer ownership of the Transmission Owner’s \nInterconnection Facilities and Stand Alone Network \nUpgrades to Transmission Owner if Interconnection \nCustomer has exercised the Option to Build (ZGIA \n5.2.9). \nAs agreed to by the Parties \nbut in no event later than the \nearlier of energization or \nthree days prior to the Initial \nSynchronization Date. \n10b. \nRefund overpayment, if any, of estimated costs to \nWithin 30 Calendar Days"},{"page":542,"startToken":155171,"endToken":155409,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nconstruct any Stand Alone Network Upgrades for \nwhich the Interconnection Customer has exercised its \nOption to Build if the Transmission Owner has elected \nto Self Fund (ZGIA 5.2.13). \nafter submitting invoice for \nfinal costs under Milestone \n10. \n11. \nNotify Transmission Provider and Transmission Owner \nin writing of Local Balancing Authority where \nGenerating Facility is located (ZGIA 9.2). \nThree months prior to Initial \nSynchronization Date. \n12. \nPre-energization meeting. \nAs may be agreed to by the \nParties. \n13. \nInitial Synchronization Date. \nAs agreed to by the Parties. \n14. \nCommercial Operation Date. \nAs agreed to by the Parties. \n15. \nInterconnection Customer shall provide the Parties with \nnotice on the status of the Generating Facility, \nincluding COD, under Article 15 of this ZGIA and \nshall also send such notice by email to \nResourceIntegration@misoenergy.org.  Notification \nshall include Interconnection Customer’s name, and as \napplicable Market Participant(s) name(s), and project \nnumber.   \n6 months prior to Initial \nSynchronization Date. \n16. \nInterconnection Customer shall provide notice to the \nParties of a test plan in advance of conducting tests for \nthe Generating Facility.  The notice shall be in the form \nbelow and should be provided under Article 15 of this \nZGIA, and a copy of such notice should be emailed to \nResourceIntegration@misoenergy.org. \n5 Business Days prior to \ntesting."},{"page":543,"startToken":155409,"endToken":155616,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n17. \nIn the event the Interconnection Customer makes any \nmodifications to the design of the site layouts or \ninterconnection facility routes after execution of this \nZGIA, Interconnection Customer shall notify the \nParties of such changes immediately upon identifying \nthe need for such changes.  After providing such \nnotification, the Interconnection Customer shall \nprovide to Transmission Provider evidence of \ncontinued Site Control for land sufficient to \naccommodate the changes in site layouts and/or \ninterconnection facility routes (GIP 7.2.2). \n90 Calendar Days after \nInterconnection Customer \nprovides notice to Parties. \n18. \nFor ZGIAs that grant ZG Interconnection Service \ngreater than 5 MW, take all steps required by the MISO \nTariff and applicable Business Practices Manual to \ncomplete registration as a Generation Resource, Energy \nStorage Resource, or Dispatchable Intermittent \nResource based on its applicable operating \ncharacteristics.  (GIA 7.1.1) \nPrior to Commercial \nOperation Date. \n \nB. \nTransmission Owner Milestones \n \n \n \n \n \n \nNo. \nDescription \nDate \n0. \nTransmission Owner to enter Network Upgrade \ninformation into Transmission Provider’s MTEP \ndatabase and model on demand. \n10 Business Days after \nEffective Date. \n1. \nProvide Certificate of Insurance (ZGIA 18.4.9). \nThe earlier of the"},{"page":544,"startToken":155616,"endToken":155793,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nconstruction work \ncommencement date or the \nmilestone date; within 90 \nCalendar Days of end of \nfiscal year or insurance \nrenewal date. \n2. \n•   Commence design of Interconnection Facilities \n(ZGIA 5.5 et seq.). \n \n•   Commence equipment procurement. \nAs agreed to by the Parties \n(after completion of \nInterconnection Facilities \nStudy, receipt of written \nauthorization from \nInterconnection Customer \nand Interconnection \nCustomer’s deposit of \nsecurity. \n3. \nCommence construction of Interconnection Facilities \n(ZGIA 5.6 et seq.). \nAs agreed to by the Parties \n(after receiving approval of \nGovernmental Authority, \nreceipt of written \nauthorization and security \nfrom Interconnection \nCustomer). \n4. \nComment on Interconnection Customer’s final design \nand specifications.  \nWithin 30 Calendar Days of \nInterconnection Customer’s \nsubmission of final design \nand specifications. \n5. \nDeliver to Interconnection Customer and Transmission \nProvider “as-built” drawings, information and \ndocuments regarding Transmission Owner’s \nInterconnection Facilities (ZGIA 5.11). \nWithin 120 Calendar Days of \nCommercial Operation Date. \n6. \nProvide payment for invoiced estimated costs to \nWithin 30 Calendar Days of"},{"page":545,"startToken":155793,"endToken":155956,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nconstruct for which the Interconnection Customer has \nexercised its Option to Build if the Transmission \nOwner has elected to Self Fund (ZGIA 5.2.13). \nreceipt of Interconnection \nCustomer’s invoice for \nestimated costs. \n6a. \nProvide payment for invoiced final cost to construct \nStand Alone Network Upgrades for which the \nInterconnection Customer has exercised its Option to \nBuild if the Transmission Owner has elected to Self \nFund (ZGIA 5.2.13). \nWithin 30 Calendar Days of \nreceipt of Interconnection \nCustomer’s invoice for final \ncosts. \n7. \nProvide Interconnection Customer final cost invoices \n(ZGIA 12.2 et seq.). \nWithin (6) six months of \ncompletion.  \n8. \nRefund overpayment of estimated costs (ZGIA 12.2). \n \n90 Calendar Days prior to \ninitial synchronization date.  \nRefunds within 30 Calendar \nDays. \n9. \nIn-Service Date/Backfeed Date. \nAs agreed to by the Parties. \n \nC. \nAffected System Owner Milestones \n \nTask \nDate Due"},{"page":546,"startToken":155956,"endToken":156044,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nAppendix B-1 to ZGIA \nPre-Certification Generation Test Notification Form \n \nThe following form would need to be submitted to MISO Real Time Operations at least five (5) \nBusiness Days prior to the first date of testing. \n \nProject Number:  \n \nProject Name:  \n \nPoint of Interconnection: \n \nDispatcher Contact Information: \n \n \nDate \nStart Time \n(in EST) \nEnd Time \n(in EST) \nExpected MW \nOutput \nExpected MVAR \nOutput (Only needed if \nbeyond normal power \nfactor)"},{"page":547,"startToken":156044,"endToken":156246,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nAppendix C to ZGIA \nInterconnection Details \n \nThis Appendix C is a part of this ZGIA among Interconnection Customer, Transmission Owner \nand Transmission Provider. \n1. \nTransmission Owner shall provide the following “as-built” drawings, information and \ndocuments regarding the Transmission Owner’s Interconnection Facilities pursuant to \nArticle 5.11 of this ZGIA. \n2. \nThe unique requirements of each generation interconnection will dictate the \nestablishment of mutually agreeable Interconnection and/or Operating Guidelines that \nfurther define the requirements of this ZGIA.  The Interconnection and/or Operating \nGuidelines applicable to this ZGIA consist of the following information.  Additional \ndetail may be provided through attachment to this Appendix C or through electronic \nmeans via the web address specified. \n(a) \nSystem Protection Facilities; \n(b) \nCommunication requirements; \n(c) \nMetering requirements; \n(d) \nGrounding requirements; \n(e) \nTransmission Line and Substation Connection configurations; \n(f) \nUnit Stability requirements; \n(g) \nEquipment ratings; \n(h) \nShort Circuit requirements; \n(i) \nSynchronizing requirements; \n(j) \nGeneration and Operation Control requirements; \n(k) \nData provisions; \n(l) \nEnergization inspection and testing requirements; and \n(m) \nControl equipment, if any. \n3. \nInformation required pursuant to Section 8.4 for Variable Energy Resource Generating \nFacilities:  ___________________________________________________."},{"page":548,"startToken":156246,"endToken":156385,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nAppendix D to ZGIA \nSecurity Arrangements Details \n \nInfrastructure security of Transmission or Distribution System equipment and operations, as \napplicable, and control hardware and software is essential to ensure day-to-day Transmission and \nDistribution System reliability and operational security.  The Commission will expect all \nTransmission Providers, market participants, and Interconnection Customers interconnected to \nthe Transmission or Distribution System, as applicable, to comply with the recommendations \nprovided by Governmental Authorities regarding Critical Energy Infrastructure Information \n(“CEII”) as that term is defined in 18 C.F.R. Section 388.113(c) and best practice \nrecommendations from the electric reliability authority.  All public utilities will be expected to \nmeet basic standards for system infrastructure and operational security, including physical, \noperational, and cyber-security practices."},{"page":549,"startToken":156385,"endToken":156496,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nAppendix E to ZGIA \nCommercial Operation Date \n \nThis Appendix E is a part of this ZGIA between Transmission Provider, Transmission \nOwner and Interconnection Customer. \n \n[Date] \n \nMidcontinent Independent System Operator, Inc. \nAttn:  Director, Transmission Access Planning \n720 City Center Drive \nCarmel, IN  46032 \n \nRe: \n_____________ Generating Facility \n \nDear _______________: \n \nOn [Date] [Interconnection Customer] has completed Trial Operation of Unit No. ___.  \nThis letter confirms that [Interconnection Customer] commenced commercial operation of Unit \nNo. ___ at the Generating Facility, effective as of [Date plus one Calendar Day]. \nThank you. \n [Signature] \n \n[Interconnection Customer Representative] \ncc: \nTransmission Owner"},{"page":550,"startToken":156496,"endToken":156574,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nAppendix F to ZGIA \nAddresses for Delivery of Notices and Billings \n \nNotices: \n \nTransmission Provider: \n \nMISO \nAttn:  Director, Transmission Access Planning \n720 City Center Drive \nCarmel, IN  46032 \n \nTransmission Owner: \n \n[To be supplied.] \n \nInterconnection Customer: \n \n[To be supplied.] \n \n \nBillings and Payments: \n \nTransmission Provider: \n \nMISO \nAttn:  Director, Transmission Access Planning \n720 City Center Drive \nCarmel, IN  46032 \n \nTransmission Owner:"},{"page":551,"startToken":156574,"endToken":156636,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \n[To be supplied.] \n \nInterconnection Customer: \n \n[To be supplied.] \n \n \nAlternative Forms of Delivery of Notices (telephone, facsimile or email): \n \nTransmission Provider: \n \nPhone: (317) 249-5700  \nEmail: misotap@misoenergy.org or \nMISOTransmissionAccessPlanning@misoenergy.org \n \nTransmission Owner: \n \n[To be supplied.] \n \nInterconnection Customer: \n \n[To be supplied.]"},{"page":552,"startToken":156636,"endToken":157017,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nAppendix G to ZGIA \nInterconnection Requirements for Inverter-Based Resource Plants \n \n \nAppendix G sets forth requirements and provisions specific to inverter-based resource \n(IBR) plants.  Transmission Owner Local Planning Criteria for IBR performance may differ from \nAppendix G requirements.  In such cases, Transmission Owner Local Planning Criteria shall \nsupersede the Appendix G requirements and be documented in Appendix C of this ZGIA1.  All \nother requirements of this ZGIA also apply to IBR plant interconnections.  IBR plants shall meet \nboth Applicable Reliability Standards and Appendix G requirements.  Battery energy storage \nsystems required to furnish grid-forming controls shall be exempt from specific IEEE 2800 \nrequirements as outlined in the BPM for Generator Interconnection.  Italicized terms indicate \nIEEE 2800-2022 defined terms2.  IEEE 2800-2022's definitions will govern these italicized terms \nunless otherwise defined herein.  \n \nA. \nGeneral   \nThe IBR plant shall adhere to IEEE 2800-2022 Clause 4 requirements, except for \nsubclauses 4.1 (introduction), 4.5 (operational measurement and communication capability), 4.6 \n(control capability requirements), 4.8 (isolation devices), 4.9 (inadvertent energization of TS), \n4.11 (interconnection integrity), and 4.12 (integration with TS grounding).  \nWithin the adopted IEEE 2800-2022 Subclauses, the following requirements shall be \nincorporated as Transmission Provider and Transmission Owner3 specification options noted in \nIEEE 2800-2022. \n• \nSubclause 4.2.1: The reference point of applicability (RPA) shall be at the point \nof measurement (POM) bus with the exception of requirements specified in \nClauses 7.2.2.3.4 and 7.2.2.3.5 of the standard to have the RPA at the point of \n \n1  IEEE 2800-2022 points to \"weak grid” issues requiring exceptions to default values and ranges of available \nsettings for various types of performance. IEEE 2800-2022 Annex C.2 contains discussion on characterizing weak \ngrid areas.  \n2  “IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with \nAssociated Transmission Electric Power Systems,\" in IEEE Std 2800-2022 , vol., no., pp.1-180, 22 April 2022, doi: \n10.1109/IEEESTD.2022.9762253. \n3  For the purpose of this ZGIA, the IEEE 2800 term of TS operator is synonymous with Transmission Owner and \nthe IEEE 2800 term of TS owner is synonymous with Transmission Planner or Transmission Owner, as applicable."},{"page":553,"startToken":157017,"endToken":157292,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nconnection (POC).   \n• \nSubclause 4.3: The Transmission Owner shall specify the nominal voltage and \nfrequency at the RPA in Appendix C of this ZGIA.  \n• \nSubclause 4.10.2: The enter service criteria shall use the default values for \napplicable voltages and applicable frequency specified in the table below unless \notherwise specified in Appendix C of this ZGIA4.  \n \nEnter service criteria \nDefault setting \nApplicable voltage, minimum value \n0.9 p.u. \nApplicable voltage, maximum value \n1.05 p.u. \nApplicable frequency, minimum value \n58.8 Hz \nApplicable frequency, maximum value \n60.12 Hz.  \n \n• \nSubclause 4.10.3: The performance during enter service shall use the default \nvalues specified below unless otherwise specified in Appendix C of this ZGIA. \no The minimum intentional delay performance, as defined in Subclause 4.10.3, \nb), shall be 0 seconds.  \no The duration of the enter service period, as defined in Subclause 4.10.3, c), \nshall be 300 seconds.  \n \nB.  \nResponse to Abnormal Conditions \nThe IBR plant shall adhere to IEEE 2800-2022 Clause 7 requirements, except for \nsubclauses 7.2.1 (voltage protection) and 7.3.1 (mandatory frequency tripping).  Where \nApplicable Reliability Standards require more stringent ride-through requirements compared to \nIEEE 2800-2022 Clause 7 requirements, those standards shall take precedence5.  \n \n4  MISO default values may be modified within the IEEE 2800 range of allowable settings by Transmission Owner \nLocal Planning Criteria. \n5  More stringent ride-through requirements include, but are not limited to, expanded voltage and frequency \nconditions or extended cumulative times under which IBR plants must ride-through."},{"page":554,"startToken":157292,"endToken":157616,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nWithin the adopted IEEE 2800-2022 Subclauses, the following requirements shall be \nincorporated as the Transmission Provider and Transmission Owner decision points6 noted in \nIEEE 2800-2022.  \n• \nSubclause 7.2.2.1: The Transmission Owner shall specify the nominal voltage for \nuse by this clause. Nominal voltages may include nominal transmission system \nvoltages that are different from standard ANSI C84.1-2016 voltages. \n• \nSubclause 7.2.2.2: If the IBR plant cannot deliver both active and reactive power \ndue to its current limit (or apparent power limit), when the applicable voltage is \nbelow 95%, then preference shall be given to reactive power while minimizing \nany reductions in active power. \n• \nSubclause 7.2.2.3: The IBR plant shall give preference to reactive power unless \notherwise specified in Appendix C of this ZGIA. In addition, the IBR plant shall \nminimize reductions in active power while carrying out the reactive current \npriority mode response.  \n• \nSubclause 7.2.2.3.4: The Interconnection Customer shall submit the IBR plant \ncontrols default relationship between the magnitude of incremental positive and \nnegative sequence reactive currents. The Transmission Provider and Transmission \nOwner, through this agreement, may specify a required IBR plant response \nrelationship between the incremental positive and negative sequence reactive \ncurrents. \n \nC. \nReactive Power \nThe IBR plant shall adhere to IEEE 2800-2022 Clause 5 requirements. \nWithin the adopted IEEE 2800-2022 Subclauses, the following requirements shall be \nincorporated as the Transmission Provider and Transmission Owner decision points noted in \nIEEE 2800-2022.  \n• \nSubclause 5.1: The IBR plant shall have the reactive power capabilities outlined \nin this clause. Consistent with section 9.6.1 of this ZGIA, an IBR plant shall \n \n6  Decision points refer to language in the IEEE 2800-2022 standard that leaves default values, application of \nrequirements, and other details open for the TS Owner or TS Operator to define."},{"page":555,"startToken":157616,"endToken":157922,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nmaintain a power factor within the range of 0.95 leading to 0.95 lagging, unless \nTransmission Provider has established different requirements that apply to all \nGenerating Facilities in the Local Balancing Authority on a comparable basis, \nmeasured at the high side of the generator substation.   \n• \nSubclause 5.2.2: The voltage control dynamic performance requirements in Table \n5 shall apply when the system short-circuit strength at the RPA is equal to or \nabove the minimum short-circuit strength identified by the Transmission Provider \nor Transmission Owner. \n• \nSubclause 5.2.2: The reaction time, as defined in Subclause 5.2.2 Table 5, shall be \n250 milliseconds or less. \n• \nSubclause 5.2.2: The maximum step response time, as defined in Subclause 5.2.2 \nTable 5, shall be 30 seconds. \n• \nSubclause 5.2.3: The power factor control mode shall appropriately operate at all \nactive power levels from the Inverter Based Resource Continuous Rating (“ICR”) \ndown to, but not including, zero. \n \nD. \nPrimary Frequency Response \nThe IBR plant shall adhere to IEEE 2800-2022 Clause 6 requirements, except for \nSubclause 6.2 (fast frequency response).   \nWithin the adopted IEEE 2800-2022 Subclauses, the following requirements shall be \nincorporated as the Transmission Provider and Transmission Owner decision points noted in IEEE \n2800-2022.  \n• \nSubclause 6.1.1: The use of primary frequency response capabilities shall be \nrequired for all IBR plants. \n• \nSubclause 6.1.1: Frequency droop shall be based on the difference between \nnameplate capacity and zero output such that the slopes of the droop curves are \nalways constant. \n• \nSubclause 6.1.2: The settling band default value in Table 8 shall be based on the \nmaximum of 2.5% of change or 0.5% of nameplate capacity."},{"page":556,"startToken":157922,"endToken":158123,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nThe exceptions to primary frequency response requirements provided to electric storage \nresources in Article 9.6.4.4 of this ZGIA shall still apply.   \n \nTABLE 1. SUMMARY OF ADOPTION TREATMENT OF IEEE 2800-2022 SUBCLAUSES \nIEEE 2800-2022 Subclause \nRequired by \nAppendix G \nfor DPP-2022 \nand later \nRequired by \nAppendix G \nfor DPP-2023 \nand later \nException \n4.1 Introduction \n \n \nX \n4.2 Reference Point of Applicability \nX \n \n4.3 Applicable Voltages and Frequencies \nX \n \n4.4 Measurement Accuracy \nX \n \n4.5 Operational Measurement and \nCommunication Capability \n \nX \n4.6 Control Capability \n \nX \n4.7 Prioritization of IBR Responses \nX \n \n4.8 Isolation Devices \n \n \nX \n4.9 Inadvertent Energization of TS \n \nX \n4.10 Enter Service \nX \n \n4.11 Interconnection Integrity \n \nX \n4.12 Integration with TS grounding \n \nX \n5.1 Reactive Power Capability \n \nX \n \n5.2 Voltage and Reactive Power Modes \n \nX \n \n6.1 Primary Frequency Response \n \nX \n \n6.2 Fast Frequency Response \n \n \nX \n7.1 Introduction \nX \n \n \n7.2.1 Voltage protection  \n \n \nX \n7.2.2.1 Voltage disturbance ride-through: \nGeneral \nX \n \n \n7.2.2.2 Voltage disturbances within continuous \nX"},{"page":557,"startToken":158123,"endToken":158377,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\noperation \n7.2.2.3 Low- and high-voltage ride-through \nX \n \n \n7.2.2.4 Consecutive voltage deviations ride-\nthrough \n \nX \n7.2.2.5 Dynamic voltage support \nX \n \n \n7.2.2.6 Restore output after voltage ride-through X \n \n \n7.2.3 Transient overvoltage  \nX \n \n \n7.3.1 Mandatory frequency tripping  \n \n \nX \n7.3.2 Frequency disturbance ride-through \nX \n \n \n7.4 Return to service \nX \n \n \n \nE. \nSupervisory Control and Data Acquisition (SCADA) Capability    \nThe IBR plant shall provide SCADA capability to transmit data and receive instructions \nfrom Transmission Provider to protect system reliability.  Transmission Provider and \nInterconnection Customer shall determine what SCADA information is essential for the \nproposed IBR plant, taking into account the size of the plant and its characteristics, location, and \nimportance in maintaining generation resource adequacy and transmission system reliability in \nits area. \n \nF. \nDisturbance Monitoring and Reporting Requirements  \nIBR plants with generating capacities of more than 20 MW must monitor and record data \nfor all frequency ride-through events, transient low-voltage disturbances that initiated reactive \ncurrent injection, reactive current injection or momentary cessation for transient high-voltage \ndisturbances, and inverter trips.  Dynamic Disturbance Recording (“DDR”) data must be \nrecorded continuously.  The data may be recorded and stored in a central plant control system. \nThe following data must be recorded:  \nPlant Level \n(1)  Plant three-phase voltage, current and power factor \n(2)  Status of ancillary reactive devices \n(3)  Status of all plant circuit breakers"},{"page":558,"startToken":158377,"endToken":158657,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n(4)  Status of plant controller \n(5)  Plant control set points \n(6)  Status of main plant transformer no load taps \n(7)  Status of main plant transformer tap changer (if applicable) \n(8)  Protective relay trips (relay target data) \nInverter Level Data \n(1)  Frequency, current, and voltage during frequency ride-through events \n(2)  Voltage and current during momentary cessation for transient high-voltage events \n(when used) \n(3)  Voltage and current during reactive current injection for transient low or high-\nvoltage events \n(4)  Inverter alarm and fault codes \n(5)  DC current \n(6)  DC voltage \nDDR Data – Plant Level \n(1) One phase-to-neutral or positive sequence voltage on high-side of the main power \ntransformer(s) \n(2) Positive sequence current or phase current for the same phase as (1)  \n(3) Real and reactive power flows expressed on a three-phase basis corresponding to each \nmain power transformer(s) where current measurements are required \n(4) Frequency of any one of the voltages in (1)  \n \nThe data must be time synchronized to a one millisecond level of resolution.  All data \nexcept DDR data must be sampled at least every 10 milliseconds.  DDR data must have an input \nsampling rate of at least 960 samples per second and an output recording rate of electrical \nquantities of at least 60 times per second. \nThe IBR plant shall store this data for a minimum of 60 calendar days.  The IBR plant, \nupon request from MISO or the transmission owner, shall make this data available within 10 \ncalendar days of the request. \nPhasor measurement unit (“PMU”) capabilities shall be used to facilitate the DDR data."},{"page":559,"startToken":158657,"endToken":159053,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nG. \nApplicability   \nIBR plants that are, or have been, interconnected to the network at the effective date of \nthe Appendix G abnormal voltage ride-through standard are exempt from meeting the Appendix \nG abnormal voltage ride-through standard for the remaining life of the existing generation \nequipment.  Except for IBR plants actively undergoing a Generating Facility Replacement at the \neffective date of this ZGIA  that have equipment on order where the OEM has documented \nperformance that differs from what is required in this ZGIA, all individual IBR units that are \nreplaced are required to meet the Appendix G performance requirements.   \nThe IEEE 2800-2022 requirements cited in Section A (IEEE 2800-2022 Clause 4) and \nSection B (IEEE 2800-2022 Clause 7, except Subclause 7.2.2.4) of Appendix G shall apply to \nIBR plants in the DPP-2022-Cycle and beyond.  For the DPP-2022-Cycle, Interconnection \nCustomers may request exceptions confined to these sections only if specific limitations or \nuncertainties of equipment or plant capabilities prevent implementation of these requirements.  \nZGIAs signed or amended with inverter changes on or after January 1, 2025, are not eligible for \nrequirement exceptions. Further, the process for establishing exceptions for these requirements \nshall not apply beyond the DPP-2022-Cycle.  \nThe IEEE 2800-2022 requirements cited in Section B (IEEE 2800-2022 Subclause \n7.2.2.4), Section C (IEEE 2800-2022 Clause 5), and Section D (IEEE 2800.2022 Clause 6) of \nAppendix G shall apply to IBR plants in the DPP-2023-Cycle and beyond.  For the DPP-2023-\nCycle, Generating Facilities Replacements, and Surplus Interconnections, Interconnection \nCustomers may request exceptions confined to these sections only if specific limitations or \nuncertainties of equipment or plant capabilities prevent implementation of these requirements.  \nZGIAs signed or amended with inverter changes on or after January 1, 2026, are not eligible for \nrequirement exceptions.  Further, the process for establishing exceptions for these requirements \nshall not apply beyond the DPP-2023-Cycle.  \nInterconnection Customers requesting exceptions shall submit documentation to the \nTransmission Provider outlining the specific IEEE 2800-2022 subclauses pertinent to the request \nalong with information from the manufacturer regarding the nature of the issue conforming to or \nassessing conformance with requirements herein.  The Transmission Provider will, in good faith, \naccept Original Equipment Manufacturer (OEM)-documented requirement exceptions and \ndocument these exceptions in Appendix C of this ZGIA."},{"page":560,"startToken":159053,"endToken":159141,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nIf the performance or capability exception can be mitigated through equipment firmware \nupgrades still under development, the Interconnection Customer shall use commercially \nreasonable efforts to implement the firmware upgrade within sixty (60) calendar days of \ncommercial availability of such firmware.  \nThe DDR and PMU requirements in the Section F, Disturbance Monitoring and \nReporting Requirements of Appendix G shall apply to IBR plants in the DPP-2023-Cycle and \nbeyond."},{"page":561,"startToken":159141,"endToken":159459,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nAppendix H to ZGIA \nInterconnection Requirements for Provisional ZGIA \n \nProvisional Agreement \n \nThis ZGIA is being provided in accordance with Section 11.5 of the Transmission Provider’s \nGIP, which provides among other things, that an Interconnection Customer may request that \nTransmission Provider provide Interconnection Customer with a Provisional Generator \nInterconnection Agreement that limits the transfer of energy by Interconnection Customer \ncommensurate with that allowed for Energy Resource Interconnection Service.  Interconnection \nCustomer requested Transmission Provider to provide a Provisional Generator Interconnection \nAgreement for limited operation at the discretion of Transmission Provider based upon the \nresults of available studies (by Interconnection Customer and by Transmission Provider). \n \nA Provisional Interconnection Study, the results of which are posted on the confidential portion \nof the Transmission Provider’s internet website, was performed by Transmission Provider in \norder to confirm the facilities that are required for provisional Interconnection Service and to \nrequire them to be in place prior to commencement of service under the ZGIA.   \n \nInterconnection Customer represents that the Interconnection Customer facilities (including \nNetwork Upgrades, Interconnection Facilities, Distribution Upgrades, System Protection \nUpgrades and/or Generator Upgrades) that are necessary to commence provisional \nInterconnection Service and meet the requirements of Electric Reliability Organization, or any \napplicable regional entity for the interconnection of a new generator are in place prior to the \ncommencement of generation from the Generating Facility and will remain in place during the \nterm of the service.  The requisite Interconnection Studies were performed for the Generating \nFacility.  Interconnection Customer shall meet any additional requirements (including reactive \npower requirements) pursuant to the results of applicable future Interconnection System Impact \nStudies.  Until such time as the applicable Interconnection Studies and any identified facilities \nare completed, the output of the Generating Facility will operate within the output limit \nprescribed in a future, if applicable, operating guide."},{"page":562,"startToken":159459,"endToken":159771,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n \nThe maximum permissible output of the Generating Facility under Appendix A will be updated \nby Transmission Provider on a quarterly basis, determined in accordance with Section 11.5 of the \nGIP, by finding the transfer limit of energy commensurate with the analysis for Energy Resource \nInterconnection Service (“ERIS”).  This study shall be performed assuming the system topology \nrepresented by the base cases used to calculate Available Flowgate Capability, as described in \nAttachment C of the Tariff, with dispatch and optimization algorithms posted on the MISO \ninternet site and operation above those limits will be deemed as unauthorized use of the \nTransmission System and subject to provisions in the Tariff surrounding that use.   \n \nUse of interim operating guide \n \nImplementation of interim operating guide, if applicable, will constitute an interim solution that \nwill permit Interconnection Customer to operate the Generating Facility under conditional \nInterconnection Service until planned Network Upgrades are constructed.  Any interim operating \nguide will be subject to the approval of Transmission Owner and Transmission Provider.  \nMinimum requirements for an interim operating guide are as indicated below. \n \n *   Transmission Operator will have control of breaker(s) dedicated to the Generating Facility \nand will be able to trip the Interconnection Customer’s Generating Facility \n *   Protection schemes must be tested and operative \n *   Interconnection Customer will provide continuous communication capability with the \nGenerator Operator \n *   Interconnection Customer and the owner of the Existing Generating Facility will enter into \nan operating agreement or similar agreement which designates, among other things, the \nresponsibilities and authorities of each of the parties and shall be subject to the acceptance of \nTransmission Provider and Transmission Owner. \n *   A termination date consistent with completion of construction of Network Upgrades will be \nincluded as part of all operating guides accepted by Transmission Owner and Transmission \nProvider."},{"page":563,"startToken":159771,"endToken":159875,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nInterconnection Customer assumes all risks and liabilities with respect to changes, which may \nimpact the Generator Interconnection Agreement including, but not limited to, change in output \nlimits and responsibilities for future Network Upgrade and cost responsibilities that have not yet \nbeen identified on the direct connect Transmission System as well as all affected Transmission, \nDistribution or Generation System(s) including non-Transmission Provider Systems.  Such \nupgrades will be determined pursuant to the Tariff and Policies in effect at the time of the \nInterconnection Studies."},{"page":564,"startToken":159875,"endToken":160145,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\nAppendix I to ZGIA \nRequirements Applicable to Surplus Interconnection Service \n \nWhere this ZGIA provides for Surplus Interconnection Service, Interconnection Customer \nacknowledges, agrees to, and will be required to operate under the following conditions: \n \n1) The combined Real-Time Offers, including Energy and Operating Reserves, of the \nGenerating Facility and the Existing Generating Facility with which Interconnection \nCustomer has an executed Energy Displacement Agreement must be less than or equal to \nInterconnection Service limit (MW, MVAR, MVA output) provided in Exhibit I-1 \n(Monitoring and Consent Agreement) (hereinafter, “Interconnection Service limit”).  \nIn the event that the sum of the simultaneous energy output of the Surplus \nInterconnection Service Generating Facility and the Existing Generating Facility exceeds \nsuch Interconnection Service limit, MISO reserves the right to curtail and/or disconnect \nthe Generating Facility immediately. \n \nIn the event that the sum of the emergency and/or economic maximum offer limits of the \nGenerating Facility and the Existing Generating Facility exceeds the Interconnection \nService limit, MISO reserves the right to curtail and/or disconnect the Generating Facility \nimmediately. \n2) The total MW, MVAR, MVA output at the Point of Interconnection resulting from the \ncombined output of the Generating Facility with Surplus Interconnection Service and the \nExisting Generating Facility with which Interconnection Customer has an executed \nEnergy Displacement Agreement shall not at any time exceed the Interconnection Service \nlimit. \n \n3) The Existing Generating Facility with which Interconnection Customer has an executed \nEnergy Displacement Agreement is not relieved of any applicable requirements under the \nRAR of the Tariff."},{"page":565,"startToken":160145,"endToken":160262,"text":"MISO \nAttachment X: Appendix 19\nFERC Electric Tariff \nZG Interconnection Agreement (ZGIA)\nATTACHMENTS \n31.0.0\nEffective On: October 18, 2026\n4) The Interconnection Customer shall submit to the Transmission Provider a report by the \nseventh Calendar Day of each month showing the prior month’s output, by 15 minute \nincrement, the combined real-time offers and cleared energy injection.  The Existing \nGenerating Facility and the Interconnection Customer shall cooperate consistent with \nother provisions in the Tariff to the extent necessary to ensure accuracy of the report.  \nTransmission Provider shall provide a template for this report. \n \n \nExhibit I-1 (Completed Monitoring and Consent Agreement - Appendix 11 of the GIP) \n \nExhibit I-2 (Completed Energy Displacement Agreement - Appendix 12 of the GIP)"},{"page":566,"startToken":160262,"endToken":160564,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nATTACHMENT FF\nTRANSMISSION EXPANSION PLANNING PROTOCOL\nI.\nTransmission Expansion Plan - Purpose and Scope, Definition and Role of OMS \nCommittee:  This Attachment FF describes the process to be used by the Transmission Provider \nto develop the MISO Transmission Expansion Plan (“MTEP”), subject to review and approval \nby the Transmission Provider Board.  The provisions of this Attachment FF are consistent with \nthe applicable provisions of Appendix B of the ISO Agreement and this Tariff.  For purposes of \nthis Attachment FF, all references to Transmission Owner(s) will include ITC(s).  The costs \nincurred by the Transmission Provider in the performance of data collection, analyses and \nreview, and in the development of the MTEP report, costs incurred under Section I.C of this \nAttachment FF, and costs incurred under Section I.D of this Attachment FF shall be recovered \nfrom all Transmission Customers under Schedule 10 of the Tariff.\nA.\nEnrollment Process:  The MTEP is developed to facilitate the timely and orderly \nexpansion of and/or modification to the Transmission System to maintain reliability, promote \nefficiency in bulk power markets and facilitate compliance with applicable Federal and state \nlaws, regulatory mandates and regulatory obligations.  Any transmission provider that wishes to \nenroll in the Transmission Provider planning process for purposes of Order No. 1000 compliance \nmust become a Transmission Owner, by signing the ISO Agreement, and by, within a reasonable \nperiod of time: (1) turning over functional control of its transmission facilities to the \nTransmission Provider; and (2) taking service under this Tariff for all its load that is physically \nlocated within the geographic area comprising the Transmission System.  All Transmission \nOwners enrolled in the Transmission Provider’s transmission planning region are listed in either"},{"page":567,"startToken":160564,"endToken":160827,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\n(1) Attachment FF-4 of this Tariff, for Transmission Owners without a separately filed local \nplanning process or (2) Attachment FF-5 of this Tariff, for Transmission Owners with a \nseparately filed local planning process.\nB.\nOMS Committee Input to MTEP Process:  To the extent not otherwise \nspecifically addressed in other portions of this Attachment FF, with respect to the MTEP process, \nthe OMS Committee may provide input to the Transmission Provider planning staff and the \nSystem Planning Committee of the Transmission Provider Board, as appropriate, regarding the \nfollowing:\n1.\nAt the start of a planning cycle, the OMS Committee may suggest to the \nTransmission Provider Board modifications to the Transmission Provider’s \nplanning principles and planning objectives for that planning cycle;\n2.\nAt the start of a planning cycle, the OMS Committee may suggest additional \nscope elements in the MTEP;\n3.\nModeling inputs or assumptions used in the development of the MTEP and related \nappropriate cost/benefit analyses with respect to certain projects that are not \nproposed strictly for reliability; and \n4.\nConcerns about general or specific issues with the MTEP process as they arise \nduring the planning year.\nFurthermore, at the end of the MTEP development process, but before the MTEP is submitted to \nthe Transmission Provider Board for its review, the OMS Committee may submit a \nreconsideration request to the Transmission Provider planning staff, which shall respond prior to \nsubmitting the final MTEP report to the Transmission Provider Board.  This reconsideration"},{"page":568,"startToken":160827,"endToken":161151,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nrequest can be made only with respect to Network Upgrades eligible to receive regional cost \nallocation under Attachment FF if such projects: (1) will be recommended to the Transmission \nProvider Board for MTEP Appendix A approval, but have not been considered through the \ncomplete MTEP process or (2) will have a change in project cost of twenty-five percent (25%) or \ngreater between the final Subregional Planning Meeting in the current planning year and the \nproject being submitted to the Transmission Provider Board for approval.  The Transmission \nProvider shall consider such a reconsideration request only if it is endorsed by the OMS acting \nby a vote of sixty-six percent (66%) or more of the OMS members.\nAt the end of each MTEP cycle, the OMS Committee may submit its assessment of the \nMTEP process to the Planning Advisory Committee, Transmission Provider, and the System \nPlanning Committee of the Transmission Provider Board.  Upon receipt of any such assessment \nfrom the OMS Committee, the Transmission Provider planning staff shall provide an appropriate \nresponse in a reasonably timely manner.\nThe manner in which the OMS Committee shall provide its assessment shall be set forth \nin the Transmission Planning Business Practices Manual procedures.  The general procedures \nadopted with respect to the OMS Committee input into the MTEP shall remain unchanged until \nJune 1, 2015, unless otherwise mutually agreed to by the Transmission Provider and the OMS \nCommittee.  Changes to the Transmission Planning Business Practices Manual procedures which \ndescribe OMS Committee input into the MTEP process may not be adopted with less than sixty \n(60) days’ notice to the OMS Committee unless the OMS Committee consents to such earlier \nadoption.  At the end of the two year period the Transmission Provider, the OMS, and other \nstakeholders will assess the success of the input procedures and provide suggestions for"},{"page":569,"startToken":161151,"endToken":161442,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nimprovement.\nC.\nDevelopment of the MTEP:  The Transmission Provider, working in \ncollaboration with representatives of the Transmission Owners, OMS, and the Planning Advisory \nCommittee, shall develop the MTEP, consistent with Good Utility Practice and taking into \nconsideration long-range planning horizons, as appropriate.  The Transmission Provider shall \ndevelop the MTEP for expected use patterns and analyze the performance of the Transmission \nSystem in meeting both reliability needs and the needs of the competitive bulk power market, \nunder a wide variety of contingency conditions.  The MTEP will give full consideration to the \nneeds of all Market Participants, will include consideration of demand-side options, and will \nidentify expansions or enhancements needed to i) support competition and efficiency in bulk \npower markets; ii) comply with Applicable Laws and Regulations; and iii) maintain reliability. \nTransmission expansions or enhancements may include any facilities that are eligible to be \nincluded in the Transmission System as provided for under this Tariff, including SATOA. Any \nSATOA may only participate in the Transmission Provider’s markets to the extent necessary to \nreceive Energy from the Transmission System and to inject Energy into the Transmission System \nto provide the services for which the SATOA was included in the MTEP.  SATOA may not \notherwise participate in the Energy and Operating Reserve Markets and/or the Planning Resource \nAuction unless and until the Tariff includes provisions for storage facilities recovering cost-\nbased revenues as transmission assets to also participate in these or other Market Activities.  This \nanalysis and planning process shall integrate into the development of the MTEP among other \nthings:  \n(i) the Transmission Issues identified from Facilities Studies carried out in connection"},{"page":570,"startToken":161442,"endToken":161742,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nwith specific transmission service requests; (ii) Transmission Issues associated with \ngenerator interconnection service; (iii) the Transmission Issues, including proposed \ntransmission projects, identified by the Transmission Owners in connection with their \nplanning analyses in accordance with local planning process described in Section I.D.1.a \nto this Attachment FF and the coordination processes of Section I.D.1.b., or developed by \nTransmission Owners utilizing their own FERC-approved local transmission planning \nprocess described in Section I.D.2, as applicable, to provide reliable power supply to their \nconnected load customers and to expand trading opportunities, better integrate the grid \nand alleviate congestion; (iv) the transmission planning obligations of a Transmission \nOwner, imposed by federal or state law(s) or regulatory authorities, which can no longer \nbe performed solely by the Transmission Owner following transfer of functional control \nof its transmission facilities to the Transmission Provider; (v) plans and analyses \ndeveloped by the Transmission Provider to provide for a reliable Transmission System \nand to expand trading opportunities, better integrate the grid and alleviate congestion; (vi) \nthe identification, evaluation, and analysis of expansions to enable the Transmission \nSystem to fully support the simultaneous feasibility of all Stage 1A ARRs; (vii) the inputs \nprovided by the Planning Advisory Committee; (viii) the inputs, if any, provided by the \nstate and local regulatory authorities having jurisdiction over any of the Transmission \nOwners; (ix) the inputs of the OMS Committee; and (x) the transmission needs driven by \npublic policy requirements selected to be included as Transmission Issues pursuant to \nSection I.C.1.b.ii in accordance with Applicable Laws and Regulations.\n1.\nPlanning Cycle and Milestones:  The ISO Agreement requires that a regional"},{"page":571,"startToken":161742,"endToken":161961,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ntransmission plan be developed biennially or more frequently.  An MTEP planning cycle \nis established for each calendar year.  The development of the MTEP for a planning cycle \nwith a given calendar year designation begins on June 1 of the year prior to the MTEP \ncalendar year designation and ends with the approval of the final MTEP report by the \nTransmission Provider Board.  This approval typically occurs at the Transmission \nProvider Board Meeting in December of the MTEP designated year.  For example, the \ndevelopment of the MTEP14 transmission plan will commence on June 1 of 2013 and \ntypically end with approval in December 2014.  The development of the MTEP will \nfollow specified process steps that are detailed, including process diagrams, in the \nTransmission Provider’s Transmission Planning Business Practices Manual (“TPBPM”).  \nThe TPBPM shall be posted on the website of the Transmission Provider.\na.\nPlanning Functions:  The planning process includes the following functions \nwhich are described in detail in the TPBPM:\ni. \nModel Development;\nii. \nGenerator Interconnection Planning;\niii. \nTransmission Service Planning;\niv. \nCyclical Regional Expansion Planning activities;\nv. \nInterregional coordination with neighboring transmission planning \nregions;\nvi. \nSystem Support Resource (“SSR”) Studies for unit de-\ncommissioning;\nvii. \nTransmission-to-Transmission Interconnections;"},{"page":572,"startToken":161961,"endToken":162184,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nviii.\nLoad Interconnections; and\nix.\nFocus Studies.  These are studies initiated during the cyclical \nbaseline planning process that cannot be delayed until the next \nplanning cycle (for example, NERC/FERC directives, or near-term \ncritical operational issues).\nEach of these planning functions may develop system expansions that are taken into \nconsideration in developing the entirety of the MTEP.\nb.\nPlanning Cycle: The regional planning process is performed through a \ncontinuous series of planning cycles, with each cycle typically addressing \nTransmission Issues through a rolling planning horizon.  Each cycle \ncommences with regional model development, identification of potential \nexpansions from the local planning processes of the Transmission Owners, \nidentification and selection of transmission needs driven by public policy \nrequirements pursuant to Section I.C.1.b.ii to be included as Transmission \nIssues, and identification by stakeholders or the Transmission Provider of \npotential expansions that address the Transmission Issues.  Each cycle \nconcludes with recommendations to the Transmission Provider Board of \nrecommended solutions to the Transmission Issues evaluated.  Transmission \nOwner plans developed through local planning processes described in Section \nI.D.1.a are included in the beginning of each regional planning cycle as \npotential alternatives to local Transmission Issues identified by the \nTransmission Owners."},{"page":573,"startToken":162184,"endToken":162409,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ni.\nKey Planning Cycle Milestones:  The regional planning process evaluates, with \nstakeholder input throughout the cycle, the local plans of the Transmission \nOwners, as one input to the development of the regional plan.  Key milestones in \nthe typical MTEP development process are listed below and requirements and \ntimelines for data submittal, review, and comment at each of these milestone \npoints are described in the TPBPM:\n(a)\nModel development;\n(b)\nIdentification and selection of transmission needs driven by public \npolicy requirements pursuant to Section I.C.1.b.ii to be included as \nTransmission Issues;\n(c)\nTesting models against applicable planning criteria;\n(d)\nDevelopment of possible solutions to identified Transmission Issues;\n(e)\nSelection of preferred solution;\n(f)\nDetermination of funding and cost responsibility; and \n(g)\nMonitoring progress on solution implementation.  \nii.\nTransmission needs driven by public policy requirements:  The process for \nselecting transmission needs driven by public policy requirements, out of the \nlarger set of transmission needs driven by public policy requirements that \nstakeholders may propose, to be included in the Transmission Issue(s) for which \ntransmission solutions will be evaluated shall be as follows:\na.\nAt the beginning of the MTEP cycle, stakeholders submit to the \nTransmission Provider, proposals to consider transmission needs"},{"page":574,"startToken":162409,"endToken":162617,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ndriven by public policy requirements, as part of the Transmission \nIssues they may raise, in accordance with Section I.C.2.b, through \nSub-Regional Planning Meetings, the Planning Subcommittee \nand/or the Planning Advisory Committee.  The Transmission \nProvider may also identify transmission needs driven by public \npolicy requirements to be evaluated. \nb.\nThe Transmission Provider will then consolidate all such identified \ntransmission needs driven by public policy requirements that it \nreceives into a list that will be distributed to stakeholders through \nthe Planning Subcommittee and/or the Planning Advisory \nCommittee and to other stakeholder forums as the Transmission \nProvider deems necessary.\nc.\nTransmission needs driven by public policy requirements will be \ndiscussed in the Sub-Regional Planning Meetings, Planning \nSubcommittee and/or the Planning Advisory Committee in \naccordance with Section I.C.2.b.\nd.\nThe Transmission Provider will assess such identified transmission \nneeds driven by public policy requirements that it receives, \nconsidering the feedback received from stakeholders and the Sub-\nRegional Planning Meetings, Planning Subcommittee and/or the \nPlanning Advisory Committee, and select the public policy \nrequirements that will be further studied in the MTEP process."},{"page":575,"startToken":162617,"endToken":162813,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nThis selection will be based on:  \n1.\nthe effective dates, nature and magnitude of the public \npolicy requirements in the Applicable Laws and \nRegulations; \n2.\n the immediacy or other estimated timing, and extent, of the \npotential impact on the identified transmission needs; \n3.\nthe availability of the resources, and any limitations thereto, \nthat would be required by consideration of such \ntransmission needs driven by public policy requirements; \n4.\nthe relative significance of other Transmission Issues that \nhave been raised for consideration; and \n5.\nother appropriate factors that can aid the prioritization of \nTransmission Issues to be considered by the regional \ntransmission planning process.\niii.\nThe Transmission Provider shall address each of these milestones throughout the \nplanning cycle through Sub-regional Planning Meetings, Planning Subcommittee \nand Planning Advisory Committee meetings.\n2.\nStakeholders Input in Planning Process:  The Transmission Provider shall \nfacilitate discussions with its Transmission Customers, Transmission Owners, OMS \nCommittee, and other stakeholders about the Transmission Issues and solutions involving \nboth transferred and non-transferred facilities, as described in Section I.D.1 of this \nAttachment FF."},{"page":576,"startToken":162813,"endToken":163044,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nThese discussions will take place at Sub-regional Planning Meetings and at \nregularly scheduled meetings of the Transmission Provider’s Planning Subcommittee, at \nlocations provided by the Transmission Provider and with communication capabilities for \nthose participants unable to have in person representation at these meetings.  Once the \nMTEP report for a specific planning cycle has been completed but prior to \nrecommendation to the Transmission Provider Board for approval, the Transmission \nProvider shall seek feedback on the proposed MTEP, including Network Upgrades \nrecommended for approval, from the Transmission Provider’s stakeholders and the OMS \nCommittee.\na.\nPlanning Advisory Committee (“PAC”):  The Planning Advisory \nCommittee is a standing committee reporting to the Transmission Provider’s \nAdvisory Committee, and functions subject to the Stakeholder Governance Guide \ndeveloped by the Stakeholder Governance Working Group, as approved by the \nAdvisory Committee.  The PAC is responsible for addressing planning policy \nissues of importance to stakeholders and within the responsibilities of the \nTransmission Provider.  The PAC charter is maintained on the Transmission \nProvider’s website.\nb.\nPlanning Subcommittee (“PS”):  The Planning Subcommittee is a standing \nstakeholder-chaired subcommittee of the Planning Advisory Committee, and \nfunctions subject to the Stakeholder Governance Guide developed by the \nStakeholder Governance Working Group, as approved by the Advisory \nCommittee.  Planning Subcommittee membership is open to interested parties,"},{"page":577,"startToken":163044,"endToken":163301,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nincluding, but not limited to:  transmission delivery service and interconnection \nservice customers, marketers, developers, Transmission Owners, state and local \nregulatory authorities, federal regulatory staff, other Market Participants, and all \ninterested parties.  The charter for the committee is developed by stakeholders and \nis maintained on the Transmission Provider’s website.  The Transmission \nProvider will seek guidance from Transmission Owners, state and local regulatory \nauthorities, and other stakeholders through the Planning Subcommittee and/or the \nPlanning Advisory Committee prior to the beginning of each new planning cycle.  \nGuidance will include the scope of planning studies to be undertaken, the \ndevelopment of future scenarios to be modeled and analyzed in long-term \nplanning studies, and the development of suitable models and assumptions to \nsupport such studies.  The Transmission Provider will also seek guidance from \nTransmission Owners, state and local regulatory authorities, and other \nstakeholders through the Planning Subcommittee and/or the Planning Advisory \nCommittee prior to implementing changes or revisions to the scope, models, and \nassumptions during the planning cycle.  The Planning Subcommittee and/or the \nPlanning Advisory Committee may form working groups at the discretion of \nstakeholders to perform specific tasks supporting the planning processes, such as \nmodel development and detail review of study results and draft plan reports.\nc.\nSub-regional Planning Meetings (“SPMs”):  The Transmission Provider \nshall utilize SPMs to provide opportunity for Transmission Owners, state and \nlocal regulatory authorities, and other stakeholders to provide input to the"},{"page":578,"startToken":163301,"endToken":163534,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nplanning process, and to carry out the tasks of coordinating transmission plans \namong the Transmission Owners and proposals to address the Transmission \nIssues identified in the scope of transmission planning studies.  Input and planned \ncoordination may occur through the use of existing sub-regional planning groups \n(“SPGs”) where they exist, or through the establishment of new sub-regional \nmeeting forums.  One or more SPMs will be used or established for each of the \nfour regional Planning Sub-regions of the Transmission Provider.  Planning Sub-\nregions shall be defined based upon the Transmission Provider Planning Sub-\nregions:  West, Central, South, and East as defined in Attachment FF-3.  \ni)\nSPM Participants:  Participants at an SPM will consist of \nrepresentatives of the Transmission Owners operating within the \nassociated Planning Sub-region that integrate their local planning \nprocesses with the regional process, representatives from state and local \nregulatory authorities, and any other parties interested in or impacted by \nthe planning process.  For those Transmission Owners engaged in local \nplanning under their own FERC approved local planning processes, such \nTransmission Owners shall participate in the SPM in order to coordinate \ntheir planning activities.  \nNeighboring transmission-owning utilities and regulatory participants are \neligible and encouraged to participate in the SPM to promote joint \nplanning between the Transmission Provider and neighboring transmission \nsystems."},{"page":579,"startToken":163534,"endToken":163729,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nii)\nSPM Guidelines.  The Sub-regional Planning Meeting participants \nshall: \n(a)\nMake recommendations for a coordinated sub-regional \nPlan, after considering sub-regional and regional needs and \nalternatives, for the ensuing ten years, for all transmission facilities \nin the sub-region; \n(b)\nReview and comment on proposed Transmission Owners \nplans identified in local planning processes described in Section \nI.D.1.a. of this Attachment FF, for additions and modifications to \nthe sub-regional transmission system, as potential solutions to \nidentify Transmission Issues and review the transmission plans \ndeveloped by those Transmission Owners that have their own \nFERC-approved local planning process (described in Section \nI.D.2) to ensure coordination of the projects set forth in such plans \nwith the potential regional planning solutions developed in the \nSPM process consistent with the requirements of Appendix B of \nthe Transmission Owners’ Agreement; \n(c)\nForm technical study task forces as required to carry out the \nsub-regional planning responsibilities; \n(d)\nEncourage non-Transmission Provider member \nparticipation to improve understanding by the SPM participants, \nthe Planning Subcommittee, and the Transmission Provider staff of"},{"page":580,"startToken":163729,"endToken":163933,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nfacility changes outside the Transmission Provider Region to \nensure the impact of such changes are considered in the planning \nstudies; \n(e)\nPromote other stakeholder (i.e., environmental agencies, \nand load and generation developers) involvement in development \nof the sub-regional plans. \n(f)\nRecommend to the Planning Subcommittee proposed sub-\nregional plans to be included in the MTEP.  In addition, the \ntransmission projects developed by any Transmission Owner or \nOwners utilizing the provisions of their own FERC-approved local \nplanning process shall be submitted for inclusion in the regional \nMTEP after being evaluated by the Transmission Provider in the \nregional evaluation of SPMs in accordance with Appendix B of the \nTransmission Owners’ Agreement in determining the Transmission \nProvider’s recommendation for inclusion in the MTEP.\n(g)\nReflect, as desired, minority opinions to the Transmission \nProvider or the Planning Subcommittee.  \n(h)\nSPM Frequency, Location and Agenda:  SPMs should meet \nat least two times per year or as otherwise provided for in the \nTPBPM, to provide input in the planning process, review plans and \nrecommend changes, if any, needed to address stakeholder needs \nand to coordinate proposed plans."},{"page":581,"startToken":163933,"endToken":164205,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nMeetings involving CEII or confidential materials shall be handled \nunder Section I.C.12 of this Attachment FF.    \n3.\nMeeting Notifications:  Notice shall be provided by way of email distribution lists \nby the Transmission Provider of all SPMs, Planning Subcommittee, and Planning \nAdvisory Committee meetings.  These email distribution lists are established and \nmaintained by the Transmission Provider and it is the responsibility of stakeholders to \nhave registered as described on the Transmission Provider website.  Meeting dates, times, \nlocations, and materials will also be posted on the meeting calendar page of the \nTransmission Provider’s website.  Meeting notification guidelines are set forth in the \nstakeholder developed Stakeholder Governance Guidelines. \n4.\nOther Meeting Schedules:  Planning Subcommittee meetings are regularly \nscheduled meetings that occur no less than bimonthly.  Annual meeting schedules and \nobjectives are developed at the December meeting each year for the subsequent year.  \nPlanning Advisory Committee meetings are scheduled as per the PAC Charter. \n5.\nPlanning Criteria:  The Transmission Provider shall evaluate the system to \naddress Transmission Issues in a manner consistent with the ISO Agreement and this \nAttachment FF.  Projects included in the MTEP may be based upon any applicable \nplanning criteria, including accepted NERC reliability standards and reliability standards \nadopted by Regional Entities, local planning reliability or economic planning criteria of \nthe Transmission Owner, or required by State or local authorities, any economic or other \nplanning criteria or metrics defined in this Attachment FF, and any Applicable Laws and \nRegulations.  Transmission Owners are required to annually provide updated copies of"},{"page":582,"startToken":164205,"endToken":164467,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nlocal planning criteria for posting on the Transmission Provider’s website.\nThe Transmission Provider will post on its website an explanation of which transmission \nneeds driven by public policy requirements will be evaluated for potential solutions in the \nlocal or regional transmission planning process, as well as an explanation of why other \nsuggested potential transmission needs will not be evaluated.\n6.\nPlanning Analysis Methods:  Planning analyses performed by the Transmission \nProvider will test the Transmission System under a wide variety of conditions as \ndescribed in Section II and using standard industry applications to model steady state \npower flow, angular and voltage stability, short-circuit, and economic parameters, as \ndetermined appropriate by the Transmission Provider to be compliant with applicable \ncriteria and this Tariff. \n7.\nPlanning Models:  The Transmission Provider shall collaborate with Transmission \nOwners, other transmission providers, Transmission Customers, and other stakeholders to \ndevelop appropriate planning models that reflect expected system conditions for the \nplanning horizon.  The planning models shall reflect the projected Load growth of \nexisting Network Customers and other transmission service and interconnection \ncommitments.  The models shall include:  (1) any transmission projects identified in \nService Agreements or Interconnection Agreements that are entered into in association \nwith requests for transmission delivery service or interconnection service, as determined \nin Facilities Studies associated with such requests, and (2) MHVDC Transmission Lines \nwith executed Transmission Connection Agreements.  Load forecasts applied to models \nwill consider the forecast Load of Network Customers reported to the Transmission"},{"page":583,"startToken":164467,"endToken":164724,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nProvider in accordance with the requirements of Module B and RAR of this Tariff, and \nthe Business Practices Manuals of the Transmission Provider.  Models will be posted on \na secure application maintained by the Transmission Provider and accessible to \nstakeholders with security measures as provided for in the TPBPM.  The Transmission \nProvider will provide an opportunity for stakeholders to review and comment on the \nposted models before commencing planning studies.  \nThe schedules for such reviews are maintained in the TPBPM.  Stakeholders shall be \nafforded opportunities to provide input on Load projections from Tariff reporting \nrequirements or from Transmission Owner forecasts.  After the base line forecast and \nmodel are established, the Transmission Provider and/or Transmission Owners may \nadjust the forecast as necessary on an ad hoc basis throughout the planning year to \naddress customer requests for new Load interconnections arising from on-going dialogue \nwith existing and prospective customers.\n8.\nPlanning Assumptions:  Each MTEP report shall list in detail the planning \nassumptions upon which the analyses are based.  In general, planning analyses will be \nbased on the following:\na.\nPlanning Horizons:  The MTEP will identify Transmission Issues for a \nminimum planning horizon of five years and a maximum planning horizon of \ntwenty years.\nb.\nLoad:  Load demand will generally be modeled by the Transmission \nProvider as the most probable (“50/50”) coincident Load projection for each \nTransmission Owner’s service territory, for the season under study.  Specific"},{"page":584,"startToken":164724,"endToken":164965,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nstudies may model alternative Load probabilities or peak Load for areas within a \nTransmission Owner’s service territory as dictated by operational and planning \nexperience and/or local planning criteria, but in any case shall be treated \nconsistently in the planning for native Load and transmission access requests.  \nc.\nGeneration:  Planning models of five years or longer will model \ngeneration, taking into consideration applicable planning reserve requirements, \nthat are: (i) existing and expected to be in existence in the planning horizon; (ii) \nnot existing but with executed interconnection agreements;  (iii) associated with \nMHVDC Transmission Lines with executed Transmission Connection \nAgreements, and (iv) additional generation as determined with stakeholder input, \nas necessary to adequately and efficiently meet demand forecasted through the \nplanning horizon and to facilitate compliance with statutory or regulatory \nmandates.  The Transmission Provider shall apply a scenario analysis to \ndetermine alternative future generation portfolio possibilities.  \nGeneration portfolio development for planning model purposes will be developed \nwith input from the Planning Advisory Committee and its subcommittees, \nworking groups, and task forces.  Point-To-Point Transmission Service and \nNetwork Integration Transmission Service customers will have an opportunity to \nguide new generation portfolio development that is reflective of customer future \nresource plans.  \nd.\nDemand Response Resources:  Planning solutions will be based upon the \nbest available information regarding the expected amount and location of Load"},{"page":585,"startToken":164965,"endToken":165219,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nthat can be effectively and efficiently reduced by demand response or energy \nefficiency programs, as well as the amount of behind-the-meter generation that \ncan reliably be expected to produce Energy that could impact planning solutions.  \nThe Transmission Provider shall perform and report on sensitivity analyses that \nindicate the effectiveness of potential demand response as alternative planning \nsolutions, to the extent that appropriate methodology for such analyses is \ndeveloped with stakeholders and documented in the TPBPM.\ne.\nTopology:  Each planning study will use the best known topology based \nupon the most recently approved MTEP.  Planning studies will include all \nprojects approved by the Transmission Provider Board, and shall identify, as \nappropriate, and as detailed in the TPBPM, any system needs already identified in \nthe most recent approved MTEP.  \n9.\nEvaluation of Alternatives:  When the planning analyses, based on the foregoing \nprinciples, identifies Transmission Issues, the Transmission Provider will consider the \ninputs from stakeholders derived from the SPM processes, the inputs from the Planning \nSubcommittee and the Planning Advisory Committee, the plans of any Transmission \nOwner with its own FERC-approved local planning process, and the MTEP aggregate \nsystem analyses against applicable planning criteria, in determining the solutions to be \nincluded in the MTEP and recommended to the Transmission Provider Board for \nimplementation.  \n10.\nFacility Design:  Facility design and system configuration (such as conductor \nsizes, transformer design, bus configuration, protection schemes) are selected by the"},{"page":586,"startToken":165219,"endToken":165486,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nTransmission Owner, and must be consistently applied by the Transmission Owner for \ncomparable system service conditions.  Comparable application of system design does \nnot preclude the consideration or selection of advanced or alternative transmission \ntechnology.  For Competitive Transmission Facilities associated with Competitive \nTransmission Projects, the Transmission Provider may provide limitations or \nrequirements regarding facility design when necessary due to a planning driver or to \nensure compatibility with existing transmission facilities to which the Competitive \nTransmission Facilities will interconnect as further described in Section VIII.C.2.c of this \nAttachment FF.\n11.\nStatus of Recommended Facilities:  The status of all project facilities \nrecommended for implementation in the MTEP shall be reported to the Transmission \nProvider on a quarterly basis and upon solicitation from the Transmission Provider.  Each \nSelected Developer and Transmission Owner is required to provide such status updates \nregarding the facilities for which it is responsible to construct to the Transmission \nProvider as further specified in this Section I.C.11 of Attachment FF of the Tariff and the \nBusiness Practices Manuals. \nThe Transmission Provider shall report on such status to the Transmission \nProvider Board on a quarterly basis, or as otherwise directed by the Transmission \nProvider Board.  The Transmission Provider shall also publicly post such status in a form \nconsistent with the Business Practices Manuals to the Transmission Provider’s website on \na quarterly basis, redacting any CEII and/or confidential information as necessary.  \n(a)\nStatus of Eligible Project facilities approved after December 1, 2015:"},{"page":587,"startToken":165486,"endToken":165790,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nEach Selected Developer and incumbent Transmission Owner shall provide \nquarterly status reports to the Transmission Provider regarding the facilities included in \nan Eligible Project approved after December 1st, 2015 for which it is responsible to \nconstruct until the quarter after all such facilities have been placed into service and \ntransferred to the Transmission Provider’s functional control, or the facilities and/or\nEligible Project are otherwise reassigned, canceled, or terminated.\nQuarterly status reports shall conform to the format set forth in the Business \nPractices Manuals and include, at a minimum, the following: (i) project schedule, \nincluding each facility’s estimated in-service date and any material changes therein; (ii) \nestimated project costs, including the estimated cost to complete each facility, any \nmaterial changes therein as compared to the applicable Baseline Cost Estimate as set \nforth in Section IX.C.1.1, the total project expenditures to date, and the total project \nexpenditures to date expressed as a percentage of the Baseline Cost Estimate, as set forth \nin Section IX.C.1.1; (iii) facility development status (i.e. under construction, in service, \ncompleted, or withdrawn); (iv) status of obtaining necessary regulatory and or \nenvironmental permits, certificates, or approvals, including meeting necessary licensing \nrequirements; (v) status of land and right-of-way acquisition; (vi) status of design and \nengineering; (vii) status of any necessary interconnection agreements; (viii) an \nexplanation of the causes of, or reasons for, any material changes to or deviations from \nthe MTEP in-service date, Baseline Cost-Estimate as set forth in Section IX.C.1.1, and \ninformation provided in the last quarterly status report; and (ix) an assessment of the \nimpact of any material changes on the project, including the continued ability to meet the"},{"page":588,"startToken":165790,"endToken":166058,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nMTEP in-service date. \nWithin one hundred eighty (180) Calendar Days after the date the Selected \nDeveloper or Transmission Owner have placed all of the facilities included in a Eligible \nProject for which it is responsible to construct into service, including the transfer of \nfunctional control to the Transmission Provider, unless the Transmission Provider and \nSelected Developer or Transmission Owner agree on a different date, shall provide the \nTransmission Provider with the following:\n1. the final costs to construct the facilities;\n2. copies of the final “as-built” drawings and specifications of the facilities;\n3. copies of any inspection reports performed on the facilities; and\n4. geo-spatial information specific to the facilities (i.e. GIS compatible maps,\nGPS coordinates, etc.)  \n(b) \nAdditional status requirements for Competitive Transmission Facilities:\nIn addition to the requirements specified above in Section I.C.11.a of Attachment \nFF, each Selected Developer shall also include in its status reports the following:  \n(i) status of any necessary project financing; (ii) the percentage (%) of the total project\nexpenditures to date as compared to the total projected project cost schedule provided in \nthe Selected Proposal; (iii) whether any rate filings associated with the Competitive \nTransmission Facilities were made during the previous quarter or expected to be made in \nthe upcoming quarter; (iv) any changes in the continuing ability to meet the obligations of \nthe Selected Developer Agreement according to the schedules and milestones agreed to \ntherein, including any binding cost-containment measures that were included in the"},{"page":589,"startToken":166058,"endToken":166347,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nSelected Proposal; (v) an explanation of the causes of, or reasons for, any changes from \nthe specifications included in the Selected Proposal; and (vi) an assessment of the impact \nof any such changes on the Competitive Transmission Facilities included in the \nCompetitive Transmission Project.\n(c) \nStatus of all other facilities recommended for implementation in the MTEP:\nThe requirements and obligations set forth in this section I.C.11.c of Attachment\nFF, shall be applicable to all facilities recommended for implementation in the MTEP \nexcept for those facilities that are included in an Eligible Project approved by the \nTransmission Provider Board after December 1, 2015.\nEach incumbent Transmission Owner shall provide status reports to the \nTransmission Provider regarding the facilities that are included in projects other than \nthose specified in Attachment FF §I.C.11.a for which it is responsible to construct, until \nthe quarter after such facilities have been placed into service and transferred to the \nTransmission Provider’s functional control. Status reports shall conform to the format set \nforth in the Business Practices Manuals and at a minimum, include the following: (i) \nmaterial changes to the schedule and to the estimated project cost; (ii) an explanation of \nthe causes of, or reasons for, any such changes; and (iii) changes in project status (i.e., \nunder construction, in service, completed, or withdrawn).  The Transmission Provider \nshall report such progress to the Transmission Provider Board on a quarterly basis, or as \notherwise directed by the Transmission Provider Board.  \n12.\nTreatment of Critical Energy Infrastructure Information (“CEII”) and Confidential \nData:  The Transmission Provider shall utilize appropriate Non-Disclosure and"},{"page":590,"startToken":166347,"endToken":166642,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nConfidentiality Agreements (“NDA”) to address sharing of Confidential Information and \nCEII transmission planning information.  The secured sites containing such information \nwill require such agreements to be executed in order to obtain access to those \napplications.  Stakeholder meetings at which CEII may be available shall be noticed to \nemail distribution lists and shall require execution of NDAs prior to participation in such \nmeetings.  In the alternative, such meetings will be structured to have separate discussion \nof issues involving CEII data only with participants that agree to execute the NDA.  \nConfidential information related to economic (e.g., congestion) studies, as well as CEII, \nis clearly sensitive information which must remain confidential.  The Transmission \nProvider shall use generic, publicly available, cost information from industry sources in \nthe economic studies to prevent the accidental release of confidential information.  This \napproach will promote an open planning process because the results of economic studies \nare available to all interested parties.\nEntities that are members of any stakeholder sector of the Advisory Committee \nshall, upon request and subject to execution of the appropriate NDA(s), be provided with \naccess to the data used by the Transmission Provider to develop the MISO Transmission \nExpansion Plan designated as Confidential Information and/or CEII.  Access, which shall \nbe described in the Transmission Planning Business Practices Manual, shall be subject to: \n(1) the prior execution of all appropriate NDAs required by the Transmission Provider to \nprotect Confidential Information as well as CEII by persons authorized by the sector \nmember to receive transmission planning information on the sector member’s behalf and \n(2) any provisions of this Tariff or the applicable Business Practice Manuals that govern"},{"page":591,"startToken":166642,"endToken":166952,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\naccess to or use of the type of information for which access is sought.  The provisions of \nthis Section I.C.12 are not exclusive and do not diminish the right of any stakeholder to \naccess Confidential Information or CEII under any other authorizing provision of the \nTariff, Business Practices Manuals, or FERC order.\n13.\nResolution of Stakeholder Input:  The Transmission Provider shall solicit input \nand comments from all stakeholders, including Transmission Owners, during and after \nstakeholder planning meetings, and will use reasonable efforts to reply to comments that \nthe Transmission Provider does not elect to implement, together with reasons for such \nactions.  The Transmission Provider shall develop a process for the documentation and \nresolution of stakeholder issues raised in the planning process, including but not limited \nto issues related to planning criteria.\n14.\nDispute resolution:  Consistent with Attachment HH of this Tariff, the \nTransmission Provider shall resolve disputes concerning MTEP issues.  The first step will \nbe for designated representatives of the affected parties to work together to resolve the \nrelevant issues in a manner that is acceptable to all parties.  If that step is unsuccessful, \neach affected party shall designate an officer who shall review disputes involving them \nthat their designated representatives are unable to resolve.  The applicable officers of the \nparties involved in such dispute shall work together to resolve the disputes so referred in \na manner that meets the interests of such parties, either until such agreement is reached, \nor until an impasse is declared by any party to such dispute.  If such officers are unable to \nsatisfactorily resolve the issues, the matter shall be referred to mediation.  Parties that are \nnot satisfied with the dispute resolution procedures may only file a complaint with the"},{"page":592,"startToken":166952,"endToken":167243,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nCommission during the negotiation or mediation steps.  \nIf a matter remains unresolved, the affected parties may pursue arbitration.\nD.\nProject Coordination:  In the course of the MTEP process, the Transmission \nProvider shall seek out opportunities to coordinate or consolidate, where possible, individually \ndefined transmission projects into more comprehensive cost-effective developments subject to \nthe limitations imposed by prior commitments and lead-time constraints.  The Transmission \nProvider shall coordinate with Transmission Owners, and shall consider the input from the \nSPMs, Planning Subcommittee, and Planning Advisory Committee to develop expansion plans \nto meet the needs of the system.  This multi-party collaborative process will allow for all projects \nwith regional and inter-regional impact to be analyzed for their combined effects on the \nTransmission System.  Moreover, this collaborative process is designed to ensure that the MTEP \naddress Transmission Issues within the applicable planning horizon in the most efficient and cost \neffective manner, while giving consideration to the inputs from all stakeholders.  In addition to \nthe requirements of this Attachment FF, there may be state or local procedural requirements \napplicable to the planning or siting of transmission facilities by the Transmission Owners.  A \ncurrent list of those requirements can be found on the Transmission Provider’s website.\n1.\nTransmission Owners Electing to Integrate their Local Planning Processes into the \nTransmission Provider’s Processes:  Some Transmission Owners have agreed to integrate \ninternal planning process with the Transmission Provider’s open and coordinated \nplanning processes for all of their transmission facilities to comply with Order 890 \nPlanning Principles instead of filing a  separate Attachment K.  Through this election, the \nlocal planning for all transmission facilities of these Transmission Owners, regardless of"},{"page":593,"startToken":167243,"endToken":167520,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nwhether the facilities are ultimately transferred to the functional control of the \nTransmission Provider, shall be integrated with and included in the regional planning \nprocesses of the Transmission Provider.  These regional planning processes, as provided \nfor in this Attachment FF and in additional detail in the TPBPM, ensure that the planning \ndecisions for all such facilities are made in an open and transparent environment.\nThis planning environment provides opportunity for input from, and review by, \nstakeholders of the Open Access Transmission Tariff services throughout the planning \nprocess, and is in accordance with the Planning Principles of the Order 890 Final Rule.  \nThe open and transparent planning provisions of this Attachment FF shall not preclude \ninteraction between stakeholders and Transmission Owners prior to the submittal of \nproposed projects to the regional planning process.\nTransmission Owners integrating local planning processes into the regional \nplanning processes are listed in Attachment FF-4.  Such Transmission Owners shall be \nresponsible for providing the Transmission Provider with sufficient information \nregarding all planning activities to enable the Transmission Provider to adequately review \nand incorporate all of the Transmission Owner’s transmission facilities into the regional \nplanning process of the Transmission Provider, as described in Sections I.D.1.a. and \nI.D.1.b. of this Attachment FF.  \nThe foregoing Transmission Owners will utilize the planning stakeholder forums \nof the Transmission Provider to demonstrate the need for, identify the alternatives to, and \nreport the status of non-transferred transmission facilities using the same open, \ntransparent and coordinated planning process provided by the Transmission Provider for"},{"page":594,"startToken":167520,"endToken":167763,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ntransferred facilities as described in this Attachment FF. \na.\nLocal Planning Processes of Transmission Owners:  In accordance with \nthe ISO Agreement, each Transmission Owner engages in local system planning in order \nto carry out its responsibility for meeting its respective transmission needs in \ncollaboration with the Transmission Provider subject to the requirements of applicable \nstate law or regulatory authority.  In meeting its responsibilities under the ISO \nAgreement, the Transmission Owners may, as appropriate, develop and propose plans \ninvolving modifications to any of the Transmission Owner’s transmission facilities which \nare part of the Transmission System.  The Transmission Owners shall include the \nfollowing specific local planning steps in order to develop plans for potential inclusion in \nthe regional plan, in accordance with the annual regional planning process as described in \nSection I.D.1.b. of this Attachment FF, and in accordance with the regional planning \nprinciples of Section I.C of this Attachment.  In addition to the local planning steps \nbelow, Transmission Owners shall adhere to any applicable state or local regulatory \nplanning processes.   \ni.\nDefine local study area and study horizon; \nii.\nDevelop appropriate power system models;\na)\nUtilize existing NERC or Transmission Provider cases to model \nexternal systems;\nb)\nInsert detailed model of Transmission Owner system if required;\nc)\nInsert updated detailed models of neighboring system models if \nrequired; and"},{"page":595,"startToken":167763,"endToken":167963,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nd)\nVerify model topology and generation.\niii.\nUpdate loads (spatial and magnitude) in study area;\na)\nReview historical MW and MVAR data to develop growth trends;\nb)\nObtain Load forecasts from customers in study area; and\nc)\nObtain input from local distribution planners in the study area.\niv.\nPerform contingency analysis using applicable Transmission Owner \nplanning criteria;\nv.\nIdentify any violations to planning criteria for each of study period;\nvi.\nDevelop alternative solutions to the criteria violations and test against the \nplanning criteria;\na)\nObtain cost estimates for each alternative and perform economic \nanalyses; and \nb)\nDetermine non-cost attributes of each alternative such as operating \nflexibility, robustness, among others.\nvii.\nSelect alternative based on cost and non-cost attributes;\nviii.\nSubmit proposed solution and list of alternatives and assumptions to the \nTransmission Provider;\nix.\nParticipate in stakeholder evaluations and discussions as a part of annual \nregional plan development process;\nx.\nPerform additional analysis as required based on feedback from \nstakeholder groups (SPM/PS) in the regional planning process;\nxi.\nSubmit results of additional analysis (if performed) to the Transmission"},{"page":596,"startToken":167963,"endToken":168223,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nProvider for further discussion with stakeholders (SPM/PS); \nxii.\nConsider regional planning process results, including stakeholder feedback \non needs, proposed solutions, and alternatives, in determining whether or not to \nproceed with implementation of Transmission Owner proposed expansions; and\nxiii.\nPost the planning criteria and assumptions, and power flow models used in \ndevelopment of each Transmission Owner’s current local planning proposal in \naccordance with Section I.D.1.b below.  To the extent that the Transmission \nOwner uses the MISO MTEP models in developing its list of newly proposed \nprojects, the Transmission Owner shall indicate as per Section I.D.1.b. below, the \nassociated MTEP model used.  \nThe Transmission Provider will maintain a link to applicable MTEP \nmodels on its website together with instructions for accessing such models \nconsistent with CEII criteria and suitable non-disclosure agreements.  In the event \nthat the Transmission Owner applies its own power flow models in developing its \nproposed local plans, the Transmission Owner shall provide such models to the \nTransmission Provider for posting, or shall provide to the Transmission Provider a \nlink to the location of such Transmission Owner model(s) and to instructions for \naccessing such models consistent with the Transmission Owner’s CEII and non-\ndisclosure requirements.  Transmission Provider shall post on its website links to \nsuch postings on Transmission Owner’s website.\nb.\nIntegration of Local Planning Processes of Transmission Owners:  \nTransmission Owners listed on Attachment FF-4 as integrating local planning processes"},{"page":597,"startToken":168223,"endToken":168535,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nwith those of the Transmission Provider, shall integrate proposals for transmission \nexpansions into the regional planning process as follows.  Each Transmission Owner \nshall submit its proposals for transmission plans to the Transmission Provider prior to the \nstart of each regional planning cycle.  Each Transmission Owner’s local plan, which \nconsists of a list of proposed projects, shall be made available on the Transmission \nProvider’s website for review by the PAC, the PS, and the SPM participants, subject to \nCEII and the confidentiality provisions in this Attachment FF.  Such local plans shall be \nposted by September 15 each year in order to provide time for written comments by \nstakeholders.  In addition to the list of proposed projects, each Transmission Owner \nsubmitting newly proposed projects by September 15 in any MTEP annual cycle shall \nprovide to the Transmission Provider by June 1 of the same year identification of any \nMISO base power flow model used by the Transmission Owner in support of the \nidentification of the list of proposed projects to be subsequently posted in September, or \nin the event that the Transmission Owner uses a non-MISO base power flow model in \nsupport of the identification of the list of proposed projects the Transmission Owner shall \nprovide to the Transmission Provider such base power flow model or a link to the power \nflow model and assumptions used.\nEach Transmission Owner’s local planning model and associated assumptions \nshall be accessible on or through a link on the Transmission Provider’s website for \nreview, subject to CEII and the confidentiality provisions in this Attachment FF and \nconsistent with section I.D.1.a.  In the event that the Transmission Owner uses a non-\nMISO base power flow model, the Transmission Owner shall provide for posting updates"},{"page":598,"startToken":168535,"endToken":168836,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nif there are significant changes in the model by July 15, August 15, and September 15 of \neach year.  Comments by stakeholders on the local planning models and assumptions that \nare provided to the Transmission Provider SPM Planning Contact by July 1, or August 1 \nor September 1 with respect to updates, shall be forwarded to the applicable Transmission \nOwner by July 8, August 8, or September 8, respectively.  The Transmission Provider \nshall address any unresolved stakeholder issues through the SPM process.\nEach Transmission Owner shall also provide to the Transmission Provider by June 1 of \neach year any updates to the posted transmission planning criteria, or a notification that \nthe posted documents have not changed.  In the event a Transmission Owner has \nadditional significant updates to the posted transmission planning criteria, the \nTransmission Owner shall provide such updates for posting by July 15, August 15, and \nSeptember 15 of each year.  \nThe Transmission Provider shall post on its website the lists of newly proposed \nprojects, criteria and assumptions, and supporting base power flow models or links to \nsupporting base power flow models, as provided by the Transmission Owners.  Initial \ncomments by stakeholders to the proposed projects should be provided to the \nTransmission Provider SPM Planning Contact 45 days after the posting of local plans \notherwise comments may be made pursuant to Section I.C.2.c.ii.  The Transmission \nProvider SPM Planning Contact shall be identified on the Transmission Provider’s web \nsite page devoted to Expansion Planning.  The Transmission Provider shall provide to the \napplicable Transmission Owner within five working days of receipt, a copy of all \nstakeholder comments received within 45 days of the posted information regarding"},{"page":599,"startToken":168836,"endToken":169113,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nTransmission Owner planning criteria and assumptions, models applied, and list of \nproposed projects.  The Transmission Provider shall address any unresolved stakeholder \nissues through the SPM process.  Each Transmission Owner must participate in SPMs in \nthe respective Planning sub-region as indicated in the Transmission Providers meeting \nschedule.  Such SPMs shall provide input to and review of the results of the needs \nassessments and adequacy of plans proposed by the Transmission Owners, or by \nstakeholders to the planning process, or by the Transmission Provider, to best meet the \nneeds of the sub-region. \nTransmission Owners identified in Attachment FF-4, must submit to the \nTransmission Provider, on an annual basis and at a time to be determined by the \nTransmission Provider, which shall be prior to the beginning of each regional planning \ncycle, all proposed transmission plans for both transferred and non-transferred \ntransmission facilities.  The submitted projects of such Transmission Owners shall be \nconsidered potential alternatives to system needs identified, and as such must be \nsubmitted when initially identified as a potential system solution, in order to permit the \nevaluation of such projects along with other potential alternatives that may be proposed \nby stakeholders or the Transmission Provider, in the SPM processes.  Such alternatives \nmay include transmission, generation, and demand-side resources.  The Transmission \nProvider will review and evaluate such alternatives on a comparable basis and select the \nmost appropriate solution. Comparability includes the ability of the Transmission \nProvider to obtain contractual assurances that the selected solution will be implemented \nby the required in-service dates.  Contractual commitments associated with the"},{"page":600,"startToken":169113,"endToken":169410,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nconstruction of an MTEP Appendix A approved project by MISO Transmission Owner(s) \nand/or Selected Developer(s) are provided for by the ISO Agreement, this Tariff, and the \nSelected Developer Agreement.  \nContractual commitments associated with generation solutions require that a \ngenerator interconnection agreement be filed with the Commission pursuant to \nAttachment X of this Tariff by the time the alternative transmission solution would need \nto be committed to in order to ensure installation on the required need date.  Contractual \ncommitments associated with ZG Associated Load require demonstration to the \nTransmission Provider of both: (1)  an executed agreement between the entity with the \nZG Associated Load and the Generating Facility with the associated ZG Interconnection \nService as described in Section 3.11 of Attachment X to the Tariff is in place and must \nspan at least the five year planning horizon to ensure the ability to provide adequate lead \ntime for an alternative transmission solution should the contracts terminate; and (2) that \nthe Generating Facility associated with the ZG Associated Load has achieved \nCommercial Operation by the time that the transmission solution would otherwise need to \nbe in service.  In the event that the Generating Facility associated with the ZG Associated \nLoad fails to achieve Commercial Operation by the date that the transmission solution \nwould otherwise need to be in service or the contract between the ZG Associated Load \nand the associated Generating Facility terminates, then the Transmission Provider may \nrequire the applicable Load Serving Entity to delay the in-service date of ZG Associated \nLoad until such time as an alternative solution can be placed in service.\nContractual commitments associated with demand-side resource solutions require"},{"page":601,"startToken":169410,"endToken":169698,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ndemonstration to the Transmission Provider of an executed contract between LSE and \nEnd-Use Customers.  Such demand-side contracts must be in place by the time that the \ntransmission solution would otherwise need to be committed to in order to ensure a \ntimely solution to the identified planning need, and must span the five year planning \nhorizon to ensure the ability to provide adequate lead time for an alternative transmission \nsolution should the demand contracts terminate.  Notwithstanding the provisions of \nSection VII of the ISO Agreement regarding the Transmission Provider review of \nTransmission Owner plans, no proposed project of a Transmission Owner that has elected \nto integrate their local planning processes into the Transmission Provider’s processes, as \nindicated on Attachment FF-4, shall be recommended in the MTEP for implementation \nuntil completion of the annual needs analysis carried out in the annual MTEP cycle, as \ndescribed in Section I.C. of this Attachment FF, except as provided for in Section I.D.1.c. \nof this Attachment FF.  \nc.\nOut-of-Cycle Review of Transmission Owner Plans:  In the event that a \nTransmission Owner determines that system conditions warrant the urgent development \nof system enhancements that would be jeopardized unless the Transmission Provider \nperforms an expedited review of the impacts of the project,  Transmission Provider shall \nuse a streamlined approval process for reviewing and approving projects proposed by the \nTransmission Owners so that decisions will be provided to the Owner within thirty (30) \ndays of the projects submittal to the MISO unless a longer review period is mutually \nagreed upon.\n2.\nTransmission Owners Filing Separate Attachment K:  Some Transmission Owners as"},{"page":602,"startToken":169698,"endToken":169994,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nlisted on the last page of Attachment FF-5 have developed individual open, local planning \nprocesses for their facilities, that comply with the Planning Principles of the Order 890 Final \nRule.  These Transmission Owners have an Attachment K that describes how the Transmission \nOwner will comply with the Order No. 890 Planning Principles for all transmission facilities that \nthey plan for, regardless of whether those facilities are ultimately transferred to the functional \ncontrol of the Transmission Provider.  With the exception of Sections I.D.1.a and I.D.1.b., the \nprovisions of this Attachment FF remain applicable to all Transmission Owners notwithstanding \nthe filing by any Transmission Owner of an Attachment K pursuant to the Order 890 Final Rule.\nE.\nInterregional  Coordination and Cost Allocation:  The MTEP shall be \ndeveloped in accordance with the principles of interregional coordination through collaboration \nwith representatives from adjacent transmission providers, their designated regional planning \norganizations, or regional transmission organizations, as provided for in this Attachment FF, or \nas otherwise provided for in existing joint agreements between the Transmission Provider and \nother regional entities that engage in planning activities.  The Transmission Provider has \ndeveloped region-specific interregional coordination and cost allocation provisions with regard \nto the following neighboring transmission planning regions: \n•\nPJM Interconnection, L.L.C. (“PJM”), as provided for under Article IX and other applicable \nprovisions of the Joint Operating Agreement between the Transmission Provider and PJM; \n•\nSoutheastern Regional Transmission Planning (“SERTP”), as provided for under Section X \nof this Attachment FF; and \n•\nSouthwest Power Pool (“SPP”), as provided for under Article IX and other applicable \nprovisions of the Joint Operating Agreement between the Transmission Provider and SPP."},{"page":603,"startToken":169994,"endToken":170252,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nThe Transmission Provider also has planning coordination provisions as part of its \ncoordination agreement with Manitoba Hydro. \nII.\nDevelopment Process for MTEP Projects:  The Transmission Provider will develop the \nMTEP biennially or more frequently.  The MTEP will identify expansion projects for inclusion \nin the MTEP according to the factors set forth in Appendix B of the ISO Agreement and Section \nI.C of this Attachment FF.  For purposes of assigning cost responsibility, expansion projects in \nthe MTEP shall be categorized pursuant to the following criteria.\nA.\nReliability Needs:  Reliability projects are identified either in the periodically performed \nBaseline Reliability Study, or in Facilities Studies associated with the request processes for new \ntransmission access.  Transmission access includes requests for both new transmission delivery \nservice and new generation interconnection service.\n1.\nBaseline Reliability Projects:  Baseline Reliability Projects are \nNetwork Upgrades identified in the base case as required to ensure that the \nTransmission System is in compliance with applicable national Electric \nReliability Organization (“ERO”) reliability standards and reliability standards \nadopted by Regional Reliability Organizations and applicable within the \nTransmission Provider Region.  Baseline Reliability Projects include projects that \nare needed to maintain reliability while accommodating the ongoing needs of \nexisting Market Participants and Transmission Customers.  Baseline Reliability \nProjects may consist of a number of individual facilities that in the judgment of \nthe Transmission Provider constitute a single project for cost allocation purposes.  \nThe Transmission Provider shall collaborate with Transmission Owning"},{"page":604,"startToken":170252,"endToken":170486,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nmembers, other transmission providers, Transmission Customers, and other \nstakeholders to develop appropriate planning models that reflect expected system \nconditions for the planning horizon.  The planning models shall reflect the \nprojected load growth of existing network customers and other transmission \nservice and interconnection commitments, and shall include any transmission \nprojects identified in Service Agreements or interconnection agreements that are \nentered into in association with requests for transmission delivery service or \ntransmission interconnection service, as determined in Facilities Studies \nassociated with such requests, and MHVDC Transmission Lines with executed \nTransmission Connection Agreements.  The Transmission Provider shall test the \nMTEP for adequacy and security based on commonly applicable national Electric \nReliability Organization (“ERO”) standards, and under likely and possible \ndispatch patterns of actual and projected Generation Resources within the \nTransmission System and of external resources, including dispatch reflective of \nLong-Term Transmission Rights of Transmission Customers, and shall produce \nan efficient expansion plan that includes all Baseline Reliability Projects \ndetermined by the Transmission Provider to be necessary through the planning \nhorizon of the MTEP.  The Transmission Provider shall obtain the approval of the \nTransmission Provider Board, as set forth in Section VI, for each MTEP \npublished.\n2.\nNew Transmission Access Projects:  New Transmission Access \nProjects are defined for the purposes of Attachment FF as Network Upgrades"},{"page":605,"startToken":170486,"endToken":170754,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nidentified in Facilities Studies and agreements pursuant to requests for \ntransmission delivery service or transmission interconnection service under the \nTariff and also include JTIQ Upgrades.  New Transmission Access Projects \ninclude projects that are needed to maintain reliability while accommodating the \nincremental needs associated with requests for new transmission or \ninterconnection service, as determined in Facilities Studies associated with such \nrequests and/or were identified as JTIQ Upgrades.  New Transmission Access \nProjects may consist of a number of individual facilities, which in the judgment of \nthe Transmission Provider constitute a single project for cost allocation purposes.  \nNew Transmission Access Projects are either Generation Interconnection Projects \nor Transmission Delivery Service Projects as defined in Sections II.A.2.a. and \nII.A.2.b.  The Transmission Provider shall consider the Baseline Reliability \nProjects already determined to be needed in the most current MTEP, as well as \nany other base-case needs not associated with the request for new service that \nmay be identified during the impact study process when determining the need for \nNew Transmission Access Projects.  Any identified base-case needs determined \nin the impact study process that are not a part of the Baseline Reliability Projects \nalready identified in the most current MTEP shall become new Baseline \nReliability Projects and shall be included in the next MTEP.  New Transmission \nAccess Projects identified in Facilities Studies and agreements pursuant to \nrequests for transmission delivery service or transmission interconnection service \nunder this Tariff shall be included in the next MTEP."},{"page":606,"startToken":170754,"endToken":171053,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\na.\nGeneration Interconnection Projects:  Generation Interconnection \nProjects are New Transmission Access Projects that are associated with \ninterconnection of new, or increase in generating capacity of existing, \ngeneration under Attachment X to this Tariff and include JTIQ Upgrades.\nb.\nTransmission Delivery Service Projects:  Transmission Delivery \nService Projects are New Transmission Access Projects that are needed to \nprovide for requests for new Point-To-Point Transmission Service, or \nrequests under Module B of the Tariff for Network Service or a new \ndesignation of a Network Resource(s).\nB.\nMarket Efficiency Projects:  Market Efficiency Projects are Network Upgrades:  (i) that \nare proposed by the Transmission Provider, Transmission Owner(s), ITC(s), Market \nParticipant(s), or regulatory authorities; (ii) that are found to be eligible for inclusion in the \nMTEP or are approved pursuant to Appendix B, Section VII of the ISO Agreement after June 16, \n2005, applying the factors set forth in Section I.C. of this Attachment FF; (iii) that, except if \nqualifying as an Interregional Market Efficiency Project under Section IX of the MISO-PJM \nJoint Operating Agreement, have a Project Cost of $5 million or more; (iv) that, except if \nqualifying as an Interregional Market Efficiency Project under Section IX of the MISO-PJM \nJoint Operating Agreement, involve facilities with voltages of 230 kV or higher1; and that may \ninclude any lower voltage facilities of 100kV or above that collectively constitute less than fifty \npercent (50%) of the combined project cost, and without which the 230 kV or higher facilities \ncould not deliver sufficient benefit to meet the required benefit-to-cost ratio threshold for the \n1 \nTransformer voltage is defined by the voltage of the low-side of the transformer for these purposes."},{"page":607,"startToken":171053,"endToken":171372,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nproject as established in Section II.B.1.c, or that otherwise are needed to relieve applicable \nreliability criteria violations that are projected to occur as a direct result of the development of \nthe 230 kV or higher facilities of the project; (v) that are not determined to be Multi-Value \nProjects; (vi) that are found to have regional benefits under the criteria set forth in Section II.B.1 \nof this Attachment FF.  In the event that a Network Upgrade qualifies as an Interregional Market \nEfficiency Project under Section IX of the MISO-PJM Joint Operating Agreement, the cost \nthreshold of Section II.B(iii) does not apply, and the voltage threshold of Section II.B.(iv) shall \nbe 100 kV or higher.2 \n1.\nCriteria to Determine Whether a Project Should be Included as a Market \nEfficiency Project:  The Transmission Provider shall employ multiple future scenarios \nand multi-year analyses including sensitivity analyses guided by input from the Planning \nAdvisory Committee to evaluate the anticipated benefits of a proposed Market Efficiency \nProject in order to determine if such a project meets the criteria for inclusion in the \nregional plan as a Market Efficiency Project eligible for regional cost sharing.  Sensitivity \nanalyses shall include, among other factors, consideration of:  (i) variations in amount, \ntype, and location of future generation supplies as dictated by future scenarios developed \nwith stakeholder input and guidance; (ii) alternative transmission proposals; (iii) impacts \nof variations in load growth; and (iv) effects of demand response resources on \ntransmission benefits.\na. \nBenefits Analysis. For purposes of qualification as a Market Efficiency \nProject, the Transmission Provider will evaluate multiple types of economic value. The \n2 \nA transformer is considered to operate above 100 kV when at least two sets of transformer terminals \noperate at voltages above 100 kV."},{"page":608,"startToken":171372,"endToken":171656,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nTransmission Provider shall apply the benefits metrics outlined in Attachment FF-7 and \nsum the results of each of the benefit metrics together to determine the economic benefits \nof a Market Efficiency Project to the Transmission Provider region.\nb.\nThe costs applied in the benefit to cost ratio shall be the present value, \nover the same period for which the project benefits are determined, of the annual \nNetwork Upgrade Charges for the project as determined in accordance with the formula \nin Attachment GG.\ni.\nThe present value calculation for both the annual benefits and \nannual costs will apply a discount rate representing the after-tax weighted average \ncost of capital of the Transmission Owners that make up the Transmission \nProvider Transmission System.  \nc.\nThe Transmission Provider shall employ a benefit to cost ratio test to \nevaluate a proposed Market Efficiency Project.  Only projects that meet a benefit to cost \nratio of 1.25 or greater shall be included in the MTEP as a Market Efficiency Project and \nbe eligible for regional cost sharing.  \ni.\nThe benefits of the project used to determine the associated cost \nallocations as a percentage of project cost shall be determined one time at the time \nthat the project is presented to the Transmission Provider Board for approval.  \nEstimated Project Cost will be used to estimate the benefit to cost ratio and the \neligibility for cost sharing at the time of project approval.  To the extent that the \nCommission approves the collection of costs in rates for Construction Work in \nProgress (“CWIP”) for a constructing Transmission Owner, costs will be"},{"page":609,"startToken":171656,"endToken":171968,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nallocated and collected prior to completion of the project.    \nd.\nThe aforementioned Market Efficiency Project inclusion criteria \nshall be used for the exclusive purpose of determining whether projects are eligible for \nregional cost sharing in accordance with Section III.A.2.f below.  These criteria shall not \naffect the existing criteria set forth in Appendix B of the ISO Agreement for determining \nwhether projects are eligible for inclusion in the MTEP.  Moreover, the costs of projects \nincluded in the MTEP, but not eligible for regional cost sharing, shall continue to be \neligible for inclusion in the calculation of Transmission Owner revenue requirements under \nAttachment O of this Tariff. \nC. \nMulti-Value Projects:  A Multi-Value Project is one or more Network Upgrades \nthat address a common set of Transmission Issues and satisfy the conditions listed in \nSections II.C.1, II.C.2, and II.C.3 of Attachment FF.  All Network Upgrades associated \nwith a Multi-Value Project including any network upgrades on an external system and  \nlower voltage facilities that may be needed to relieve applicable reliability criteria \nviolations that are projected to occur as a direct result of the development of the Multi-\nValue Project including any lower voltage facilities that are needed on an external system; \nmay be cost shared per Section III.A.2.g of Attachment FF except for (i) any Network \nUpgrade cost associated with constructing an underground or underwater transmission line \nabove and beyond the cost of a feasible alternative overhead transmission line that provides \ncomparable regional benefits, and (ii) any DC transmission line and associated terminal \nequipment when scheduling and dispatch of the DC transmission line is not turned over to \nthe Transmission Provider's markets, real-time control of the DC transmission line is not"},{"page":610,"startToken":171968,"endToken":172236,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nturned over to the Transmission Provider's automatic generation control system and/or the \nDC transmission line is operated in a manner that requires specific users to subscribe for \nDC transmission service. \n1.\nA Multi-Value Project must be evaluated as part of a Portfolio of projects, as \ndesignated in the transmission expansion planning process, whose benefits are: (i) \nspread broadly across the MISO system-wide footprint; or (ii) if the benefits of the \nPortfolio are not spread broadly across the MISO system-wide footprint, the \nbenefits are spread broadly across: (a) the MISO Midwest MVP Cost Allocation \nSubregion; or (b) the MISO South MVP Cost Allocation Subregion.\n2.\nA Multi-Value Project must meet one of the three criteria outlined below:\na.\nCriterion 1.  A Multi-Value Project must be developed through the \ntransmission expansion planning process for the purpose of enabling the \nTransmission System to reliably and economically deliver energy in support \nof documented energy policy mandates or laws that have been enacted or \nadopted through state or federal legislation or regulatory requirement that \ndirectly or indirectly govern the minimum or maximum amount of energy \nthat can be generated by specific types of generation.  The MVP must be \nshown to enable the transmission system to deliver such energy in a manner \nthat is more reliable and/or more economic than it otherwise would be \nwithout the transmission upgrade.\nb.\nCriterion 2.  A Multi-Value Project must provide multiple types of \neconomic value across multiple pricing zones with a Total MVP Benefit-to-"},{"page":611,"startToken":172236,"endToken":172487,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nCost ratio of 1.0 or higher where the Total MVP Benefit -to-Cost ratio is \ndescribed in Section II.C.7 of this Attachment FF.  The reduction of \nproduction costs and the associated reduction of LMPs resulting from a \ntransmission congestion relief project are not additive and are considered a \nsingle type of economic value.\nc.\nCriterion 3.  A Multi-Value Project must address at least one Transmission \nIssue associated with a projected violation of a NERC or Regional Entity \nstandard and at least one economic-based Transmission Issue that provides \neconomic value across multiple pricing zones.  The project must generate \ntotal financially quantifiable benefits, including quantifiable reliability \nbenefits, in excess of the total project costs based on the definition of \nfinancial benefits and Project Costs provided in Section II.C.7 of \nAttachment FF.\n3.\nAll of the following conditions must be satisfied in order for a project to be \nclassified as a Multi-Value Project:\na.\nFacilities associated with the transmission project must not be in service, \nunder construction, or approved for construction by the Transmission \nProvider Board prior to July 16, 2010 or the date a Transmission Owner \nbecomes a signatory member of the ISO Agreement, whichever is later.  \nThis Section II.C.3.a shall not preclude the Multi-Value Project \nclassification of a Competitive Transmission Project that makes a Selected \nDeveloper(s) eligible to become a Transmission Owner."},{"page":612,"startToken":172487,"endToken":172726,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nb.\nThe transmission project must be evaluated through the Transmission \nProvider's transmission planning process and approved for construction by \nthe Transmission Provider Board prior to the start of construction, where \nconstruction does not include preliminary site and route selection activities.\nc.\nThe transmission project must not contain any transmission facilities listed \nin Attachment FF-1 of this Tariff. \nd.\nThe total capital cost of the transmission project must be greater than or \nequal to $20,000,000.00.\ne.\nThe transmission project must include, but not necessarily be limited to, the \nconstruction or improvement of transmission facilities operating at voltages \nabove 100 kV. A transformer is considered to operate above 100 kV when \nat least two sets of transformer terminals operate at voltages above 100 kV.\nf.\nNetwork Upgrades driven solely by an Interconnection Request, as defined \nin Attachment X of the Tariff, or a Transmission Service request will not be \nconsidered Multi-Value Projects.\n4.\nAny transmission project that qualifies as a Multi-Value Project shall be \nclassified as an MVP irrespective of whether such project is also a Baseline \nReliability Project and/or Market Efficiency Project.\n5.\nThe specific types of economic value provided by a Multi-Value Project \ninclude the following:\na.\nProduction cost savings where production costs include generator \nstartup, hourly generator no-load, generator energy and generator"},{"page":613,"startToken":172726,"endToken":172950,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nOperating Reserve costs. Production cost savings can be realized \nthrough reductions in both transmission congestion and transmission \nenergy losses.  Productions cost savings can also be realized through \nreductions in Operating Reserve requirements within Reserve Zones \nand, in some cases, reductions in overall Operating Reserve \nrequirements for the Transmission Provider.\nb.\nCapacity losses savings where capacity losses represent the amount \nof capacity required to serve transmission losses during the system \npeak hour including associated planning reserve.\nc.\nCapacity savings due to reductions in the overall Planning Reserve \nMargins resulting from transmission expansion.\nd.\nLong-term cost savings realized by Transmission Customers by \naccelerating a long-term project start date in lieu of implementing a \nshort-term project in the interim and/or long-term cost savings \nrealized by Transmission Customers by deferring or eliminating the \nneed to perform one or more projects in the future.\ne.\nAny other financially quantifiable benefit to Transmission \nCustomers resulting from an enhancement to the Transmission \nSystem and related to the provisions of Transmission Service.\n6.\nAny project to facilitate like-for-like capital replacements of plant originally \ninstalled as part of a Multi-Value Project where replacement is due to aging, failure, \ndamage or relocation requirements where such replacement is not the result of"},{"page":614,"startToken":172950,"endToken":173240,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nnegligence by the constructing Transmission Owner will be treated as a Multi-\nValue Project.  The minimum project cost limitation for Multi-Value Projects \ndescribed in Section II.C.3.d of Attachment FF will not apply to the like for- like \ncapital replacement projects described in this Section.\n7.\nThe following Total MVP Benefit-to-Cost Ratio will be applied to any \nMulti-Value Project justified solely on the basis of Sections II.C.2.b or II.C.2.c of \nthis Attachment FF to ensure such project qualifies as a Multi-Value Project: \nTotal MVP Benefit-to-Cost Ratio = financial benefits / Project Costs.\nFor the purpose of this calculation, Financial Benefits will be set equal to the \npresent value of all financially quantifiable benefits provided by the project \nprojected for the first 20 years of the project's life and Project Costs will be set \nequal to the present value of the annual revenue requirements projected for the first \n20 years of the project's life.\n8.\nThe aforementioned Multi-Value Project inclusion criteria shall be used for \nthe exclusive purpose of determining whether projects are eligible for regional cost \nsharing in accordance with Section III.A.2.g below.  These criteria shall not affect \nthe existing criteria set forth in Appendix B of the ISO Agreement for determining \nwhether projects are eligible for inclusion in the MTEP.  Moreover, the costs of \nprojects included in the MTEP, but not eligible for regional cost sharing, shall \ncontinue to be eligible for inclusion in the calculation of Transmission Owner \nrevenue requirements under Attachment O of this Tariff.\nD.\nMarket Participant Funded Projects: Market Participant funded projects (MPFPs) are"},{"page":615,"startToken":173240,"endToken":173501,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ndefined as Network Upgrades fully funded by one or more market participants but owned and \noperated by an incumbent Transmission Owner.  These projects apply to those Network \nUpgrades that are neither currently included in the MTEP Appendix A nor targeted for approval \nwithin the current planning cycle.\nThe development of the MPFPs will follow specified process steps that are detailed in the \nTransmission Provider’s Transmission Planning Business Practices Manual (“TPBPM”).  These \nprocess steps shall include, at a minimum, the following:\n1.\nConsistent with the MTEP process the submittal deadline for a proposed \nMPFP project shall be September 15 of the current planning cycle and the \nproposed MPFP shall be submitted to the Transmission Provider planning contact, \nindicated on the MPFP submittal form posted on the Planning page of the \nTransmission Provider web site.\n2.\nAn MPFP proposed by a Market Participant shall follow the same analysis \nand approval timeline as an MTEP Target Appendix A project for the current \nplanning cycle.\n3.\nIn the event that multiple Market Participants submit project proposals that \nare electrically similar, Transmission Provider shall make a determination in \ncollaboration with the affected Transmission Owner(s) as to whether the projects \nare effectively the same project.  Such consideration shall include whether the \nproposals have the same terminal stations, substantially address the same market \ncongestion issues or otherwise serve similar system purposes, and can each be  \nphysically accommodated together with the other similar proposals.  If the"},{"page":616,"startToken":173501,"endToken":173778,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nprojects are determined to be effectively the same project, the priority for the \nproject shall be determined by the time-stamp date of receipt of the MPFP \nProposal Form, unless otherwise agreed to by the impacted Market Participants.  \nE.\nIdentification of Potential Impacts of a Market Efficiency Project or Multi-Value \nProject on Neighboring Transmission Planning Region(s)\nAs part of the evaluation of any proposed Market Efficiency Project or Multi-Value \nProject, the Transmission Provider will determine whether the proposed Market Efficiency Project \nor Multi-Value Project causes any violations of NERC reliability standards on the transmission \nsystem(s) of the adjacent neighboring transmission planning region(s).  If the Transmission \nProvider’s evaluation identifies any such violations of NERC reliability standards, the \nTransmission Provider will contact and coordinate with the other potentially affected adjacent \nneighboring transmission planning region(s) on any further evaluation.  \nF.\nTargeted Market Efficiency Projects:  \nA Targeted Market Efficiency Project is an upgrade that is identified in a Targeted Market \nEfficiency Project Study initiated by the Joint RTO Planning Committee as provided for under \nArticle IX of the Joint Operating Agreement between the Transmission Provider and PJM and that \nsatisfies the criteria for a Targeted Market Efficiency Project as set forth in Article IX of the Joint \nOperating Agreement between the Transmission Provider and PJM.  Any Targeted Market \nEfficiency Project that is recommended by the Joint RTO Planning Committee under Article IX of \nthe Joint Operating Agreement between the Transmission Provider and PJM shall be presented to \nthe Transmission Provider Board for approval in the MTEP."},{"page":617,"startToken":173778,"endToken":174041,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nG.\nTreatment of Storage as a Transmission-Only Asset (SATOA)  \n1.  SATOA May Be Included in MTEP as a Solution to a Transmission Issue\nA storage facility proposed as a Storage as Transmission Only Asset (“SATOA”) may be \nconsidered in the transmission planning process as a solution to a Transmission Issue.   A \nSATOA may be any one of the transmission project types described in Sections II.A through \nII.D and II.F of this Attachment FF that meet the definitions, criteria, or factors applicable to \nthose project types.  A SATOA is eligible for cost recovery consistent with the cost recovery for \nits project type under Attachment FF, including cost recovery under Attachment FF, Section \nIII.A.2.k. \na.\nComparative Evaluations of Proposed SATOA.   \nThe Transmission Provider will evaluate the appropriateness of proposed SATOAs as solutions \nto Transmission Issues identified in the development of the MTEP comparably to any other \ntransmission asset.  Considerations will include:\ni.\nAbility of the proposed SATOA to address the Transmission Issue (e.g., loading, \nvoltage, stability) in all hours that the Transmission Issue is determined to exist, \nwith a life-cycle cost that is comparable to other proposed solutions or as \notherwise needed to address the Transmission Issue, and after consideration of \nthe comparability in system performance to other proposed solutions, including \nany non-transmission alternatives consistent with the provisions of Section \nI.D.1.b.\nii.\nThe minimum and maximum Capacity required to address the Transmission Issue"},{"page":618,"startToken":174041,"endToken":174297,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nto ensure that excess storage Capacity is not treated as a transmission asset.  Cost \nrecovery under transmission rates is limited to the cost of the maximum Capacity \ndetermined to be needed to address the Transmission Issue and will be pro-rated \non that basis if a SATOA of higher Capacity is proposed, selected for inclusion in \nAppendix A of MTEP, and installed.\niii.\nAssurance of sufficient Energy and/or reactive capability (MWh/MVAr) to charge \nor discharge Energy for any period identified as necessary in the planning study. \niv.\nAssessment of system reliability impacts applicable to inverter-based facilities on \nthe same basis and in a manner comparable to such analysis in the Generator \nInterconnection Procedures applicable to storage Resources as inverter-based \nfacilities.  \nv.\nLife-cycle cost comparisons, including consideration of the period that is required \nto address the Transmission Issue, which may be less than the life cycle of \nalternatives, and including the factors described in Section II.G.1.b.  \nvi.\nAdditional considerations that may support comparative evaluation to other \nsolutions to the Transmission Issue, such as lead-time to develop, right of way or \nsubstation impacts, expandability, operational flexibility, or others.\nb. Life Cycle, Degradation, and Cost Assumptions \nSelection of the proposed SATOA as the preferred solution will consider similar cost and \neffectiveness considerations as applied to any other proposed transmission solution.  The entity \nproposing the SATOA shall provide the planning estimate of the SATOA’s:"},{"page":619,"startToken":174297,"endToken":174502,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ni.\nDirect capital cost; \nii.\nExpected useful life; \niii.\nEquipment replacement schedules and associated life-cycle costs and other \nongoing costs to maintain the SATOA at its required Capacity and Energy \ncapability necessary to address the Transmission Issue identified, or otherwise \ncomparable to a traditional wires solution; and \niv.\nOther cost and performance information as the Transmission Provider may \ndetermine is necessary to compare cost and performance with other proposed \nsolutions to the Transmission Issue identified.\nc.\nSelection of proposed SATOA as a Preferred Solution in MTEP\nTo be selected for inclusion in the MTEP, in addition to the requirements of Section II.G.1.a., the \nproposed SATOA must:\ni.\nDemonstrate a basis to be recommended for inclusion in Appendix A of the \nMTEP as a transmission asset by:\na. Unique characteristics or circumstances of the proposed SATOA \nnecessary to meet the identified Transmission System performance \nrequirements and not otherwise available at comparable costs from other \nproposed solutions, including speed of operation, lead-time to implement, \nright-of-way or other property considerations.   \nb. A need to resolve the Transmission Issue(s) through the storage facility’s"},{"page":620,"startToken":174502,"endToken":174821,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nfunctioning as a SATOA instead of as a Resource that participates in the \nTransmission Provider’s markets. A storage facility will not be evaluated \nas a potential SATOA to resolve a routine (i.e. N-0 or N-1) Transmission \nIssue that can be addressed by a market solution.  \nii.\nMeet the criteria to be designated in the MTEP as one of the transmission project \ntypes consistent with the provisions of Sections II.A through II.D and II.F of this \nAttachment FF, or as eligible for cost recovery pursuant to Section III.A.2.k.  \nd. Consideration of Impacts on Resources in the Interconnection Queue\nIf the Transmission Provider or stakeholder identifies a potential impact to Generating Facilities \nin the Definitive Planning Phase pursuant to Attachment X, the Transmission Provider will \nassess whether the proposed SATOA will impact Generating Facilities in the Definitive Planning \nPhase and such assessment may include targeted contingency analyses applying Applicable \nReliability Standards and applicable regional and local planning criteria to evaluate the \nincremental impact of the proposed SATOA on Generating Facilities in the Definitive Planning \nPhase that are in proximity to the SATOA in the MTEP model to compare loading and other \nsystem performance impacts attributable to the addition of the SATOA.  The Transmission \nProvider will test the expansion model with and without the SATOA operating in the manner \nrequired for the SATOA to address the Transmission Issue identified for the SATOA to resolve.  \nIf such assessment demonstrates that the necessary operating mode of the proposed SATOA \nwould cause the need for additional system mitigation, the cost of such mitigation will be \nincluded in the evaluation of the proposed SATOA against other potential transmission solutions \nand will be included as part of the SATOA project itself and the total project costs will be"},{"page":621,"startToken":174821,"endToken":175100,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\neligible for recovery through the appropriate Attachment and Schedule of the Tariff.\n2. Development of Operating Guides Associated with SATOA Selected for MTEP  \nOperation of SATOA in real time will be under the functional control of the Transmission \nProvider as provided for in Rate Schedule 1 (Transmission Owners Agreement), Article Three, \nSection I.A.  For each SATOA included in the MTEP, the Transmission Provider will develop an \nOperating Guide specifying the operating practices applicable to the SATOA and consistent with \nthe system performance requirements determined through the planning study supporting the \nselection of the SATOA for inclusion in the MTEP. The Operating Guide will include limitations \non the operation of the SATOA above the maximum Capacity determined to be needed to \naddress the Transmission Issue, consistent with Section II.G.1.a.ii.\n3. Storage as Non-Transmission Alternatives\nAs provided for under Section I.D.1.b, storage facilities that are not proposed as SATOA may be \nconsidered as alternatives to transmission assets to address system needs when participating as \ngeneration or demand-side resources.    \n4. SATOA Participation in Markets\nSATOA may only participate in the Transmission Provider’s markets to the extent necessary to \nreceive Energy from the Transmission System and to inject Energy into the Transmission System \nto provide the services for which the SATOA was included in the MTEP.  SATOA may not \notherwise participate in the Energy and Operating Reserve Markets and/or the Planning Resource \nAuction.  \n5. Transmission Service Associated with SATOA Operation\nNo Transmission Service charges are applicable to the operation of a SATOA."},{"page":622,"startToken":175100,"endToken":175358,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\n6. Responsibility for Market-Derived Costs and Revenues Associated with SATOA \na. Accounting for Costs Incurred in the Market\nCosts resulting from Market Activities of a SATOA directed under the Transmission \nProvider’s functional control shall be collected through transmission rates in a manner \nconsistent with the treatment of costs associated with the transmission project type that \nthe SATOA is included as in Appendix A of the MTEP pursuant to Section II.G.1.c.ii.  \nAs an example, costs for charging a SATOA battery storage device may be included in \ntransmission rates in a manner consistent with the inclusion in transmission rates as a \nBaseline Reliability Project if the battery storage device operates to serve as a Baseline \nReliability Project.\nb. Credit Back of Market Revenues\nRevenues collected from Market Activities of a SATOA directed under the Transmission \nProvider’s functional control shall be credited back through transmission rates in a \nmanner consistent with the treatment of costs associated with the project category in \ntransmission rates. \n7. Removal\nNo SATOA may be removed from service permanently unless the removal is submitted into the \nannual MTEP planning process as a proposed project removal, reviewed by the Transmission \nProvider for its impact on Transmission System performance, and accepted by the Transmission \nProvider based on such review.\nIII.\nDesignation of Cost Responsibility for MTEP Projects:  Based on the planning \nanalysis performed by the Transmission Provider, which shall take into consideration all"},{"page":623,"startToken":175358,"endToken":175678,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nappropriate input from Market Participants or external entities, including, but not limited to, any \nindications of a willingness to bear cost responsibility for an enhancement or expansion, the \nrecommended MTEP shall, for any enhancement or expansion that is included in the plan, \ndesignate:  (i) the Market Participant(s) in one or more pricing zones that will bear cost \nresponsibility for such enhancement or expansion, as and to the extent provided by any \napplicable provision of the Tariff, including Attachments N, X, or any applicable cost allocation \nmethod ordered by the Commission; or, (ii) in the event and to the extent that no provision of the \nTariff so assigns cost responsibility, the Market Participant(s) or Transmission Customer(s) in \none or more pricing zones from which the cost of such enhancements or expansions shall be \nrecovered through charges established pursuant to Attachment GG of this Tariff, or as otherwise \nprovided for under this Attachment FF. \nAny designation under clause (ii) of the preceding sentence shall be determined as provided for \nin Section III.A of this Attachment FF with the cost responsibility at least roughly commensurate \nwith the benefits.  For all such designations, the Transmission Provider shall calculate the cost \nallocation impacts to each pricing zone.  The results will be reviewed for unintended \nconsequences by the Transmission Provider and the Tariff Working Group and any such \nidentified consequences shall be reported to the Planning Advisory Committee, and the OMS.\nA.\nAllocation of Costs Within the Transmission Provider Region \n1.\nDefault Cost Allocation:  Except as otherwise provided for in this Attachment FF, or by \nany other applicable provision of this Tariff and consistent with the ISO Agreement, the \nresponsibility for Network Upgrades included in the approved MTEP will be addressed in \naccordance with the provisions of the ISO Agreement."},{"page":624,"startToken":175678,"endToken":175940,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\n2.\nCost Allocation:  The Transmission Provider will designate and assign cost \nresponsibility on a regional, and sub-regional basis for Network Upgrades identified \nin the MTEP subject to the grand-fathered project provisions of Section III.A.2.b.  \na.\nMarket Participant’s Option to Fund:  Notwithstanding the Transmission \nProvider’s assignment of cost responsibility for a project included in the \nMTEP, one or more Market Participants may elect to assume cost \nresponsibility for any or all costs of a Network Upgrade that is included in \nthe MTEP.  Provided however, in the event the Market Participant is also \na Transmission Owner such election of the option to fund must be made \non a consistent, non-discriminatory basis.\nb.\nGrandfathered Projects:  The cost allocation provisions of this \nAttachment FF shall not be applicable to transmission projects identified \nin Attachment FF-1, which is based on the list of projects designated as \nPlanned Projects in the MTEP approved by the Transmission Provider \nBoard on June 16, 2005 (MTEP 05) and some additions of proposed \nprojects that the Transmission Provider has determined to be in the \nadvanced stages of planning.\nc.\nBaseline Reliability Projects:  Costs of Baseline Reliability Projects shall \nbe recovered pursuant to Attachment O of this Tariff by the Transmission \nOwner(s) and/or ITC(s) developing such projects, such that the \nTransmission Owner(s) and/or ITC(s) developing a Baseline Reliability \nProject shall be responsible for all of the costs of the portion of the"},{"page":625,"startToken":175940,"endToken":176176,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nBaseline Reliability Project that is physically located in the Transmission \nOwner’s and/or ITC’s pricing zone, subject to the requirements of the ISO \nAgreement.\nd.\nGeneration Interconnection Projects:  Costs of Generation Interconnection \nProjects that are not JTIQ Upgrades and that are not determined by the \nTransmission Provider to be Baseline Reliability Projects, Market \nEfficiency Projects, or Multi-Value Projects and the Network Upgrade \ncosts associated with advancing a Baseline Reliability Project, Market \nEfficiency Project, or Multi-Value Project associated with a generator \ninterconnection will be paid for by the Interconnection Customer(s) in \naccordance with Attachment X.\nFor Generation Interconnection Projects interconnecting to the American \nTransmission Company LLC transmission system and that are not JTIQ \nUpgrades, such costs will be subject to the provision of Attachment FF – \nATCLLC.  In the event that a Generation Interconnection Project that is \nnot a JTIQ Upgrade defers or displaces a Baseline Reliability Project, the \ncosts of the Generation Interconnection Project up to the costs of the \ndeferred or displaced Baseline Reliability Project shall be allocated \nconsistent with the cost allocation for the Baseline Reliability Project.\n1)\nFor Network Upgrades to facilities in voltage classes at or above \n345 kV and that are not a JTIQ Upgrade, the Interconnection \nCustomer shall be repaid 10 percent of the costs of the Generation"},{"page":626,"startToken":176176,"endToken":176397,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nInterconnection Project funded by the Interconnection Customer \nonce Commercial Operation is achieved.  The Transmission \nOwner(s) constructing the Generation Interconnection Project will \nrepay 10% of the Generation Interconnection Project costs \nassociated with Network Upgrade facilities in a voltage class of \n345 kV or greater to the Interconnection Customer under \nrepayment terms consistent with the schedules and other terms of \nAttachment X.  \nThe 10% of the Project Cost associated with Network Upgrade \nfacilities of voltage class 345 kV or above and that are not a JTIQ \nUpgrade, and repaid to the Interconnection Customer pursuant to \nthis section, shall be allocated on a system-wide basis and \nrecovered pursuant to Attachment GG of this Tariff.\nCosts of Generation Interconnection Projects that are JTIQ \nUpgrades included in a JTIQ Portfolio, and where a JTIQ Upgrade \nincluded in the JTIQ Portfolio has been selected to receive funding \nthrough the United States Department of Energy Grid Resilience \nand Innovation Partnerships (GRIP) Program by December 31, \n2023, shall be allocated to Interconnection Customers included in \nthe JTIQ Commitment Groups consistent with Section 9.4 and \nrelated subsections of Rate Schedule 6.  If none of the JTIQ \nUpgrades have been selected to receive funds through the GRIP"},{"page":627,"startToken":176397,"endToken":176620,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nprogram, the Transmission Provider will propose an appropriate \ncost allocation method pursuant to the terms of Section 9.4 of Rate \nSchedule 6. \nIn the event that the JTIQ Portfolio in Section 9.4 of Rate Schedule \n6 is not fully subscribed as set forth in Rate Schedule 6, the costs \nof JTIQ Upgrades constructed by a Transmission Owner and not \nrecovered from the JTIQ Commitment Groups shall be recovered \non a system-wide basis pursuant to Attachment JJJ. \nA JTIQ Upgrade identified pursuant to Section 9.4 of Rate \nSchedule 6 shall be presented to the Transmission Provider Board \nfor approval for inclusion in the MTEP.\n2)\nAn Interconnection Customer may be required to contribute to the \ncost of Shared Network Upgrades, as defined in Attachment X to \nthe Tariff, that are funded by another Interconnection Customer,  \nincluding when the Transmission Owner elects to fund the capital \ncost of a Shared Network Upgrade under Section 11.3 of the \nGenerator Interconnection Agreement, as a Generation \nInterconnection Project pursuant to Attachment X in accordance \nwith the following provisions:  \n(a)\nEach Interconnection Customer with one or more Shared \nNetwork Upgrade(s) identified in Appendix A of its \nGenerator Interconnection Agreement for which the"},{"page":628,"startToken":176620,"endToken":176824,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nTransmission Owner(s) has not elected to fund the capital \ncost of a Shared Network Upgrade(s) under Section 11.3 of \nthe Generator Interconnection Agreement shall make a one-\ntime payment under Schedule 26-B to the Transmission \nProvider in accordance with the terms in the Generator \nInterconnection Agreement. The one-time payment will \nreflect the cost of the Shared Network Upgrade assigned to \nthe Interconnection Customer as determined by the \nTransmission Provider.\nAll revenue collected by the Transmission Provider through \nSchedule 26-B shall be distributed to the appropriate \nInterconnection Customer(s).\n(b)\nIf the Transmission Owner(s) has elected to fund the capital \ncost of a Shared Network Upgrade(s) under Section 11.3 of \nthe Generator Interconnection Agreement, each \nInterconnection Customer with that Shared Network \nUpgrade(s) identified in Appendix A of its Generator \nInterconnection Agreement shall enter into a Facilities \nService Agreement(s) with the Transmission Owner(s).\n3)\nThe Interconnection Customer shall be entitled, pursuant to \nSection 46 of this Tariff, to any Financial Transmission Rights or \nother rights to the extent provided for under this Tariff, for any"},{"page":629,"startToken":176824,"endToken":177016,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nNetwork Upgrade costs funded by or charged to the \nInterconnection Customer and not subject to repayment under the \nprovisions of this Section III.A.2.d and that are not costs for JTIQ \nUpgrades.  For costs funded by or charged to the Interconnection \nCustomer for Generation Interconnection Projects that are JTIQ \nUpgrades, the Interconnection Customer shall be eligible for \nFinancial Transmission Rights pursuant to Section 47 of this \nTariff.  \n4)\nInternational Transmission/Michigan Electric Transmission \nCompany: \n(a)\nFor those Generation Interconnection Projects that \nare not JTIQ Upgrades for which International \nTransmission Company or Michigan Electric Transmission \nCompany, LLC, (“International” or “METC”) as \nTransmission Owners will be a signatory to the \ninterconnection agreement under the terms of Attachment \nX of this Tariff or any successor provision of the Tariff \nexecuted by the parties after the effective date of this \nAttachment FF Section III.A.2.d.4, this Attachment FF \nSection III.A.2.d.4 shall apply.\n(b)\nGeneration Interconnection Projects:  The cost of \nNetwork Upgrades for Generation Interconnection Projects"},{"page":630,"startToken":177016,"endToken":177199,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nthat are not determined by the Transmission Provider to be \nBaseline Reliability Projects shall be reimbursed by the \nTransmission Owner as provided in this Section III.A.2.d.4.  \nAll costs of Network Upgrades for Generation \nInterconnection Projects will initially be paid by the \nInterconnection Customer in accordance with the terms of \nthe Interconnection Agreement entered into pursuant to \nAttachment X of this Tariff.  To the extent the \nInterconnection Customer demonstrates at the time of \nCommercial Operation of the Generating Facility one of the \nfollowing:  \ni.\nGenerating Facility has been designated as a \nNetwork Resource in accordance with the \nTariff, or\nii.\nContractual commitment has been entered into \nwith a Network Customer for capacity, or in the \ncase of an Intermittent Resource, for energy, \nfrom the Generating Facility for a period of one \n(1) year or longer.\nThe Interconnection Customer will receive up to one \nhundred percent (100%) reimbursement of reimbursable \ncosts within ninety (90) days of the Commercial Operation"},{"page":631,"startToken":177199,"endToken":177411,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nDate, such reimbursement prorated by the percentage of the \nGenerating Facility capacity or annual available energy \noutput contracted for and as demonstrated to the \nsatisfaction of the Transmission Provider.\nIf the Interconnection Customer is unable to \ndemonstrate to the satisfaction of the Transmission \nProvider at the time of Commercial Operation of the \nGenerating Facility that the Generating Facility has met the \nrepayment obligations set forth in Attachment FF Sections \nIII.A.2.d.4.b.i. or III.A.2.d.4.b.ii. the Interconnection \nCustomer shall be directly assigned 100% of the costs of \nthe Generation Interconnection Project.  The Transmission \nOwner may effect this direct assignment of costs by either \nforegoing any repayment of costs funded by the \nInterconnection Customer, or by electing to repay 100% of \nthe costs under repayment terms consistent with the \nschedules and other terms of Attachment X.\nThe Interconnection Customer shall be entitled, pursuant to \nSection 46 of this Tariff, to any Financial Transmission \nRights or other rights to the extent provided for under this \nTariff, for any Network Upgrade costs funded by or \ncharged to the Interconnection Customer and not subject to"},{"page":632,"startToken":177411,"endToken":177599,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nrepayment under the provisions of this Attachment FF \nSection III.A.2.d.4.  In the event that a Generation \nInterconnection Project defers or displaces a Baseline \nReliability Project, the costs of the Generation \nInterconnection Project up to the costs of the deferred or \ndisplaced Baseline Reliability Project shall be allocated \nconsistent with the cost allocation for the Baseline \nReliability Project.\n(c)\nFor all amounts to be reimbursed by a Transmission \nOwner to an Interconnection Customer in accordance with \nthis Attachment FF Section III.A.2.d.4, the Transmission \nOwner will reimburse the sums received from the \nInterconnection Customer in cash together with any \napplicable interest, in accordance with the terms of the \nInterconnection Agreement.\n(d)\nAllocation of Generation Interconnection \nReimbursement.  For all amounts reimbursed by a \nTransmission Owner to an Interconnection Customer under \nthis Attachment FF Section III.A.2.d.4, the reimbursement \nwill be allocated as follows:  \ni.\nProjects of Voltage Below 345 kV:  50% of \nthe applicable Project Cost for Generation"},{"page":633,"startToken":177599,"endToken":177764,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nInterconnection Projects with a voltage class \nbelow 345 kV shall be allocated on a sub-\nregional basis to all Transmission Customers \nin designated pricing zones.  The designated \npricing zones and the sub-regional allocation \nof the Project Cost shall be determined on a \ncase-by-case basis in accordance with a Line \nOutage Distribution Factor Table (“LODF \nTable”) developed by the Transmission \nProvider which is similar in form to that \nattached hereto as Attachment FF-2.  The \nLODF Table is based on Transmission \nSystem topology and Line-Outage \nDistribution Factors associated with the \nproject under consideration and is used to \ndetermine the pricing zones to be included \nin the sub-regional allocation of the Project \nCost.  The percentage of the sub-regional \nallocation assigned to each designated \npricing zone shall be determined based on \nthe relative share between pricing zones of \nthe sum of the absolute value of the product"},{"page":634,"startToken":177764,"endToken":177930,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nof the Line-Outage Distribution Factor on \neach Branch Facility in a pricing zone and \nthe length in miles of the Branch Facility.\nThe remaining fifty percent (50%) of the \nreimbursement will not be subject to any \nregional or sub-regional cost allocation, but \nwill be recovered by that Transmission \nOwner under its Attachment O transmission \nrate formula under this Tariff.\nii.\nProjects of Voltage 345 kV and Higher:  \n10% of the applicable Project Cost for \nGeneration Interconnection Projects with a \nvoltage class of 345 kV or higher shall be \nallocated on a system-wide basis to all \nTransmission Customers and recovered \nthrough a system-wide rate.  40% of the \napplicable Project Cost for Generation \nInterconnection Projects with a voltage class \nof 345 kV or higher shall be allocated on a \nsub-regional basis to all Transmission \nCustomers in designated pricing zones.  The \ndesignated pricing zones and the sub-"},{"page":635,"startToken":177930,"endToken":178098,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nregional allocation of the Project Cost shall \nbe determined on a case-by-case basis in \naccordance with a Line Outage Distribution \nFactor Table (“LODF Table”) developed by \nthe Transmission Provider similar in form to \nthat attached hereto as Attachment FF-2. \nThe LODF Table is based on Transmission \nSystem topology and Line-Outage \nDistribution Factors associated with the \nproject under consideration and is used to \ndetermine the pricing zones to be included \nin the sub-regional allocation of the Project \nCost.  The percentage of the sub-regional \nallocation assigned to each designated \npricing zone shall be determined based on \nthe relative share between pricing zones of \nthe sum of the absolute value of the product \nof the Line-Outage Distribution Factor on \neach Branch Facility in a pricing zone and \nthe length in miles of the Branch Facility.\nThe remaining fifty percent (50%) of the \nreimbursement will not be subject to any"},{"page":636,"startToken":178098,"endToken":178304,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nregional or sub-regional cost allocation, but \nwill be recovered by that Transmission \nOwner under its Attachment O transmission \nrate formula under this Tariff.\ne.\nTransmission Delivery Service Projects:  Costs of Transmission Delivery \nService Projects shall be assigned and recovered in accordance with \nAttachment N of this Tariff.\nf.\nMarket Efficiency Projects:  Costs of Market Efficiency Projects shall be \nallocated as follows:\ni)\nOne Hundred  percent (100%) of the costs of the Market \nEfficiency Projects with a voltage at or above 230 kV that do \nnot qualify as Interregional Market Efficiency Projects under \nSection IX of the MISO-PJM JOA shall be allocated to all \nTransmission Customers in each of the of the Transmission \nPricing Zones that has a net positive present value of the \nannual benefits over the evaluation period applying the \nbenefit metrics in Attachment FF-7. For Market Efficiency \nProjects that are also Interregional Market Efficiency \nProjects under Section IX of the MISO-PJM Joint Operating \nAgreement with a voltage at or above 345 kV,one hundred \npercent (100%) of the Transmission Provider’s share of the \ncosts shall be allocated to all Transmission Customers in"},{"page":637,"startToken":178304,"endToken":178510,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\neach of the Transmission Pricing Zones that has a net \npositive present value of the annual benefits over the \nevaluation period applying the benefit metrics in Attachment \nFF-7. \nii)\nFor Market Efficiency Projects that are also Interregional \nMarket Efficiency Projects under Section IX of the MISO-\nPJM Joint Operating Agreement with a voltage at or above \n100 kV but below 345 kV, one hundred percent (100%) of \nthe Transmission Provider’s share of the costs shall be \nallocated to all Transmission Customers in each of the \nCost Allocation Zones, as defined in Attachment WW.  \nThe cost allocated to each Cost Allocation Zone shall be \nbased on the relative benefit determined for each Cost \nAllocation Zone that has a positive present value of annual \nbenefits over the evaluation period using the methodology \nfor project benefit determination of Attachment FF-7, \nSection I.A. \niii) \nExcessive Funding or Requirements:  The Transmission \nProvider shall seek to identify and manage the development \nof, as a part of the planning process for Market Efficiency \nProjects, portfolios of projects that tend to provide net \nbenefits  over the planning horizon, as determined according"},{"page":638,"startToken":178510,"endToken":178727,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nto the applicable section(s) of Attachment FF-7, throughout \neach Transmission Pricing Zone for each Market Efficiency \nProject with a voltage at or above 230 kV that does not \nqualify as Interregional Market Efficiency Projects under \nSection IX of the MISO-PJM JOA, for each Market \nEfficiency Project that is also an Interregional Market \nEfficiency Project under Section IX of the MISO-PJM Joint \nOperating Agreement with a voltage at or above 345 kV, and \nfor each Cost Allocation Zone, as defined in Attachment \nWW, for each Market Efficiency Project that is also an \nInterregional Market Efficiency Projects under Section IX of \nthe MISO-PJM Joint Operating Agreement with a voltage at \nor above 100 kV but below 345 kV.  The Transmission \nProvider shall analyze on an annual basis whether the project \nportfolios developed in accordance with this goal and the \ncriteria in Section III.A.2.f unintentionally result in unjust or \nunreasonable annual capital funding requirements for any \nTransmission Owner or rate increases for Transmission \nCustomers in designated pricing zones; or otherwise result in \nundue discrimination between the Transmission Customers, \nTransmission Owners, or any Market Participants; any such \nidentified consequences shall be reported to the Planning"},{"page":639,"startToken":178727,"endToken":178906,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nAdvisory Committee and to the Organization of MISO \nStates.  After discussing such assessments with the \naforementioned stakeholder bodies, and taking into \nconsideration the cumulative experience in applying this \nAttachment FF, the Transmission Provider will make a \ndetermination as to whether Tariff modifications are \nrequired, and if so file such modifications.\ng.\nMulti-Value Projects: Costs of Multi-Value Projects will be allocated as \nfollows: \ni)\nFor a Portfolio of Multi-Value Projects with benefits spread \nbroadly across the MISO system-wide footprint, one-\nhundred percent (100%) of the annual revenue \nrequirements of the Multi-Value Projects shall be allocated \non a system-wide basis to Transmission Customers that \nwithdraw energy, including external transactions sinking \noutside the Transmission Provider's region, and recovered \nthrough an MVP Usage Charge pursuant to Attachment \nMM.\nii)\nFor a Portfolio including only Multi-Value Projects with \nbenefits spread broadly across the MISO Midwest MVP \nCost Allocation Subregion identified in Attachment XX but \nnot broadly spread across the MISO system-wide footprint,"},{"page":640,"startToken":178906,"endToken":179091,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\none-hundred percent (100%) of the annual revenue \nrequirements of such Multi-Value Projects shall be: (1) \nallocated on a pro-rata basis to Transmission Customers \nthat withdrew energy in the MISO Midwest MVP Cost \nAllocation Subregion identified in Attachment XX, \nincluding applicable external transactions associated with \nthe MISO Midwest MVP Cost Allocation Subregion \nsinking outside the Transmission Provider’s region; and (2) \nrecovered through an MVP Usage Charge pursuant to \nAttachment MM.\niii)\nFor a Portfolio including only Multi-Value Projects with \nbenefits spread broadly across the MISO South MVP Cost \nAllocation Subregion identified in Attachment XX but not \nbroadly spread across the MISO system-wide footprint, \none-hundred percent (100%) of the annual revenue \nrequirements of such Multi-Value Projects shall be: (1) \nallocated on a pro-rata basis to Transmission Customers \nthat withdraw energy in the MISO South MVP Cost \nAllocation Subregion as identified in Attachment XX, \nincluding applicable external transactions associated with \nthe MISO South MVP Cost Allocation Subregion and \nsinking outside the Transmission Provider's region; and (2)"},{"page":641,"startToken":179091,"endToken":179298,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nrecovered through an MVP Usage Charge pursuant to \nAttachment MM.\nh.\nTargeted Market Efficiency Projects:  The cost of a Targeted Market \nEfficiency Project shall be allocated as follows:\ni)\nTargeted Market Efficiency Projects are interregionally \ncost allocated between the Transmission Provider and PJM \nper Section 9.4.4.2.5 of the Joint Operating Agreement \nbetween the Transmission Provider and PJM.\nii)\nOne hundred percent (100%) of the Transmission Provider’s \nshare of the cost of a Targeted Market Efficiency Project \nshall be allocated to all Transmission Pricing Zones that \nreceive a positive congestion contribution benefit from the \nTargeted Market Efficiency Project.  The share of such cost \nallocated to each Transmission Pricing Zone shall be in \nproportion to the relative positive congestion contribution \nbenefit accruing from the Targeted Market Efficiency Project \nto the Transmission Pricing Zone over the evaluation period \nof Section 9.4.4.1.5(iv)(d) of the Joint Operating Agreement \nbetween the Transmission Provider and PJM.  To determine \nthe relative positive contribution benefit accruing to each \nTransmission Pricing Zone, the Transmission Provider will \nuse the data resulting from the Targeted Market Efficiency"},{"page":642,"startToken":179298,"endToken":179519,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nProject study conducted pursuant to Section 9.3.7.2(c) of the \nJoint Operating Agreement and apply a congestion \ncontribution formula to each load node and generator node in \nthe Commercial Model equal to the multiplication of the \nShadow Price of the flowgate, shift factor of the load node or \ngenerator node to the flowgate, and the amount of load or \ngeneration at the node.  This formula will be applied for all \nhours in the Day Ahead market where the Reciprocal \nCoordinated Flowgate experienced congestion.  The \ncongestion contribution of each load node or generator node \non the Reciprocal Coordinated Flowgate will be calculated \nfor each congested interval during the evaluation period of \nSection 9.4.4.1.5(iv)(d) of the Joint Operating Agreement \nbetween the Transmission Provider and PJM.  Summing all \nof the congestion contributions will yield the relative benefits \nof the upgrade to each load node or generator node.  \nAggregating the load node or generator node congestion \ncontributions for each Transmission Pricing Zone gives the \nnet benefits of the upgrade to each Transmission Pricing \nZone, providing the basis for cost allocation of the \nTransmission Provider’s share of the cost of the Targeted \nMarket Efficiency Project."},{"page":643,"startToken":179519,"endToken":179727,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\niii)\nProvided, however, that no cost for the Targeted Market \nEfficiency Project shall be allocated to a Transmission \nPricing Zone if the positive congestion contribution benefit \nfrom the Targeted Market Efficiency Project to that \nTransmission Pricing Zone is calculated to be less than a \nthreshold of either: (1) $5,000 total or (2) less than one \npercent (1%) of the Transmission Provider’s cost of the \nTargeted Market Efficiency Project.  Any costs that are not \nallocated to a Transmission Pricing Zone because they fall \nwithin this threshold will be collected by a reallocation to the \nremaining Transmission Pricing Zones that receive positive \ncongestion contribution benefits from the Targeted Market \nEfficiency Project in proportion to the share of positive \ncongestion contribution benefits each Transmission Pricing \nZone is calculated to receive from the Targeted Market \nEfficiency Project.\niv)\nProvided, further, that no cost for a Targeted Market \nEfficiency Project that is approved in any MTEP by the \nTransmission Provider Board during the Second Planning \nArea’s Transition Period shall be allocated to a Transmission \nPricing Zone located in the Second Planning Area if the \nTargeted Market Efficiency Project terminates wholly"},{"page":644,"startToken":179727,"endToken":179952,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\noutside of MISO or terminates exclusively in the First \nPlanning Area.  Any costs that are not allocated to a \nTransmission Pricing Zone in the Second Planning Area as a \nresult of this subsection shall be collected by a reallocation to \nthe remaining Transmission Pricing Zones that receive \npositive congestion contribution benefits from the Targeted \nMarket Efficiency Project in proportion to the share of \npositive congestion contribution benefits each Transmission \nPricing Zone is calculated to receive from the Targeted \nMarket Efficiency Project.     \ni.\nMarket Participant Funded Projects (MPFPs):  Costs of MPFPs \nwill be allocated as follows: One-hundred percent (100%) of the cost of a \nMarket Participant Funded Project (MPFP) shall be assigned to the Market \nParticipant that proposed the project, subject to the provisions of this \nAttachment FF Section II.D.3, unless other cost sharing arrangement is \nagreed to between the Market Participant and the incumbent Transmission \nOwner.\nj.\nTreatment of Projects that meet both Baseline Reliability Project Criteria \nand/or New Transmission Access Project Criteria, and the Market \nEfficiency Project Criteria:  If the Transmission Provider determines that a \nproject designated as a Market Efficiency Project also meets the criteria to \nbe designated as a Baseline Reliability Project and/or a New Transmission"},{"page":645,"startToken":179952,"endToken":180185,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nAccess Project, the cost of such project shall be allocated in accordance \nwith the Market Efficiency Project allocation procedures.\nk.\nOther Projects:  Unless otherwise agreed upon pursuant to \nSection III.A.2.a. of this Attachment FF, the costs of Network Upgrades \nthat are included in the MTEP, but do not qualify as Baseline Reliability \nProjects, New Transmission Access Projects, Targeted Market Efficiency \nProjects, Market Efficiency Projects, or Multi-Value Projects shall be \neligible for recovery pursuant to Attachment O of this Tariff by the \nTransmission Owner(s) and/or ITC(s) paying the costs of such project, \nsubject to the requirements of the ISO Agreement. \nl.\nWithdrawal from MISO:  A Transmission Owner that withdraws from the \nMISO as a Transmission Owner shall remain responsible for all financial \nobligations incurred pursuant to this Attachment FF while a Member of \nthe MISO and payments applicable to time periods prior to the effective \ndate of such withdrawal shall be honored by the MISO and the \nwithdrawing Member. \nm.\nNew Transmission Owners: A new Transmission Owner joining the MISO \nwill be responsible for the following financial obligations:\na.\nNew Transmission Owners will not be responsible for any \nportion of Baseline Reliability Projects, Generation \nInterconnection Projects, Transmission Delivery Service \nProjects, Targeted Market Efficiency Projects, or Market"},{"page":646,"startToken":180185,"endToken":180382,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nEfficiency Projects that were approved prior to their entry \ndate.\nb.\nFor Multi-Value Projects approved prior to the new \nTransmission Owner’s entry date, the load interconnected \nto the Transmission Owner’s Transmission System will be \nresponsible for one-hundred percent (100%) of the MVP \nusage charge described in Attachment MM for the years \nfollowing the Transmission Owner’s entry date applied to \nthe Monthly Net Actual Energy Withdrawals for Load \ninterconnected to the Transmission Owner’s Transmission \nSystem.\nn.\nOnly a Transmission Owner shall be authorized to construct and/or own \ntransmission facilities associated with a Baseline Reliability Project.  For \nprojects jointly developed between Transmission Owners and other \nparties the portion constructed and owned by a Transmission Owner may \nqualify as a Baseline Reliability Project, Market Efficiency Project, \nand/or Multi Value Project.\nIV.\nMerchant Transmission Project Data Requirements: A proposed merchant \ntransmission developer assumes all financial risk and funding requirements for developing its \ntransmission project(s) and constructing the proposed transmission facility(ies).  In order for a \nproposed merchant transmission developer’s facility to be interconnected to the Transmission"},{"page":647,"startToken":180382,"endToken":180640,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nSystem, it is first necessary for the impacted Transmission Owner and the Transmission Provider \nto analyze the reliability and operational impact of the proposed new merchant transmission \nfacility(ies) on the Transmission System to determine if the new merchant transmission facilities \ncan be reliably supported by the Transmission System, and if not, what Network Upgrades \nfunded by the merchant transmission developer would be required to reliably support the \nproposed merchant transmission facility(ies).  In order to perform the required reliability and \noperational analyses, the merchant transmission developer must provide the following data to the \nTransmission Provider:  \n(1)\nEach transmission circuit and substation, including new facilities, associated with \nthe merchant transmission proposal;\n(2)\nNominal operating voltage level in kV and voltage characteristics (i.e., AC or DC) \nfor each transmission circuit associated with the merchant transmission proposal;\n(3)\nTypical and maximum MW power flow schedules, in each direction, for all \nproposed DC transmission circuits associated with the merchant transmission proposal;\n(4)\nNormal and emergency summer and winter load ratings for each transmission \ncircuit associated with the merchant transmission proposal;\n(5)\nMaximum allowable positive sequence impedance for each AC transmission circuit \nassociated with the merchant transmission proposal, when applicable;\n(6)\nList of all transmission buses associated with the merchant transmission proposal, \nincluding nominal operating voltage level in kV, voltage characteristics, and terminating \ntransmission branches and shunts;\n(7)\nProposed substation one-line diagrams for all new substations associated with the"},{"page":648,"startToken":180640,"endToken":180907,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nmerchant transmission proposal, including circuit breaker and bus configuration details;\n(8)\nLoad ratings, winding connections, impedances, tap data, and any other relevant \ninformation for load carrying equipment and facilities associated with the merchant \ntransmission proposal, as applicable;\n(9)\nModeling files to model proposed facilities and relevant new contingencies in \npower flow, stability, short-circuit and other relevant study models; and\n(10)\nAny other data determined pertinent to the study by the Transmission Provider \nand/or interconnecting Transmission Owners for the specific merchant transmission facility \nproposal.\nV.\nDesignation of Entities to Construct, Implement, Own, Operate, Maintain, Repair, \nRestore, and/or Finance MTEP Projects:  With the exception of Competitive Transmission \nProjects, for each project included in the recommended MTEP Appendix A and prior to approval \nby the Transmission Provider Board, the plan shall designate one or more Transmission Owners to \nconstruct, own, operate, maintain, repair, restore, and finance the recommended project, based on \nthe planning analysis performed by the Transmission Provider and based on other input from \nparticipants, including, but not limited to, any indications of a willingness to bear cost \nresponsibility for the project; and applicable provisions of the ISO Agreement.  Regarding \nCompetitive Transmission Projects, upon the determination of the Selected Developer(s) for such \nprojects, as set forth in Section VIII of this Attachment FF, the Transmission Provider shall update \nthe approved MTEP Appendix A by identifying the Selected Developer(s) for each Competitive \nTransmission Project.  Should the facilities from such Competitive Transmission Projects not be"},{"page":649,"startToken":180907,"endToken":181174,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\napproved by state regulatory authorities as Competitive Transmission Facilities, but instead as \nupgrades to existing transmission facilities, as defined in Section VIII.A.2 of this Attachment FF, \nthe Transmission Provider shall update MTEP Appendix A by designating the appropriate \nTransmission Owner(s) to construct, own, operate, maintain, repair, restore, and finance such \nfacilities in accordance with the ISO Agreement.\nVI.\nImplementation of the MTEP: \nA.\nIf the Transmission Provider and any Transmission Owner’s planning \nrepresentatives, or other designated entity(ies), cannot reach agreement on any element of the \nMTEP, the dispute may be resolved through the dispute resolution procedures provided in the \nTariff, or in any applicable joint operating agreement, or by the Commission or state regulatory \nauthorities, where appropriate.  The MTEP shall have as one of its goals the satisfaction of all \nregulatory requirements as specified in Appendix B or Article IV, Section I, Paragraph C of the \nISO Agreement.\nB.\nThe Transmission Provider shall present the MTEP, along with a summary of \nrelevant alternative projects that were not selected, to the Transmission Provider Board for \napproval on a biennial basis, or more frequently if needed.  The proposed MTEP shall include \nspecific projects already approved as a result of the Transmission Provider entering into Service \nAgreements with Transmission Customers where such agreements provide for identification of \nneeded transmission construction, timetable, cost, and Transmission Owner or other parties’ \nconstruction responsibilities.  \nC.\nApproval of the MTEP by the Transmission Provider Board certifies it as the"},{"page":650,"startToken":181174,"endToken":181488,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nTransmission Provider plan for meeting the transmission needs of all stakeholders subject to any \nrequired approvals by federal or state regulatory authorities.  The Transmission Provider shall \nprovide a copy of the MTEP to all applicable federal and state regulatory authorities.  The \naffected Transmission Owner(s), Selected Developer(s), or other designated entity(ies), shall \nmake a good faith effort to design, certify, and build the designated facilities to fulfill the \napproved MTEP.  However, in the event that an MTEP Appendix A project approved by the \nTransmission Provider Board is being challenged through the dispute resolution procedures \nunder this Tariff or in court proceedings, the obligation of the Transmission Owners, or other \ndesignated entity(ies), to build that specific project (subject to required approvals) is waived until \nthe approved project emerges from the dispute resolution procedures.  In the event that selection \nof the Selected Developer(s) to construct a project is being challenged through the Dispute \nResolution Process under Attachment HH of the Tariff, the obligation of the Selected \nDeveloper(s) to construct the project pursuant to the Selected Developer Agreement is not \nwaived.  The Transmission Provider Board shall allow the Transmission Owners, or other \ndesignated entity(ies), to optimize the final design of specific facilities and their in-service dates \nif necessary to accommodate changing conditions, provided that such changes comport with the \napproved MTEP and provided that any such changes are accepted by the Transmission Provider \nthrough the Variance Analysis process described in Section IX of this Attachment FF, as \nnecessary.  Any disagreements concerning such matters shall be subject to the dispute resolution \nprocedures of this Tariff. \nD.\nThe Transmission Provider shall assist the affected Owner(s), Selected \nDeveloper(s), or other designated entity(ies), in justifying the need for, and obtaining"},{"page":651,"startToken":181488,"endToken":181761,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ncertification of, any facilities required by the approved MTEP by preparing and presenting \ntestimony in any proceedings before state or federal courts, regulatory authorities, or other \nagencies as may be required.  The Transmission Provider shall publish annually, and distribute to \nall Members and all appropriate state regulatory authorities, a five-to-ten-year planning report of \nforecasted transmission requirements.  Annual reports and planning reports shall be available to \nthe general public upon request.\nVII.\nMulti-Value Project Costs and Benefits Review and Reporting\nA.\nFrequency and Reporting of Multi-Value Project Review:  For two (2) three \n(3) year cycles, as provided below and in the Business Practices Manual for Transmission \nPlanning, the Transmission Provider shall conduct a review of the cumulative costs and \nbenefits associated with any MVP(s) first included in an approved MTEP in the \npreceding six (6) years, and shall disseminate the results of such reviews to its \nstakeholders.  The Transmission Provider shall use the review process and results to \nidentify potential modifications to the MVP methodology and its implementation for \nprojects to be approved at a future date.\n1.\nTriennial MVP Review:  Beginning with the third MTEP following approval of an \nMVP , and the third MTEP thereafter, the Transmission Provider shall conduct a \nMVP review, as provided in Section VII.B of this Attachment FF. \n2.\nCalculation of Costs and Benefits:  The Triennial MVP Reviews MVP Reviews \nshall calculate costs and benefits on a forward-looking basis over both twenty \n(20)-year and forty (40)-year periods.  The costs calculation shall use updated"},{"page":652,"startToken":181761,"endToken":181989,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nproject costs and in-service dates provided in the latest MTEP quarterly status \nreport, and the benefits calculation shall use updated future scenarios from the \nlatest MTEP planning cycle.  The results of the costs and benefits calculation shall \nbe provided for each Cost Allocation Zone as defined in Attachment WW.\n3.\nDissemination of the Results of the Triennial MVP Reviews:  Within a reasonable \ntime after completion of each MVP review, the Transmission Provider shall \ndisseminate the results of and supporting analysis for the MVP review through:  \n(a) publication in the MTEP; (b) posting on the appropriate section of the \nTransmission Provider’s public website; and (c) presentation to the appropriate \nstakeholder committees.\nB.\nScope of Triennial Multi-Value Project Review:  Each Triennial MVP Review \nshall at a minimum include the following: \n1.\nQuantitative Benefits:  Analysis of the quantifiable economic benefits resulting \nfrom the addition of MVPs first included in an approved MTEP within the \npreceding six years, including, but not limited to:  \na.\nCongestion and Fuel Savings:  Savings from increased access to lower \ncost Resources; \nb.\nDecreased Operating Reserves:  Savings associated with lower Operating \nReserve requirements; \nc.\nDecreased System Planning Reserve Margin:  Savings associated with \ndeferred generation investment due to a reduction in the system-wide \nPlanning Reserve Margin; and"},{"page":653,"startToken":181989,"endToken":182179,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nd.\nDecreased Transmission Line Losses:  Savings associated with deferred \ngeneration investment due to a reduction in the Capacity required to serve \ntransmission losses during peak hours, to the extent that MVPs reduce \nsuch losses.\n2.\nPublic Policy and Other Qualitative Benefits:  Analysis of the public policy and \nother qualitative benefits accruing from MVPs, such as newly interconnected \nwind units; and an increase in the percentage of the Transmission Provider’s \nEnergy needs being supplied by wind and/or other renewable resources, and wind \ncurtailments. \n3.\nHistorical Data:  Based on the historical data available to the Transmission \nProvider for the five (5) prior years, of information on certain additional market \ntrend metrics including, but not limited to: \na.\nCongestion costs; \nb.\nEnergy prices; \nc.\nFuel costs; \nd.\nPlanning Reserve Margin requirements; \ne.\nNumber of newly interconnected Resources, by Resource type; and \nf.\nThe share of the Transmission Provider’s Energy supplied, by Resource \ntype.  \nVIII.\nCOMPETITIVE TRANSMISSION PROCESS\nThis section of Attachment FF of the Tariff describes the processes and requirements"},{"page":654,"startToken":182179,"endToken":182445,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nassociated with identifying Competitive Transmission Facilities contained within a Market \nEfficiency Project or Multi-Value Project approved by the Transmission Provider Board in \nMTEP Appendix A; certifying entities as Qualified Transmission Developers, whether they are \nexisting Transmission Owners or non-incumbent transmission developers; solicitation of \nProposals from Qualified Transmission Developers to construct, implement, own, operate, \nmaintain, repair, and restore the Competitive Transmission Facilities; evaluation of Proposals; \nand designation of a Selected Proposal and Selected Developer(s) pursuant to Section VIII of \nAttachment FF of the Tariff.\nVIII.A.\nAPPLICABILITY \nExcept as otherwise provided in Sections VIII.A.1, VIII.A.2 and VIII.A.3 of this \nAttachment FF, the Competitive Developer Selection Process shall be applicable to all \ntransmission facilities and substation facilities located on the Transmission System and included \nin an Eligible Project.\nVIII.A.1.\nState or Local Rights of First Refusal:\nThe Transmission Provider shall comply with any Applicable Laws and \nRegulations granting a right of first refusal to a Transmission Owner.  The Transmission \nOwner will be assigned any transmission project within the scope, and in accordance with \nthe terms, of any Applicable Laws and Regulations granting such a right of first refusal.  \nThese Applicable Laws and Regulations include, but are not limited to, those granting a \nright of first refusal to the incumbent Transmission Owner(s) or governing the use of \nexisting developed and undeveloped right of way held by an incumbent utility. \nVIII.A.2.\nUpgrades to Existing Transmission Facilities:"},{"page":655,"startToken":182445,"endToken":182734,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nA Transmission Owner shall have the right to develop, own, and operate any \nupgrade to a transmission facility owned by the Transmission Owner, in accordance with \nthis Tariff and the ISO Agreement.\nFor an Eligible Project that contains both upgrades to existing transmission \nfacilities as defined in Sections VIII.A.2.1 through VIII.A.2.2.1 and new transmission \nfacilities that are not upgrades, the Transmission Provider shall apply the following rules \nto assign the facilities included in the Eligible Project to applicable incumbent \nTransmission Owners or Selected Developer.\na.\nIf 80% or more of the total cost of the transmission facilities included in \nthe Eligible Project are upgrades as defined in Sections VIII.A.2.1 through \nVIII.A.2.2.1 of this Attachment FF, the Transmission Provider shall \ndesignate the applicable incumbent Transmission Owner(s) to develop, \nown, and operate all transmission facilities comprising the Eligible Project \nin accordance with the ISO Agreement.\nb. If less than 80% of the total cost of the transmission facilities included in \nthe Eligible Project are upgrades as defined in Sections VIII.A.2.1 through \nVIII.A.2.2.1 of this Attachment FF, the Transmission Provider shall divide \nthe Eligible Project into two or more facilities or segments of facilities \nbased upon the rules set forth in Sections VIII.A.2.1 through VIII.A.2.2.1 \nof this Attachment FF.  For those facilities or segments of facilities that \nare upgrades as defined in Sections VIII.A.2.1 through VIII.A.2.2.1, the \nTransmission Provider shall designate the applicable incumbent"},{"page":656,"startToken":182734,"endToken":182959,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nTransmission Owner(s) to develop, own, and operate all transmission \nfacilities comprising the Eligible Project in accordance with the ISO \nAgreement.  Those facilities or segments that are not exempt from the \nCompetitive Developer Selections Process pursuant to Section VIII.A.1 \nthrough VIII.A.3 shall be subject to the Competitive Developer Selection \nProcess.\nFor purposes of this Section VIII.A.2, the Transmission Provider shall use \nthe cost estimates prepared by the Transmission Provider for presentation to the \nTransmission Provider Board at the time such facilities are approved for inclusion \nin Appendix A to calculate the total cost of the transmission facilities contained \nwithin an Eligible Project.\nVIII.A.2.1.\nUpgrades to Existing Transmission Lines:  Upgrades to \nexisting transmission line facilities include any expansion, replacement, or \nmodification, for any purpose, made to existing transmission line facilities \nclassified as transmission plant and owned by one or more Transmission Owners, \nfor reasons including, but not limited to:\n(a)\nIncreasing the load capability of the transmission line or an \nassociated circuit;\n(b)\nIncreasing the nominal operating voltage of the transmission line \nor an associated circuit;\n(c)\nInstalling additional plant on an existing overhead or underground \ntransmission line facility, such as, but not limited to:"},{"page":657,"startToken":182959,"endToken":183140,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ni.\nplant associated with an additional circuit installed on spare \nstructure positions;\nii.\nadditional structures to increase a sag limit or for other \npurposes;\niii.\na sectionalizing switch installed on an existing transmission \nline circuit regardless of whether or not it is installed on an existing \nstructure; and\niv.\nany other plant additions to existing transmission line \nfacilities.\n(d)\nInstalling additional plant on a replaced overhead or underground \ntransmission line facility, where the new additional circuit will be co-\nlocated with an existing transmission line, such as, but not limited to:\ni.\nplant associated with an additional circuit installed on a \nreplaced structure; \nii.\nadditional structures to increase a sag limit or for other \npurposes;\niii.\na sectionalizing switch installed on an existing transmission \nline circuit regardless of whether or not it is installed on an existing \nstructure; and\niv.\nany other plant additions to replacement transmission line \nfacilities.\n(e)\nAny requirement or request to relocate transmission line facilities"},{"page":658,"startToken":183140,"endToken":183370,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nowned by an incumbent Transmission Owner where the purpose of the \nrelocation is not part of the core scope of a Competitive Transmission \nProject, including, but not limited to, relocations driven by aesthetics, \nhighway expansion projects, other infrastructure expansion projects, \nprojects to improve the reliability or performance of the Transmission \nSystem, projects to reduce the cost to operate and maintain the \nTransmission System, projects to interconnect new generation and load, \nand projects to accommodate the relocation of an existing substation;\n(f)\nAny requirement or request to relocate existing transmission line \nfacilities owned by an incumbent Transmission Owner to accommodate \nCompetitive Transmission Line Facilities associated with a Competitive \nTransmission Project, where such construction of the Competitive \nTransmission Line Facilities requires or requests use of the incumbent \nTransmission Owner’s right-of-way and, as a result, also requires or \nrequests transfer of the existing transmission facilities to alternative right-\nof-way or an alternative position on the same right-of-way based on either \nmutual consent of the incumbent Transmission Owner and Selected \nDeveloper(s) and/or the outcome of a state regulatory proceeding or court \naction;  \n(g)\nFunctionally equivalent capital replacement of any portion of an \nexisting transmission line facility due to aging, deterioration, damage, \npoor performance, aesthetics, high operating and maintenance costs, or"},{"page":659,"startToken":183370,"endToken":183556,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nother similar reasons; \n(h)\nReplacing one or more existing components of any existing \ntransmission line facility, such as, but not limited to:\ni.\nreplacing existing conductors with higher capacity \nconductors or better performing conductors;\nii.\nreplacing existing structures;\niii.\nreplacing insulators rated at a specific voltage with \ninsulators rated at a higher voltage;\niv.\nreplacing aging or defective components associated with \nthe existing transmission line;\n(i)\nImproving the performance or characteristics of the existing \ntransmission line for any reason;\n(j)\nConverting an existing overhead transmission line to an \nunderground transmission line on the same right-of-way and/or converting \nan existing underground transmission line to an overhead transmission on \nthe same right-of-way;\n(k)\nImproving land and land rights booked under the Commission’s \nUniform System of Accounts, Account Nos. 105, 350, and/or 380; or\n(l)\nAny other modifications to existing transmission facilities.\nVIII.A.2.1.1. Installation of additional transmission circuits on \nexisting transmission lines:\nIf a Competitive Transmission Project includes developing a new"},{"page":660,"startToken":183556,"endToken":183801,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ntransmission circuit and in a subsequent state or local regulatory \nproceedings determine that all or a portion of the circuit must be installed \non an existing transmission line that is part of the Transmission System \n(i.e., co-located with existing transmission circuits on the same structures), \nthe following rules will be used to determine what constitutes an upgrade:   \n(a)\nIf the structures associated with the existing transmission line are \nmulti-circuit structures and have spare positions to accommodate \ninstallation of one or more additional transmission circuit(s), \ninstallation of the new transmission circuit(s) on these spare \nstructure positions will be considered an upgrade.\n(b)\nIf the structures associated with the existing transmission line can \nbe expanded to accommodate installation of one or more additional \ntransmission circuit(s), expansion of the structure and installation \nof the new transmission circuit(s) will be considered an upgrade.\n(c)\nIf the structures associated with the existing transmission line are \nnot multi-circuit structures and cannot be expanded to accept \nadditional circuits, do not have sufficient spare structure positions \navailable to accommodate the new transmission circuit(s), or have \nspare structure positions that are reserved for future use by the \nincumbent Transmission Owner and not available for the new \ntransmission circuit(s) in question, it will be necessary to rebuild \nthe existing transmission line to accommodate one or more"},{"page":661,"startToken":183801,"endToken":184007,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nadditional transmission circuits.  Under this scenario, all of the \nnecessary and applicable actions (e.g., acquisition of additional \nright-of-way; removal of the existing transmission line plant; \nconstruction of new transmission line structures; transfer or \nreplacement of the existing transmission line conductors, \ninsulators, and shield wire(s); and installation of new conductors, \ninsulators, and shield wire(s) associated with the new transmission \ncircuit(s) co-located with existing transmission circuit(s) on the \nsame structures; etc.) will be considered an upgrade.  \nVIII.A.2.2.\nUpgrades to Existing Substations:  \nUpgrades to existing substations include any expansions, \nreplacements or modifications made, in part or in whole, to any existing \nsubstation or portion thereof that is owned by one or more Transmission \nOwners, and where some or all of the plant within the existing substation \nis classified as transmission plant.  These upgrades include, but are not \nlimited to:\n(a)\nReplacing facilities and/or equipment within an existing substation \nfootprint;\n(b)\nInstalling additional plant within an existing substation footprint;  \n(c)\nModifying facilities and/or equipment within an existing substation \nfootprint;\n(d)\nExpanding an existing substation footprint within the existing"},{"page":662,"startToken":184007,"endToken":184244,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nsubstation site boundaries and installing additional plant within the \nexpanded area; \n(e)\nAcquiring additional land adjacent to the existing substation in \nconjunction with installation of additional plant within the \nboundaries of this additional land, including facilities to \ninterconnect such plant to the existing substation plant; and\n(f)\nDeveloping an additional footprint near the existing substation to \nfacilitate effective expansion of the existing substation as further \ndescribed below in Section VIII.A.2.2.1.\nVIII.A.2.2.1. Expansion of an existing substation by developing an \nadditional footprint near the existing substation:\nConstruction of a new substation footprint near an existing substation to \nfacilitate expansion of the existing substation is considered an upgrade and \nis necessary when the transmission project calls for expansion of the \nexisting substation and there is not sufficient space for such expansion.  \nUpgrades through development of a second substation footprint can be \naccomplished in one of two ways.  First, a second substation footprint can \nbe developed near the existing substation footprint, and the two substation \nfootprints will function electrically as a single substation and will be \ninterconnected by bus extensions or connectors.  An example would be \nexpanding an existing substation that is landlocked by public roadways by \ndeveloping a second substation footprint on the other side of one of the"},{"page":663,"startToken":184244,"endToken":184511,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nroads and then installing an overhead single span connector which would \nfunction as a substation bus to interconnect the two substation footprints.  \nSecond, an existing substation could be retired for many reasons such as \nbut not limited to: lack of room for future expansions, physical conditions \nsuch as soil subsidence, earthquake reinforcement requirements, to prevent \nflood damage, regulatory/public necessity/economic reasons, and other \nsimilar factors.  A new substation could be developed nearby on a \ndifferent site and all transmission circuits into the existing substation could \nbe rerouted to the new site, which is essentially the relocation of an \nexisting substation.  These scenarios represent upgrades to an existing \nsubstation when the intent of the transmission project produced by the \ntransmission planning process is to expand the existing substation rather \nthan develop a new substation or to relocate an existing substation for \nreasons not related to implementation of a regionally cost shared \ntransmission project.   \nVIII.A.3. Immediate Need Reliability Projects\nImmediate Need Reliability Projects are projects that: (a) are identified in a Baseline \nReliability Study needed to address a reliability need and needed within thirty-six (36) \nmonths from first Calendar Day of the month in which the Transmission Provider Board \napproves the project for inclusion in Appendix A of an MTEP; and (b) meet the criteria \nfor designation as a Baseline Reliability Project pursuant to Section II.A.1 of this \nAttachment FF, notwithstanding the fact that such project also meets the criteria set forth"},{"page":664,"startToken":184511,"endToken":184762,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nin Section II.B of this Attachment FF for classification as a Market Efficiency Project. \nThe Transmission Provider shall designate the applicable Transmission Owner to \ndevelop, own, and operate all transmission facilities comprising such Immediate Need \nReliability Project in accordance with the ISO Agreement.\nVIII.A.3.1 Procedure for Review of Immediate Need Reliability Projects:\n(a) \nWithin thirty (30) Calendars Days after the Transmission Provider Board \napproves the respective MTEP, the Transmission Provider shall post a report on its \nwebsite that separately identifies each Immediate Need Reliability Project that the \nTransmission Provider has determined to assign to the applicable Transmission Owner. \nThe posted report shall include:\ni. An identification of the transmission facilities contained within the Immediate\nNeed Reliability Project;\nii. The need by date of each Immediate Need Reliability Project;\niii. A brief explanation of the reliability need(s), that each Immediate Need\nReliability Project is required to address, including the reason(s) for the need\nby date, in sufficient detail to allow stakeholders to understand the need and why\nit is time sensitive;\niv. The date(s) and manner in which the reliability need was first identified\nduring the planning process along with an explanation of why the need was\nnot identified earlier;\nv. An explanation of other transmission or, consistent with the provisions of\nSection I.D.1.b, any non-transmission alternatives the Transmission Provider"},{"page":665,"startToken":184762,"endToken":185032,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nconsidered but concluded would not sufficiently address the immediate\nreliability need.\n(b) \nIf the Transmission Provider identifies any Immediate Need Reliability Projects\npursuant to Section VIII.A.3.1(a), the Transmission Provider shall provide\nstakeholders with thirty (30) Calendar Days to submit comments in response to\nthe report required by Section VIII.A.3.1(a) starting with the date that such report\nis posted on the Transmission Provider’s website. Within sixty (60) Calendar\nDays after posting the report required by Section VIII.A.3.1(a), the Transmission\nProvider shall post the comments received together with any responses by the\nTransmission Provider.\n(c) \nThe Transmission Provider shall post and update at least annually a list of prior \nyears’ designations of Market Efficiency Projects that met the criteria in Section\nVIII.A.3, for designation as an Immediate Need Reliability Project which list shall\ncontain both the need-by date and the date that the Transmission Owner placed the\nfacility in service.\nVIII.A.3.2 Immediate Need Reliability Project Dispute Resolution.\nAny disputes regarding determinations to classify or not classify a transmission project as\nan Immediate Need Reliability Project and/or assign transmission facilities associated\nwith such Immediate Need Reliability Project to the Transmission Owner will be referred\nto the Dispute Resolution Process under Attachment HH of this Tariff. In the event that\nsuch classification and/or assignment is being challenged through the Dispute Resolution\nProcess under Attachment HH of the Tariff, the obligation of the designated"},{"page":666,"startToken":185032,"endToken":185270,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nTransmission Owner to construct such facilities is not waived.\nVIII.B.\nCOMPETITIVE DEVELOPER QUALIFICATION PROCESS\nThis section of Attachment FF of the Tariff describes the processes and requirements \nassociated with certifying entities as Qualified Transmission Developers, whether they are \nexisting Members or non-incumbent transmission developers.\nVIII.B.1.\nQualified Transmission Developers:\nOnly Qualified Transmission Developers may submit Proposals in response to a \nRequest for Proposals posted by the Transmission Provider for a Competitive \nTransmission Project.  The Transmission Provider will maintain a list of Qualified \nTransmission Developers on its website that will be updated within thirty (30) Calendar \nDays of the conclusion of the Competitive Developer Qualification Process.\nVIII.B.2.\nPrequalification Process:\nThe Transmission Provider will open a prequalification window each quarter of \nthe calendar year for entities that are not currently listed as Qualified Transmission \nDevelopers, including existing Members, Non-incumbent Developers, and Non-owner \nMembers, by posting on its website a Transmission Developer Application template and \ninvitation to submit a Transmission Developer Application.  To become a Qualified \nTransmission Developer, each Transmission Developer Applicant must submit a \nTransmission Developer Application using the template(s) posted with the invitation and \nfurther described in the applicable Business Practices Manuals, by the deadline specified \nin the invitation, but no less than thirty (30) Calendar Days from the date the invitation"},{"page":667,"startToken":185270,"endToken":185547,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nwas posted.  The Transmission Developer Applicant shall submit its completed \nTransmission Developer Application by the day specified as the deadline in accordance \nwith the requirements in the applicable Business Practices Manual.  The Transmission \nDeveloper Applicant shall also submit a non-refundable transmission developer \napplication fee, as further described in the applicable Business Practices Manuals, in the \namount of $20,000.00 by 5:00 PM EPT on the day specified as the Transmission \nDeveloper Application deadline to cover the cost of processing, reviewing, and \ndetermining whether the Transmission Developer Applicant does or does not satisfy all \nthe qualification requirements  required by Sections VIII.B.4(a) – (g) and VIII.B.4.1 – \nVIII.B4.4 of this Attachment FF to be certified as a Qualified Transmission Developer.  \nA Transmission Developer Applicant may rely on the resources, capabilities, or \ncompetencies of an Affiliate to satisfy the qualification requirements contained in \nSections VIII.B.4.1 – VIII.B.4.4 provided that the Transmission Developer Applicant: (a) \nclearly identifies in the Transmission Developer Application which prequalification \nrequirements the Transmission Developer Applicant will rely on its Affiliate to satisfy; \n(b) clearly identifies the resources, capabilities, and/or competencies of the Affiliate the \nTransmission Developer Applicant intends to rely on to satisfy each prequalification \nrequirement; and (c) includes with its Transmission Developer Application submission a \nStatement of Support executed by the Affiliate on which the Transmission Developer \nApplicant will rely for such support.   \nVIII.B.2.1.\nCompleted Transmission Developer Applications:\nTo the extent the Transmission Provider finds the Transmission"},{"page":668,"startToken":185547,"endToken":185745,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nDeveloper Application deficient of information or data required by the \nTransmission Developer Application template(s), the Transmission \nProvider will notify the Transmission Developer Applicant of the \ndeficiencies electronically within thirty (30) Calendar Days of the \nTransmission Provider’s receipt of the respective Transmission \nDeveloper Application.  The Transmission Developer Applicant shall \nhave thirty (30) Calendar Days from the date the Transmission Provider’s \ndeficiency notification was sent to submit the additional data required to \nthe Transmission Provider.  No additional Transmission Developer \nApplication cure period will be allowed for the purposes of gaining \nQualified Transmission Developer status. \nVIII.B.2.2.\nTransmission Developer Application Review:\nThe Transmission Provider will review each Transmission \nDeveloper Application that has been cured of any identified deficiencies \nand will notify each Transmission Developer Applicant of the \nTransmission Provider’s decision to certify or not certify the \nTransmission Developer Applicant as a Qualified Transmission \nDeveloper within one-hundred eighty (180) Calendar Days of the \nTransmission Provider’s receipt of the respective Transmission \nDeveloper Application.  \nThe Transmission Provider will certify those Transmission \nDeveloper Applicants that meet the qualification requirements specified"},{"page":669,"startToken":185745,"endToken":185981,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nin Sections VIII.B.2 and VIII.B.4 of this Attachment FF and the \napplicable Business Practices Manuals.  If the Transmission Provider \ndoes not certify a Transmission Developer Applicant, it will provide the \nTransmission Developer Applicant with a written explanation detailing \nits determination within thirty (30) Calendar Days after notification.  \nThe Competitive Transmission Executive Committee shall have \nthe exclusive and final authority to approve or reject Transmission \nDeveloper Applications and certify Transmission Developer Applicants \nas Qualified Transmission Developers.\nVIII.B.3.\nBiennial Recertification Process:\nEach Qualified Transmission Developer that intends to remain qualified must \nrecertify its Qualified Transmission Developer status every second calendar year as \ndetermined by the recertification cycle posted by the Transmission Provider.  The \nTransmission Provider will assign each Qualified Transmission Developer to a \nrecertification cycle after the Qualified Transmission Developer’s initial application is \napproved.  Before July 15 of the year immediately preceding the year in which a QTD is \ndue for recertification, the Transmission Provider will send a notification to each \nQualified Transmission Developer that is required to recertify its status in accordance \nwith Section VIII.B.3.1 of this Attachment FF.\nVIII.B.3.1.\nRecertification Submission Requirements:\n Each Qualified Transmission Developer that is sent a recertification \nnotification shall submit, within thirty (30) Calendar Days after the recertification"},{"page":670,"startToken":185981,"endToken":186254,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nnotification is sent, a recertification statement in a form to be provided by the \nTransmission Provider, executed by an authorized representative of the Qualified \nTransmission Developer.  There will be no fee for the first recertification, but for \neach recertification thereafter, the Qualified Transmission Developer shall also \nsubmit a non-refundable transmission developer recertification fee in the amount \nof $2,000 as further described in the applicable Business Practices Manuals, by \n5:00 PM EPT on the day specified as the Qualified Transmission Developer \nrecertification deadline.  The recertification statement shall confirm, to the best of \nthe Qualified Transmission Developer’s knowledge, that the Qualified \nTransmission Developer continues to meet the requirements for initial \nqualification as set forth in Sections VIII.B.4, VIII.B.4.1, VIII.B.4.2, VIII.B.4.3, \nand VIII.B.4.4 of this Attachment FF.  The recertification statement shall also \ncontain a completed checklist indicating whether the Qualified Transmission \nDeveloper, or any parent or affiliate whose resources are relied upon for \nrecertification, have experienced certain changes since the date the Qualified \nTransmission Developer last submitted a Transmission Developer Application or \nrecertification statement.  The specific changes shall be identified in the \nrecertification notice and may include, but are not limited to: (1) merger, \nreorganization, or a change in the identity of any parent or affiliate providing \nsupport; (2) changes to the Qualified Transmission Developer’s legal name, state \nof domicile, or MISO membership status; (3) bankruptcies, liquidations, \nreceiverships or general assignments; (4) any new legal or regulatory violations"},{"page":671,"startToken":186254,"endToken":186497,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nthat would be required to be reported in a Transmission Developer Application \npursuant to Section VIII.B.4.3 of this Attachment FF; and (5) any specific \nchanges that the Transmission Provider identifies as necessary to evaluate a \nQualified Transmission Developer’s continued qualifications.\nA properly completed and executed recertification statement stating that \nthe Qualified Transmission Developer and, if applicable, its supporting parent or \naffiliate, has not experienced any of the changes listed by the Transmission \nProvider in the recertification statement form shall be deemed a completed \nrecertification application.\nIf a Qualified Transmission Developer identifies in its recertification \nstatement that any of the changes specified in the recertification statement form \naccompanying the recertification notice have occurred, initial disclosure shall not \ncreate any presumption of disqualification. Upon receipt of an executed  \nrecertification statement indicating that a listed change has occurred, the \nTransmission Provider shall provide the Qualified Transmission Developer with \nfurther instructions for submitting information and explanations to enable the \nTransmission Provider to evaluate the effect of the identified changes on the \nQualified Transmission Developer’s continued qualifications. Such further \ninstructions shall be tailored to the disclosed change and shall be due no later than \nthirty (30) Calendar Days after the date that the additional information request \nwas sent to the Qualified Transmission Developer. \nShould a Qualified Transmission Developer fail to submit a properly"},{"page":672,"startToken":186497,"endToken":186734,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ncompleted recertification statement or any information in response to the \nTransmission Provider’s request for further information within the applicable \nsubmission periods specified in this Section VIII.B.3.1 of this Attachment FF, the \nTransmission Provider shall notify the Qualified Transmission Developer \nelectronically within five (5) Business Days of the deadline specified in\nthe renewal notification or request for further information of any deficiencies that\nthe Transmission Provider has identified.  The Qualified Transmission\nDeveloper will have five (5) Business Days from the date of notification of\ndeficiency to cure the identified deficiencies by submitting the required\ninformation.  Should a Qualified Transmission Developer fail to cure the \nidentified deficiency during this five (5) Business Day period, the Transmission \nProvider will deem that the Qualified Transmission Developer has requested to \nvoluntarily terminate its certification as a Qualified Transmission Developer in \naccordance with Section VIII.B.5 of this Attachment FF.   \nVIII.B.3.2.\nReview of Recertification Submissions.\nThe Transmission Provider shall review each Qualified \nTransmission Developer’s recertification submission, any supporting \ninformation and explanations, and the annual financial information \nsubmitted pursuant to Section VIII.B.8 of this Attachment FF. The \nTransmission Provider shall determine whether the information included \nin the submission warrants recertification or termination of a Qualified \nTransmission Developer’s status under the standards established in"},{"page":673,"startToken":186734,"endToken":186993,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nSection VIII.B.1 through VIII.B.4.4 of this Attachment FF.  The \nTransmission Provider will notify each Qualified Transmission Developer \nas to whether or not such entity has been recertified, within one-hundred \neighty (180) Calendar Days of the date the Transmission Provider sent the \nrecertification notification.  \nIn the event that the Competitive Transmission Executive \nCommittee terminates or determines not to recertify a Qualified \nTransmission Developer, the Transmission Provider shall provide that \nentity with a written explanation detailing its determination within thirty \n(30) Calendar Days of such notification.  If the Transmission Provider \neither terminates or does not recertify a Qualified Transmission \nDeveloper, such entity may seek re-qualification during any subsequent \nqualification process as described in Section VIII.B.2 of this Attachment \nFF.  The Competitive Transmission Executive Committee shall have the \nexclusive and final authority to recertify or terminate a Qualified \nTransmission Developer’s Qualified Transmission Developer status.  \nVIII.B.4.\nRequirements for Qualified Transmission Developer Status:  \nTo be certified as a Qualified Transmission Developer, the requirements set forth \nin Sections VIII.B.4, VIII.B.4.1, VIII.B.4.2, VIII.B.4.3, and VIII.B.4.4 of this Attachment \nFF must be satisfied. A Transmission Developer Applicant may elect to satisfy one or \nmore of these requirements by referencing and/or utilizing the qualifications, capabilities, \nand/or competencies of one or more Affiliates instead of, or in addition to, those of the"},{"page":674,"startToken":186993,"endToken":187238,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nTransmission Developer Applicant. Should a Transmission Developer Applicant elect to \nreference and/or utilize the qualifications, capabilities, and/or competencies of one or \nmore Affiliates, the Transmission Developer Applicant must: (a) clearly identify in the \nTransmission Developer Application each Tariff requirement that the Transmission \nDeveloper Applicant intends to rely on an Affiliate to satisfy; and (b) include in the \nTransmission Developer Application an executed Statement of Support for each such \nAffiliate that acknowledges that the Transmission Developer Applicant is relying on the \nspecified qualifications, capabilities, and/or competencies of the Affiliate. A \nTransmission Developer Applicant may elect to satisfy one or more of the requirements \nof VIII.B.4.3(a) and VIII.B.4.3(b) of this Attachment FF by submitting documentation \npertaining to an Affiliate provided that the Transmission Developer Applicant also \nsubmits such documentation pertaining to itself, included an executed Statement of \nSupport in the Transmission Developer Application for each such Affiliate, and has \nclearly identified which information and documentation pertains to the Affiliate and \nwhich information and documentation pertains to itself. \nThe general requirements applicable to Qualified Transmission Developers \ninclude the following: \n(a)\nThe Transmission Developer Applicant shall be a Transmission Owner or \na Non-owner Member in good standing at the time the Transmission \nDeveloper Application is acted on by the Transmission Provider and shall \nmaintain such status."},{"page":675,"startToken":187238,"endToken":187482,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\n(b)\nThe Transmission Developer Applicant shall either: (i) submit a written \ncommitment, signed by an authorized representative of the Transmission \nDeveloper Applicant, to execute the ISO Agreement should it be \ndesignated as a Selected Developer and to list any Competitive \nTransmission Facilities for which it is designated a Selected Developer, \npursuant to the Selected Proposal, in Appendix H of the ISO Agreement \n(i.e. the list of transmission facilities transferred to MISO’s functional \ncontrol for the purposes of planning and operation); or (ii) state that it is \nalready a signatory to the ISO Agreement and submit a written \ncommitment, signed by an authorized representative of the Transmission \nDeveloper Applicant, that it will list any Competitive Transmission \nFacilities for which it is designated as a Selected Developer for, pursuant \nto the Selected Proposal, in Appendix H of the ISO Agreement.  The \nexecution of the ISO Agreement must take place after the Competitive \nTransmission Facilities have been constructed but prior to their \nenergization and the addition of the Competitive Transmission Facilities to \nAppendix H of the ISO Agreement must take place after the Competitive \nTransmission Facilities have been energized; \n(c)\nThe Transmission Developer Applicant shall submit a written \ncommitment, signed by an authorized representative of the Transmission \nDeveloper Applicant, to comply with all Applicable Laws and \nRegulations, codes, and standards governing the engineering, design,"},{"page":676,"startToken":187482,"endToken":187703,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nconstruction, operation, and maintenance of transmission facilities \nincluding, but not limited to, federal laws; applicable state and local laws; \napplicable state and local building codes; federal regulatory requirements; \napplicable state and local regulatory requirements; applicable state and \nlocal licensing authorities; the National Electric Safety Code; the National \nElectric Code; Applicable Reliability Standards; and Good Utility Practice \nshould the Transmission Developer Applicant be designated as a Selected \nDeveloper for one or more Competitive Transmission Facilities;  \n(d)\nThe Transmission Developer Applicant shall either: (i) submit a written \ncommitment, signed by an authorized representative of the  Transmission \nDeveloper Applicant, to register with NERC in accordance with NERC’s \nregistration guidelines as the transmission owner (TO), transmission \noperator (TOP), and transmission planner (TP), as those terms are defined \nby NERC, for all Competitive Transmission Facilities that the \nTransmission Developer Applicant, if designated as the Selected \nDeveloper, will own; or (ii) demonstrate that the Transmission Developer \nApplicant is already registered with NERC, in accordance with NERC’s \nregistration guidelines, as the transmission owner (TO), transmission \noperator (TOP), and transmission planner (TP), as those terms are defined \nby NERC; \n(e)\nThe Transmission Developer Applicant shall submit a written \ncommitment, signed by an authorized representative of the Transmission"},{"page":677,"startToken":187703,"endToken":187941,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nDeveloper Applicant, that if designated as the Selected Developer, the \nTransmission Developer Applicant shall either: (i) contract with the \ninterconnecting Local Balancing Authority(s) to include the Competitive \nTransmission Facilities within the boundaries of the interconnecting LBA \nand demonstrate to the satisfaction of the Transmission Provider and per \nagreement by the interconnecting LBA that applicable LBA-related tasks \nassociated with the proposed Competitive Transmission Facilities that may \nbe delegated to an LBA by the Balancing Authority Agreement will be \ncarried out either by the LBA or the Transmission Developer Applicant if \ndesignated as a Selected Developer; or ii) execute the Balancing Authority \nAgreement, register with NERC as a Balancing Authority (BA), and be \ndesignated as the Local Balancing Authority for any proposed \nCompetitive Transmission Facilities, unless the Transmission Developer \nApplicant is already registered with NERC as a BA and designated as an \nLBA for one or more of the existing transmission facilities that may \ninterconnect directly with any Competitive Transmission Facilities \nassociated with the Competitive Transmission Project(s) that the \nTransmission Developer may be awarded;\n(f)\nThe Transmission Developer Applicant shall make a written commitment, \nsigned by an authorized representative of the Transmission Developer \nApplicant, that, if designated as a Selected Developer, it shall comply with \nthe FERC Form 715 Part 4 TRPC, Transmission Planning Criteria and"},{"page":678,"startToken":187941,"endToken":188137,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nGuidelines on file with FERC and established by each incumbent \nTransmission Owner whose existing transmission facilities will \ninterconnect directly with the Competitive Transmission Facilities; and\n(g)\nThe Transmission Developer Applicant must make a written commitment, \nsigned by an authorized representative of the  Transmission Developer \nApplicant, that, if it is designated as a Selected Developer, it shall comply \nwith current requirements and standards regarding the interconnection of \ntransmission facilities published by each  Transmission Owner or non-\nMember to which Competitive Transmission Facilities will interconnect \nincluding, but not limited to, those standards and requirements required for \ncompliance with the applicable NERC Facilities Design, Connections, and \nMaintenance (“FAC”) Reliability Standards.  \nVIII.B.4.1.\nProject Implementation Requirements:  \nEach Transmission Developer Applicant shall submit documentation to \ndemonstrate to the Transmission Provider that the Transmission Developer \nApplicant has or can obtain sufficient capabilities and competencies to satisfy the \nfollowing project implementation requirements for Competitive Transmission \nProjects:  \n(a)\nProject management; \n(b)\nRouting and siting studies including public outreach;  \n(c)\nPreliminary and detailed engineering and surveying;\n(d)\nMaterial and equipment procurement;"},{"page":679,"startToken":188137,"endToken":188374,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\n(e)\nConstruction; and\n(f)\nCommissioning.\nThere are two general methods that a Transmission Developer Applicant \nmay use to demonstrate it will have sufficient capabilities and competencies to \nperform project implementation tasks if chosen as the Selected Developer for a \nCompetitive Transmission Project.  First, the Transmission Developer Applicant \nmay provide evidence that it currently develops transmission projects by listing \ndata, pursuant to templates developed by the Transmission Provider, regarding the \ntransmission facilities it owns and the infrastructure and resources it has in place \nto perform the project implementation activities to develop such transmission \nfacilities, where infrastructure and resources may include, but not necessarily be \nlimited to, employees, contractors, tools, equipment, buildings, vehicles, policies, \nprocesses, and procedures.  Second, a Transmission Developer Applicant can \nprovide a detailed business implementation plan describing how it would acquire \nthe capabilities and competencies to perform the specific project implementation \ntasks listed above, including plans for: (i) retaining personnel or contractors; (ii) \nutilizing infrastructure and resources owned and operated by an affiliate company; \n(iii) qualifying personnel and contractors utilized; (iv) acquiring required tools, \nequipment, and vehicles; (v) development of project management, engineering, \nmaterial, and construction standards and practices to be followed for specific \ntypes of facilities; (vi) route and site studies (including public outreach); and (vii) \nprocuring adequate capital to develop transmission projects."},{"page":680,"startToken":188374,"endToken":188631,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nIn the event that a Transmission Developer intends to demonstrate its \nproject implementation qualifications by obtaining the requisite capabilities and \ncompetencies by contracting with third parties, the Transmission Developer \nApplicant shall submit either as part of its business implementation plan or in \nseparate documentation an explanation of the capabilities and competencies that \nthe Transmission Developer Applicant possesses at the time of application and \nthose capabilities and competencies for which the Transmission Developer \nApplicant intends to contract in order to demonstrate its ability to satisfy the \nforegoing project implementation requirements for Competitive Transmission \nProjects.  For each capability or competency that the Transmission Developer \nApplicant does not possess but intends to procure through contracting with third \nparties, the Transmission Developer Applicant shall provide a detailed contracting \nplan that contains a detailed description of the steps the Transmission Developer \nApplicant intends to take to procure needed capabilities or competencies if it is \nchosen as the Selected Developer for a Competitive Transmission Project.\nThe Transmission Developer Applicant shall not be required to have \nexecuted contracts with third parties to obtain all required capabilities or \ncompetencies at the time of application in order to prequalify as a Transmission \nDeveloper.  However, the Transmission Developer Applicant bears the burden of \nidentifying the capabilities or competencies it possesses and those for which it \nmust contract with third parties and that the Transmission Developer Applicant \nhas a realistic contracting plan for obtaining those capabilities."},{"page":681,"startToken":188631,"endToken":188811,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nThe Transmission Developer Applicant shall include a written certification \nsigned by an authorized representative of the Transmission Developer Applicant \nstating that the information in the submission is true and accurate.\nVIII.B.4.2 \nOperations, maintenance, repair, and replacement requirements:\n \nEach Transmission Developer Applicant shall submit documentation that \ndemonstrates to the Transmission Provider that the  Transmission Developer \nApplicant possesses or can obtain sufficient capabilities and competencies to \nadequately perform the following operations, maintenance, testing, inspection, \nrepair, and replacement tasks for any Competitive Transmission Facilities \nassociated with a Competitive Transmission Project once such facilities are in \nservice and part of the Transmission System: \n(a)\nForced outage response for transmission line circuits; \n(b)\nForced outage response for substations;  \n(c)\nSwitching for transmission line circuits; \n(d)\nSwitching for substations; \n(e)\nTransmission line emergency repair;\n(f)\nSubstation emergency repair and testing; \n(g)\nTransmission line preventative and/or predictive  maintenance, \nincluding vegetation management;  \n(h)\nSubstation preventative and/or predictive maintenance including \nequipment testing;"},{"page":682,"startToken":188811,"endToken":189027,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\n(i)\nMaintenance and management of spare parts, spare structures, \nand/or spare equipment inventories for substations and/or \ntransmission lines, as applicable, including description of any \nagreements to share spare equipment, spare parts, and/or spare \nstructures with other transmission entities;\n(j)\nReal-time operations monitoring and control capabilities; \n(k)\nMajor facility replacements or rebuilds required as a result of \ncatastrophic destruction or natural aging through normal wear and \ntear, including financial strategy to facilitate timely replacements \nand/or rebuilds; and\n(l)\nOnce a Transmission Developer, the Transmission Provider may \nrequire additional demonstration of qualifications to operate, \nmaintain, restore, test, inspect, and replace specific Competitive \nTransmission Facilities associated with specific Competitive \nTransmission Projects for a specific Request for Proposals.\nThere are two general methods that a Transmission Developer Applicant \nmay use to demonstrate it will have sufficient capabilities and competencies to \nperform operations and maintenance services if chosen as the Selected Developer \nfor a Competitive Transmission Project.  First, Transmission Developer Applicant \nmay provide evidence that it currently owns and/or operates and maintains \nelectric transmission facilities by listing data, pursuant to templates developed by \nthe Transmission Provider, regarding the transmission facilities it owns and/or"},{"page":683,"startToken":189027,"endToken":189274,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\noperates and maintains and the infrastructure and resources it has in place to \nperform the operations and maintenance activities for such transmission facilities, \nwhere infrastructure and resources may include, but not necessarily be limited to, \nemployees, contractors, tools, equipment, buildings, spare materials and \nequipment, vehicles, policies, processes, and procedures.  Second, a Transmission \nDeveloper Applicant can provide a detailed business implementation plan \ndescribing how it would acquire the capabilities and competencies to perform the \nspecific operations and maintenance tasks listed above, including plans for: (i) \nretaining personnel or contractors; (ii) utilizing infrastructure and resources \nowned and operated by an affiliate company; (iii) qualifying personnel and \ncontractors utilized; (iv) acquiring required tools, equipment, and vehicles; (v) \ndevelopment of maintenance standards and practices to be followed for specific \ntypes of facilities; (vi) developing standards governing where personnel, \nequipment, and spare parts/equipment will be maintained with respect to potential \nfuture facilities (e.g., maximum distance between facility and local office, etc.); \n(vii) emergency response times; and (viii) maintaining adequate capital \nprocurement capabilities to rebuild facilities following major catastrophic outages \n(including property insurance and risk mitigation strategies).  \nIn the event that a Transmission Developer Applicant intends to \ndemonstrate its operations and maintenance, repair and replacement qualifications \nby obtaining the requisite capabilities and competencies by contracting with third \nparties, the Transmission Developer Applicant shall submit, either as part of its"},{"page":684,"startToken":189274,"endToken":189529,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nbusiness implementation plan or in separate documentation, an explanation of the \ncapabilities and competencies that the Transmission Developer Applicant \npossesses at the time of application and those capabilities and competencies for \nwhich the Transmission Developer Applicant intends to contract in order to \ndemonstrate its ability to implement the foregoing project operation, maintenance, \nrepair, and replacement requirements for Competitive Transmission Projects.  For \neach capability or competency that the Transmission Developer Applicant does \nnot possess but intends to procure through contracting with third parties, the \nTransmission Developer Applicant shall provide a detailed contracting plan that \ncontains a detailed description of the steps the Transmission Developer Applicant \nintends to take to procure needed capabilities or competencies if it is chosen as the \nSelected Developer for a Competitive Transmission Project.\nThe Transmission Developer Applicant shall not be required to have \nexecuted contracts with third parties to obtain all required capabilities or \ncompetencies at the time of application in order to prequalify as a Qualified \nTransmission Developer.  However, the Transmission Developer Applicant bears \nthe burden of identifying the capabilities or competencies it possesses and those \nfor which it must contract with third parties and that the Transmission Developer \nApplicant has a realistic contracting plan for obtaining those capabilities. \nThe Transmission Developer Applicant shall include a written certification \nsigned by an authorized representative of the Transmission Developer Applicant \nstating that the information in the submission is true and accurate."},{"page":685,"startToken":189529,"endToken":189743,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nVIII.B.4.3.\nLegal Requirements:  \nEach Transmission Developer Applicant shall submit the following \ninformation and demonstrate to the Transmission Provider that the information \nsubmitted represents an acceptable level of risk to rely on the Transmission \nDeveloper Applicant, if designated a Selected Developer, to successfully \nimplement a Competitive Transmission Project and own and operate the \nassociated transmission facilities once in service.  The information submitted \nmust include written certification signed by an authorized representative of the \nTransmission Developer Applicant stating that the submitted information is \naccurate:  \n(a)\nA summary of legal and/or regulatory violations during the past \nfive (5) years or, if the Transmission Developer Applicant has been \nin business for less than five years, the number of years for which \nthe Transmission Developer Applicant has been in business, by the \nTransmission Developer Applicant found by federal or state courts, \nfederal regulatory agencies, state public utility commissions, other \nregulatory agencies, or attorneys general. This includes, but is not \nlimited to, the Federal Energy Regulatory Commission, North \nAmerican Electric Reliability Corporation Reliability Standards, \nSecurities Exchange Commission (“SEC”) regulations, U.S. \nCommodity Futures Trading Commission (“CFTC”) regulations, \nand other applicable requirements.  Notwithstanding the foregoing,"},{"page":686,"startToken":189743,"endToken":189939,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nthe Transmission Developer Applicant does not need to provide \nany information regarding violations of the Applicable Reliability \nStandards that were resolved as a compliance exception as defined \nby the NERC rules of procedure.\n(b)\nA summary of any and all instances in which the Transmission \nDeveloper Applicant is currently under investigation or is a \ndefendant in a proceeding involving an attorney general or any \nstate or federal regulatory agency, for violation of any laws, \nincluding regulatory requirements, during the past five years or, if \nthe Transmission Developer Applicant has been in business for \nless than five years, the number of years for which the \nTransmission Developer Applicant has been in business. The \nTransmission Developer Applicant shall include an affidavit \nsigned by an authorized officer of the Transmission Developer \nApplicant’s company stating that the information in the submission \nis true and accurate and that the Transmission Developer Applicant \nwill comply with all applicable requirements in this Tariff, the \nBusiness Practices Manuals, or other applicable Transmission \nProvider documents or agreements.\nVIII.B.4.4\nFinancial Requirements:"},{"page":687,"startToken":189939,"endToken":190171,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nEach Transmission Developer Applicant shall submit the following \ninformation and demonstrate to the Transmission Provider that the information \nsubmitted represents an acceptable level of risk to rely on the Transmission \nDeveloper Applicant to successfully implement a Competitive Transmission \nProject and own and operate the associated transmission facilities once in service.  \nThe information submitted must include written certification signed by an \nauthorized representative of the Transmission Developer Applicant stating that \nthe submitted information is accurate:  \n(a)\nA proposed financial plan demonstrating adequate capital resources (e.g., \ncurrent assets, revolving lines, commercial paper, letter of credit, stock or \nbond issuance or other sources of liquidity) are available to the  \nTransmission Developer Applicant to allow for Competitive Transmission \nProjects to be implemented on schedule and associated Competitive \nTransmission Facilities to be operated and maintained appropriately after \nthe facilities are in service.\n(b)\nThe credit rating(s) for the Transmission Developer Applicant from \nMoody’s Investor Services, Inc., Standard and Poor’s Rating Group and/or \nother Nationally Recognized Statistical Rating Organization (“NRSRO”) \nas recognized by the Securities and Exchange Commission (“SEC”).  In \nthe event the Transmission Developer Applicant is rated by more than one \nNRSRO, then the lowest rating will be the benchmark for consideration of \ndemonstrating and maintaining an investment grade credit rating.  For"},{"page":688,"startToken":190171,"endToken":190429,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nexample, an investment grade rating is considered to be a rating of Baa3 or \nabove from Moody’s Investor Services, Inc. or BBB- or above from \nStandard and Poor’s Rating Group (equivalent ratings will be used for \nother rating agencies).  The focus of the review will be on the entity’s \nunsecured, senior long-term debt ratings (not supported by third-party \nenhancements).  If unsecured, senior long-term debt ratings are not \navailable, the Transmission Provider may consider Issuer Ratings. \nIn the event the Transmission Developer Applicant does not have \nan investment grade rating, the Transmission Provider will consider the \nother information the Transmission Developer Applicant has submitted to \nevaluate its financial capability to construct the transmission facility in a \ntimely manner, and to maintain and operate it reliably for the long term.  \n(c)\nGeneral financial information, including two (2) years of audited financial \nstatements with notes to the financials and a signed commitment by an \nauthorized representative of the Transmission Developer Applicant that it \nis not aware of any material events or circumstances that would likely \nresult in a material adverse weakness in financial strength throughout \nproject implementation of future Competitive Transmission Projects that it \nmight be awarded after it is certified as a Transmission Developer.   In the \nevent the Transmission Developer Applicant does not have two (2) years \nof audited financial statements and has not submitted two (2) years of \naudited financial statements from an Affiliate providing an executed"},{"page":689,"startToken":190429,"endToken":190700,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nStatement of Support, the Transmission Developer Applicant must submit \nan audited balance sheet dated within the last ninety (90) days. It must also \nsubmit pro forma financials for the next fiscal year which include an \nincome statement, balance sheet, and statement of cash flows.\n(d)\nA summary of any history of bankruptcy, dissolution, merger, or \nacquisition of the Transmission Developer Applicant, or any predecessors \nin interest for the current calendar year and the five (5) calendar years \nimmediately preceding its submission of the Transmission Developer \nApplication.  This information must also be submitted for any Affiliate \nproviding a Statement of Support to satisfy any of the requirements in \nSection VIII.B.4.4 of this Attachment FF. \nVIII.B.5.\nVoluntary Termination of Qualified Transmission Developer Status:\nA Qualified Transmission Developer that desires to voluntarily terminate its’ \nstatus as a Qualified Transmission Developer, may do so at any time by notifying the \nTransmission Provider.  Upon such notification, the Transmission Provider will update \nthe Qualified Transmission Developer list within thirty (30) Calendar Days of the \nnotification.  Failure of a Qualified Transmission Developer to timely submit a \nrecertification statement pursuant to Section VIII.B.3.1 of this Attachment FF of the \nTariff shall be deemed a voluntary termination under this Section VIII.B.5 of this \nAttachment FF.  A terminated Qualified Transmission Developer may become a \nQualified Transmission Developer again by following the process outlined in Section \nVIII.B.2 of this Attachment FF of the Tariff for Transmission Developer Applicants"},{"page":690,"startToken":190700,"endToken":190942,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nseeking Qualified Transmission Developer status in a subsequent qualification process. \nVIII.B.6. Confidential Treatment of Competitive Developer Qualification \nInformation:\nAll information submitted with Transmission Developer Applications and \nrecertification submittals will be considered Confidential Information, except for the \nname of the organization to be posted on the Qualified Transmission Developer list, and \nwill not be publicly posted or shared with any individual except for employees of the \nTransmission Provider and/or contractors of the Transmission Provider that have \nexecuted appropriate non-disclosure agreement(s). \nVIII.B.7.\nAlternative Dispute Resolution:\nAny Transmission Developer Applicant who is not approved as a Qualified \nTransmission Developer by the Transmission Provider may request alternative dispute \nresolution under Attachment HH of the Tariff within thirty (30) Calendar Days of \nreceiving the Transmission Provider’s written explanation detailing its determination to \ndeny the Transmission Developer Application.  Any entity that is not recertified as a \nQualified Transmission Developer by MISO, or a Qualified Transmission Developer \nwhose Qualified Transmission Developer status is terminated, may request alternative \ndispute resolution under Attachment HH of the Tariff within
thirty (30) Calendar Days \nof receiving the MISO’s written explanation detailing its determination to not recertify or \nto terminate the entity’s Qualified Transmission Developer status.\nVIII.B.8. \nOngoing Responsibilities of Qualified Transmission Developers: \nEach Qualified Transmission Developer has an ongoing duty to provide the"},{"page":691,"startToken":190942,"endToken":191226,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nTransmission Provider with notification as soon as reasonably practical should any of the \nchanges specified in Section VIII.B.3.1 of this Attachment FF occur and a copy or link to \ntheir audited financial statements annually, within thirty (30) Calendar Days of such \nstatements being prepared.  The Competitive Transmission Executive Committee shall \nhave the exclusive and final authority to make determinations regarding the continued \nqualifications of Qualified Transmission Developers based upon the information received \nin accordance with this Section VIII.B.8.\nVIII.C.\nREQUEST FOR PROPOSALS\nShould Appendix A of a Transmission Provider Board approved MTEP contain Eligible \nProjects, the Transmission Provider will review each such Eligible Project to determine whether \nor not it contains any Competitive Transmission Facilities.  The Transmission Provider will \nrelease a Request for Proposals (RFP) for each Competitive Transmission Project pursuant to \nSection VIII.C of this Attachment FF and the applicable Business Practices Manuals.  If \nAppendix A of a Transmission Provider Board approved MTEP contains only one (1) \nCompetitive Transmission Project, the Transmission Provider will release an RFP within sixty \n(60) Calendar Days of the date the Transmission Provider Board approved the Competitive \nTransmission Facilities for inclusion in Appendix A of the MTEP.  If Appendix A of a \nTransmission Provider Board approved MTEP contains multiple Competitive Transmission \nProjects, the Transmission Provider shall have the option to stagger the release of each RFP \nassociated with the multiple Competitive Transmission Projects.  \nIf the Transmission Provider elects to stagger the release of RFPs, the Transmission \nProvider shall take the following actions following the date that  the Transmission Provider"},{"page":692,"startToken":191226,"endToken":191554,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nBoard approved the Competitive Transmission Facilities for inclusion in Appendix A of the \nMTEP: (1) Within ten (10) Business Days publicly post on its website a statement indicating that \nthe Transmission Provider will stagger the RFP release dates; (2) Within thirty (30) Calendar \nDays post a schedule listing the planned release dates for each RFP, with the first RFP being \nreleased within sixty (60) Calendar Days of the date the respective MTEP was approved by the \nTransmission Provider Board.  In determining the schedule of RFP releases when staggering is \nused, the Transmission Provider will consider the timing impacts of the Competitive Developer \nSelection Process with respect to the in-service dates of the Competitive Transmission Projects.  \nIn all events, the schedule of RFP releases developed by the Transmission Provider shall provide \nthat all RFPs are released not later than three hundred and sixty five (365) Calendar Days after \nthe date the Transmission Provider Board approved the Competitive Transmission Facilities for \ninclusion in Appendix A of the MTEP.  If the Transmission Provider elects not to stagger the \nrelease of RFPs, the Transmission Provider shall release each RFP within sixty (60) Calendar \nDays of the date the respective MTEP was approved by the Transmission Provider Board.\nVIII.C.1.\nMinimum Contents of a RFP:\nEach RFP shall include, at a minimum, a listing of each Competitive Transmission \nFacility contained within the Competitive Transmission Project, the Proposal Submission \nDeadline, the applicable items specified in Sections VIII.C.1.1 and VIII.C.1.2 of this Attachment \nFF to the Tariff, any applicable items specified in the Transmission Provider’s Business Practices \nManuals, and a list of the current transmission facility interconnection standards and \nrequirements, established by the Transmission Owner(s) and established by any transmission \nowner(s) that are not a Member who have chosen to provide interconnection standards and"},{"page":693,"startToken":191554,"endToken":191854,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nrequirements to the Transmission Provider, to which the Competitive Transmission Project will \ninterconnect.  The Transmission Provider reserves the right to specify any additional information \nin a RFP including, but not limited to, any additional information for specific Competitive \nTransmission Line Facilities and/or Competitive Substation Facilities. The Transmission \nProvider shall include in each RFP a list of any aspects, or elements of the Competitive \nTransmission Project that the Transmission Provider anticipates at the time of posting to be \nparticularly important for the success of the Competitive Transmission Project. This information \nshall be provided for informational purposes only and shall not alter the criteria and/or \nweightings applicable to evaluation of the Proposals pursuant to Sections VIII.E through \nVIII.E.3 of this Attachment FF.\nIf and to the extent a RFP contains any Critical Energy Infrastructure Information (CEII), \nthe Transmission Provider will redact such CEII for public posting and create a non-public RFP \ncontaining the CEII which will be available to entities and individuals that have executed the \nappropriate CEII and non-disclosure agreements required by the Transmission Provider.  \nInformation on how to request the non-public RFP will be provided in the publicly posted RFP.  \nPursuant to Section VIII.A.1 of this Attachment FF, only Competitive Transmission Facilities \neligible under state law will be included in the Competitive Transmission Project where (i) all \nother Competitive Transmission Facilities and (ii) upgrades as described in Section VIII.A.2 of \nthis Attachment FF will be assigned to the applicable incumbent Transmission Owner in \naccordance with the ISO Agreement. \nVIII.C.1.1\nRFP Requirements for Competitive Transmission Line Facilities:\nEach RFP that includes one or more Competitive Transmission Line"},{"page":694,"startToken":191854,"endToken":192041,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nFacilities will specify, at a minimum, the following items for each Competitive \nTransmission Line Facility:\n (a)\nExpected in-service date;\n(b)\nNominal operating voltage level in kV and voltage characteristics \n(i.e., three-phase AC, bipolar DC, etc.) for each transmission \ncircuit;\n(c)\nTerminating substations and buses for each transmission circuit;\n(d)\nMinimum required normal and emergency load ratings for both \nsummer and winter seasons for each transmission circuit; and\n(e)\nMaximum allowable positive sequence impedance for each \ntransmission circuit when determined applicable by planning \nstudies performed by the Transmission Provider.\nVIII.C.1.2\nRFP Requirements for Competitive Substation Facilities:\nEach RFP that includes one or more Competitive Substation Facilities will \nspecify, at a minimum, the following information for each Competitive Substation \nFacility:\n(a)\nExpected in-service date;\n(b)\nList of all transmission buses within the Competitive Substation \nFacility, including nominal operating voltage level in kV and \nvoltage characteristics;\n(c)\nList of all major equipment and facilities within the Competitive \nSubstation Facility and associated terminating buses including"},{"page":695,"startToken":192041,"endToken":192228,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\npower transformers, voltage regulators, phase angle regulators, \nseries reactors, series capacitors, shunt reactors, shunt capacitors, \nstatic VAR compensators, DC converters, transmission line circuit \nterminals, generator terminals, and loads;\n(d)\nLimitations on and/or requirements for bus configurations when \ndetermined applicable by planning studies performed by the \nTransmission Provider including required load ratings of circuit \nbreakers, disconnects, bus sections and other load carrying \nequipment under alternative bus configurations;\n(e)\nRequired load ratings for all load carrying equipment and facilities \nidentified in item (c) above;\n(f)\nWinding connection and tap requirements for power transformers, \nvoltage regulators, phase angle regulators and load tap changers \nwhen determined necessary by planning studies performed by the \nTransmission Provider;\n(g)\nImpedance requirements for power transformers, phase angle \nregulators, series reactors and series capacitors when determined \nnecessary by planning studies performed by the Transmission \nProvider; and\n(h)\nLimitations on and/or requirements for protection systems when \ndetermined applicable by a planning driver or Applicable \nReliability Standard or in order to ensure a compatible"},{"page":696,"startToken":192228,"endToken":192498,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ninterconnection with existing protection systems associated with \nexisting transmission facilities to which the Competitive \nTransmission Facilities will interconnect.\nVIII.D.\nPROPOSALS\nProposals may be submitted only in response to an RFP issued by the Transmission \nProvider and only by entities that are certified as a Qualified Transmission Developer at the time \nsuch Proposal is submitted.  Once submitted and unless withdrawn pursuant to Section VIII.D.8 \nof this Attachment FF, Proposals shall be held open as offers capable of acceptance by the \nTransmission Provider until such time as the Transmission Provider announces the identity of the \nSelected Developer and designates an Alternate Selected Developer pursuant to Sections \nVIII.E.2 and VIII.H of this Attachment FF.   \nVIII.D.1.\nProposal Submission Deadline:\nProposals shall be submitted to the Transmission Provider no later than 5:00 PM \nEPT on the Proposal Submission Deadline.  The Proposal Submission Deadline will be \nthe date specified in the RFP, which shall not exceed one hundred and sixty-five (165) \nCalendar Days from the date the Transmission Provider issued the RFP, unless the one \nhundred and sixty-five (165) day maximum duration causes the Proposal Submission \nDeadline to fall on a Saturday, Sunday, or holiday in which case the Proposal Submission \nDeadline shall be the next Business Day that is not a holiday.\nVIII.D.2. Proposal Deposit:\nAn RFP Respondent must submit an initial deposit, in an amount not to exceed \n$150,000.00 (in August 2023 dollars), to the Transmission Provider.  The Transmission"},{"page":697,"startToken":192498,"endToken":192798,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nProvider shall calculate the maximum amount of the deposit by determining the inflation \nadjustment in accordance with the inflation calculator located at the U.S. Bureau of Labor \nStatistics website.  The inflation adjustment shall be calculated from August 2023, to the \nmost up-to-date data available at the time the notification takes place, where such amount \nwill be rounded to the nearest $100.  The RFP shall state the amount of each deposit, the \ndate(s) by which such deposit must be received, and any applicable submission \nrequirements. In no event shall an RFP specify a deadline for submitting Proposal \ndeposits that is more than thirty (30) Calendar Days prior to the Proposal Submission \nDeadline.  Only one (1) proposal deposit is required for each Proposal, regardless of the \nnumber of RFP Respondents and Proposal Participants involved with the Proposal. In the \nevent that an RFP Responder submits an initial deposit for a Proposal before the Proposal \nSubmission Deadline specified in an RFP but does not submit the corresponding Proposal \nfor such RFP by the Proposal Submission Deadline, the Transmission Provider shall \nrefund the full amount of such deposit within thirty (30) Calendar Days after the Proposal \nSubmission Deadline. Each deposit submitted to the Transmission Provider will be held \nin an interest-bearing account.\nVIII.D.3. RFP Administration and Proposal Evaluation Expenses:\nRFP Respondents shall, on a pro rata basis, be responsible for paying the actual \ncosts incurred by the Transmission Provider, including the costs of the expert \nconsultant(s) engaged to assist the Transmission Provider, in administering the \nCompetitive Developer Selection Process for the specific RFP that the RFP \nRespondent(s) responded to through its Proposal submission.  The Transmission Provider"},{"page":698,"startToken":192798,"endToken":193109,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nwill track all costs, including the Transmission Provider’s time and the costs of the expert \nconsultant(s), in administering the Competitive Developer Selection Process for each \nspecific RFP.\nThe Transmission Provider shall evaluate all Proposals submitted in response to a \nspecific RFP together and apply each of their respective proposal deposits equally to the \ncost of administering the Competitive Developer Selection Process for that specific RFP, \nexcept for Proposals that were found to be deficient by the Transmission Provider and \nwere refunded 90% of the proposal deposit under Section VIII.D.10 of Attachment FF of \nthe Tariff.  Any shortfall will be billed by the Transmission Provider on a pro rata basis \nto each Proposal submitted in response to the RFP.  Each respective RFP Respondent(s) \nis responsible for paying the pro rata share allocated to its Proposal(s) within thirty (30) \nCalendar Days of receiving notice of such shortfall.  If a RFP Respondent fails to pay the \nexpenses allocated to any of the Proposals it submitted within sixty (60) Calendar Days \nof the monthly invoice remittance date, those Proposals shall be disqualified from further \nconsideration and evaluation by the Transmission Provider.  Furthermore, the RFP \nRespondent may lose its Qualified Transmission Developer designation at the sole \ndiscretion of the Transmission Provider as they are no longer in good standing with the \nTransmission Provider pursuant to Section VIII.B.4.a of Attachment FF of the Tariff.\nAny funds remaining after the Transmission Provider has completed the \nCompetitive Developer Selection Process, including the issuance of refunds to Proposals \nthat were withdrawn pursuant to Section VIII.D.8 of Attachment FF of the Tariff or \ndeemed deficient pursuant to Section VIII.D.10 of Attachment FF of the Tariff, will be"},{"page":699,"startToken":193109,"endToken":193364,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nrefunded by the Transmission Provider on a pro rata basis to each Proposal within \nseventy-five (75) Calendar Days following the designation of the Selected Proposal, \nincluding any interest actually earned on such deposits.\nVIII.D.4.\nProposal Submission Format:\nProposals shall be submitted to the Transmission Provider prior to the Proposal \nSubmission Deadline.  Proposals shall be submitted to the Transmission Provider in \naccordance with the requirements specified in the RFP and Business Practices Manuals \n(e.g. the location, format, number of copies, use of submission templates, etc.).  Proposals \nmay be submitted in one of two different forms: (i) a Single-Developer Proposal; or (ii) a \nJoint-Developer Proposal.  The Transmission Provider may provide template(s) for \nProposal submissions and, if provided, RFP Respondents shall utilize the template(s) in \nsubmitting their Proposals.  Any questions or inquiries regarding an issued RFP from the \ndate the RFP was issued through the date that the selection report for the Competitive \nTransmission Project is publicly posted shall be solely directed to the Transmission \nProvider through the contacts listed in the RFP and not to the interconnecting incumbent \nMember(s).\nVIII.D.4.1.\nSingle-Developer Proposal:\nA Single-Developer Proposal is a Proposal submitted by a single RFP \nRespondent that would become the sole Selected Developer for the Competitive \nTransmission Project, should its Single-Developer Proposal be designated as the \nSelected Proposal by the Transmission Provider.\nVIII.D.4.2.\nJoint-Developer Proposal:"},{"page":700,"startToken":193364,"endToken":193627,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nA Joint-Developer Proposal is a Proposal submitted jointly by two or more \nRFP Respondents that would each be designated as Selected Developers for the \nCompetitive Transmission Project, should the Joint-Developer Proposal be \ndesignated as the Selected Proposal by the Transmission Provider.  The Joint-\nDeveloper Proposal shall only be submitted once to the Transmission Provider by \none of the RFP Respondents.  Each RFP Respondent of a Joint-Developer \nProposal shall either: (i) acknowledge and agree to be jointly and severally liable \nfor all aspects of the submitted Joint-Developer Proposal; or (ii) clearly specify \nthe aspects of the Competitive Transmission Project that each RFP Respondent \nwill be solely liable, such that all aspects of the submitted Joint-Developer \nProposal are accounted for.  If at least one of the RFP Respondents does not \ncommit to being jointly and severally liable for all aspects of the submitted Joint-\nDeveloper Proposal, the existence of any grounds that would trigger Variance \nAnalysis, including default and termination of the Selected Developer Agreement, \nwith respect to any one RFP Respondent shall trigger Variance Analysis of the \nentire Joint-Developer Proposal, pursuant to Attachment FF Section IX of the \nTariff.\nVIII.D.4.3.\nProposal Participants:\nRFP Respondents may convey an interest of the Competitive \nTransmission Project to one or more Proposal Participant(s) at any time, provided \nhowever that (i) the RFP Respondent(s) identified and disclosed in its Proposal \nthe Proposal Participants to which an interest will be conveyed; (ii) RFP"},{"page":701,"startToken":193627,"endToken":193901,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nRespondent(s) convey such an interest on substantially the same terms as \ndisclosed in the Proposal; (iii) the Aggregate ATRR for the Competitive \nTransmission Project shall not exceed the Aggregate ATRR contained in the \nProposal; (iv) each RFP Respondent and each Proposal Participant to which an \ninterest will be conveyed has each provided a written agreement committing to \nany applicable cost-containment measures contained in the Proposal; (v) each \nRFP Respondent and each identified Proposal Participant has each executed the \nISO Agreement, to the extent that the entity is not already a Member, but no later \nthan the date the Competitive Transmission Facilities are energized; and (vi) each \nRFP Respondent and each identified Proposal Participant has listed the \nCompetitive Transmission Facilities for which it owns or has been conveyed an \nownership interest in Appendix H of the ISO Agreement (i.e. the list of \ntransmission facilities transferred to MISO’s functional control for the purposes of \nplanning and operation).  If a Proposal identifies one or more Proposal \nParticipants, the RFP Respondent(s) that convey such an interest shall \nacknowledge and agree to be responsible for all aspects of the Competitive \nTransmission Project, notwithstanding any default of any Proposal Participant’s \nobligations, whether identified in the Proposal or under any contractual \nagreement(s) between the Proposal Participant and the respective RFP \nRespondent(s).  Except as provided in Section VIII.D.5 of Attachment FF of the \nTariff, the Transmission Provider shall only evaluate the capabilities and \nresources of the RFP Respondent(s) when evaluating a Proposal."},{"page":702,"startToken":193901,"endToken":194169,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nVIII.D.5. Proposal Content Requirements:\nEach Proposal shall include all data and information required by the RFP, \napplicable Business Practices Manuals, and Tariff including, but not limited to, the items \nspecified below in Section VIII.D.5 of Attachment FF of the Tariff.  RFP Respondents \nmay include additional data and information in the Proposal if they believe it is relevant \nand useful to the evaluation  of their Proposal.  If and to the extent RFP Respondents are \nutilizing any resources, capabilities, or competencies from an Affiliate, those resources, \ncapabilities, or competencies shall be clearly identified in the Proposal and the RFP \nRespondent shall submit an “Acknowledgement of Support” signed by an authorized \nagent of the  Affiliate expected to provide such support and the RFP Respondent.  An \n“Acknowledgement of Support” may also be provided, but is not required, from any \nother entity on which RFP Respondent(s) intends to rely for such support.\nVIII.D.5.1.\nGeneral Proposal Information:\nVIII.D.5.1.1. Identification of RFP Respondents:\nEach Proposal shall clearly identify each RFP Respondent involved in the \nProposal and identify a primary and secondary point of contact for the Proposal \nthat will represent the RFP Respondent(s) in any communications and actions \nwith the Transmission Provider.\nEach Joint-Developer Proposal shall clearly and specifically identify each \nRFP Respondent’s respective roles and responsibilities (including the respective \npercentage of responsibility) to finance, construct, implement, own, operate, \nmaintain, repair, and restore the Competitive Transmission Project in such a"},{"page":703,"startToken":194169,"endToken":194435,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nmanner that one hundred percent (100%) of the responsibilities are identified and \ndisclosed in the Proposal.  Any agreements between or among the RFP \nRespondents governing the division of roles and responsibilities shall also be \nsubmitted with the Proposal\nFurthermore, each RFP Respondent involved in a Joint-Developer \nProposal shall include either: (i) an agreement to be jointly and severally liable for \nall aspects of the Joint-Developer Proposal; or (ii) clearly specify the aspects of \nthe Competitive Transmission Project that each RFP Respondent will be solely \nliable, such that all aspects of the submitted Joint-Developer Proposal are \naccounted for.  If at least one of the RFP Respondents does not commit to being \njointly and severally liable for all aspects of the Joint-Developer Proposal, the \nexistence of any grounds that would trigger Variance Analysis, including default \nand termination of the Selected Developer Agreement, with respect to any one \nRFP Respondent shall trigger Variance Analysis of the entire Joint-Developer \nProposal, pursuant to Attachment FF Section IX of the Tariff. \nVIII.D.5.1.2. Identification of Proposal Participants:\nEach Proposal shall clearly identify whether the RFP Respondent(s) plan \nto convey an interest of the Competitive Transmission Project to one or more \nProposal Participant(s).  If a RFP Respondent contemplates any conveyance of \ninterest of the Competitive Transmission Project to one or more Proposal \nParticipant(s), it shall clearly and specifically (i) identify each Proposal \nParticipant in the Proposal;  (ii) identify the type and amount of any conveyed"},{"page":704,"startToken":194435,"endToken":194677,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ninterest in the Proposal; (iii) provide any agreements between or among the RFP \nRespondent and the Proposal Participants regarding the conveyed interest in the \nCompetitive Transmission Project; (iv) disclose the expected timing of any such \ntransfer of ownership or interest; (v) provide a written agreement from the RFP \nRespondent and each Proposal Participant to execute the ISO Agreement, to the \nextent that the entity is not already a Member, but no later than the date the \nCompetitive Transmission Facilities are energized, should the Transmission \nProvider designate the proposal as the Selected Proposal; and (vi) the RFP \nRespondent’s written agreement to be responsible for all aspects of the \nCompetitive Transmission Project notwithstanding, any default of any Proposal \nParticipant’s obligations, whether identified in the Proposal or under any \ncontractual agreement(s) between the Proposal Participant and the respective RFP \nRespondent(s).\nVIII.D.5.2.\nProject Implementation Schedule:\nEach Proposal shall contain a detailed project implementation schedule, driven by \nthe required in-service date, for each Competitive Transmission Facility contained in the \nCompetitive Transmission Project which shall include proposed schedules for route and \nsite evaluation, regulatory permitting, land acquisition, engineering and design, land \nsurveying, material procurement, construction, and commissioning/energization for all \nCompetitive Transmission Facilities.\nVIII.D.5.3.\nProject Cost Estimate:\nEach Proposal shall contain a detailed project cost-estimate, based upon the"},{"page":705,"startToken":194677,"endToken":194951,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nreasonably descriptive facility design submitted in the Proposal, for each Competitive \nTransmission Facility in the Competitive Transmission Project.  The cost-estimates \ndeveloped by the Transmission Provider during the transmission planning process and \nutilized for project approval should be considered by RFP Respondents for informational \npurposes only and are not guaranteed to be accurate or complete in all respects.  RFP \nRespondents shall create and rely on their own cost calculations when submitting \nProposals. To the extent that any RFP Respondent or Proposal Participant identified in a \nProposal, or an Affiliate of either, has not committed to forego recovery of such costs, the \nproject cost estimate shall include: \n(i) all costs to develop the Proposal, including any costs of participating in the \nplanning process and Competitive Developer Selection Process for the Competitive \nTransmission Project for which recovery may be sought.  To the extent that a RFP \nRespondent submits more than one Proposal for a Competitive Transmission Project, \nsuch cost estimate shall state all costs for which recovery may be sought if any of the \nProposals submitted by such RFP Respondent for the Competitive Transmission Project \nis selected as the Selected Proposal; and \n(ii) any other pre-commercial expense for which a RFP Respondent or Proposal \nParticipant identified in a Proposal, or an Affiliate of either, may seek recovery if the \nProposal is selected as the Selected Proposal.\nVIII.D.5.4.\nEstimated Annual Transmission Revenue Requirements:\nEach Proposal shall contain separate estimated annual transmission revenue \nrequirements for each RFP Respondent and Proposal Participant involved with the"},{"page":706,"startToken":194951,"endToken":195233,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nProposal beginning in the year costs would first be recovered under Attachment O and \neither Attachment MM or Attachment GG (including any incentives, such as  to collect \nConstruction Work In Progress (“CWIP”) in ratebase or pass-through pre-commercial \nexpenses on a current basis), through the first forty (40) calendar years that the \nCompetitive Transmission Facilities included in the Competitive Transmission Project \nwill be in service, in accordance with Attachment MM of the Tariff for Multi-Value \nProjects and Attachment GG of the Tariff for Market Efficiency Projects, including the \nsupporting detail on the annual allocation factors for operations and maintenance, general \nand common depreciation expense, taxes other than income taxes, income taxes, and \nreturn used to estimate the annual revenue requirements.  \nIf the Proposal involves more than one RFP Respondent or any Proposal \nParticipants, the Proposal shall also include an estimated Aggregate ATRR beginning in \nthe year costs would first be recovered under Attachment O and either Attachment MM \nor Attachment GG (including any incentives, such as to collect CWIP in ratebase or pass-\nthrough pre-commercial expenses on a current basis), through for the first forty (40) years \nthe Competitive Transmission Facilities included in the Competitive Transmission \nProject will be in service representing the combined effect of each RFP Respondents’ and \nProposal Participants’ individual annual transmission revenue requirements.\nVIII.D.5.5.\nBinding Cost-Containment:\nEach Proposal shall contain information and details regarding any binding cost-\ncontainment measures, including any binding cost caps, that may be offered as part of the \nProposal.  If any binding cost-containment measures are submitted as part of the"},{"page":707,"startToken":195233,"endToken":195498,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nProposal, each RFP Respondent and Proposal Participant submitting such binding cost-\ncontainment measures shall also provide a draft term sheet or agreement that clearly \ndescribes in detail the nature of the cost-containment measures being proposed, including \nall exclusions, exceptions, conditions, enforcement mechanisms, interaction with change \norders, and such other information as is specified in the applicable Business Practices \nManuals, as part of the Proposal submittal.\nVIII.D.5.6.\nFinancial Information:\nEach Proposal shall include a detailed financing plan for the Competitive \nTransmission Project.  The financing plan shall conform to the format(s) specified in an \nRFP and must contain information pertaining to the following elements, if applicable, as \nfurther explained in the applicable Business Practices Manuals:\n1) \nA description of capital resources available to fund Competitive Transmission \nProject implementation costs, which demonstrate that the RFP Respondent(s) can \nprocure capital to fund at least one hundred percent (100%) of expected project \nimplementation costs, including any contingencies projected by the RFP \nRespondent(s) to show an ability to cover risks associated with foreseeable cost \noverruns.  \nFor each funding source the RFP Respondent(s) shall provide a description of \nhow much capital is available, when the funds will be obtained, and what \nconditions must to be met to secure the funds.  At a minimum, the RFP \nRespondent(s) shall identify each funding source by type with a brief description \nand state the costs for each funding sources.  If the cost of funds information is"},{"page":708,"startToken":195498,"endToken":195752,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nnot known at the time the RFP Response is submitted, the RFP Respondent(s) \nmay submit a range or estimate and describe the limitations that prevent this \ninformation from being provided.  \n2) \nAn exhibit or a high-level narrative description of the expected cash flows \nbetween the RFP Respondent(s) and the funding sources sufficient to explain the \ntiming, form and volume of cash flows expected between each RFP Respondent \nand the identified funding sources. \n3) \nAn overview schedule of significant expenditures for project implementation \nsufficient to demonstrate that funds will be available when needed for significant \nexpenditures. \n4) \nA description of immediately available funds, that the RFP Respondent(s) shall \nhave access to in order to address unforeseen contingencies that arise during \nproject implementation. \n5) \nInformation describing the RFP Respondent’s plan to obtain Project Financial \nSecurity within the timeframe required by the Selected Developer Agreement in \nsufficient detail to demonstrate that the RFP Respondent(s) reasonably expect(s) \nto be able to satisfy this requirement if selected as the Selected Developer. \n6) \nIn the event that a RFP Respondent intends to rely on personnel, material, \ntechnical, financial, and/or other resources from an Affiliate in its Proposal, the \nRFP Respondent shall provide an Acknowledgment of Support executed by such \nAffiliate, which lists the personnel, material, technical, financial, and/or other \nresources that the RFP Respondent(s) desire(s) the Transmission Provider to"},{"page":709,"startToken":195752,"endToken":196006,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nconsider in evaluating the Proposal to demonstrate that such Affiliate is aware of \nthe RFP Respondent’s reliance on such Affiliate’s resources and will make such \nresources available if the RFP Respondent’s Proposal is selected. \n7)  \nThe credit ratings, if applicable, of the RFP Respondent and any Affiliate \nproviding financial support pursuant to an Acknowledgment of Support and \ngeneral financial information including audited financial statements and notes for \nthe RFP Respondent and any parent or Affiliate providing financial support \npursuant to an Acknowledgment of Support, as well as pro forma financial \nstatements for each calendar year until the RFP Respondent(s) expect(s) to place \nall project facilities into service.\n8) \nThe RFP Respondent’s financial strategy to facilitate timely replacements and \nrebuilds for the life of the project to demonstrate that it reasonably can be relied \nupon to address catastrophic destruction and normal wear and tear.\nVIII.D.5.7.\nReasonably Descriptive Design:  \nEach Proposal shall contain a reasonably descriptive facility design for each \nCompetitive Transmission Facility included in the Competitive Transmission Project.  \nReasonably descriptive facility designs represent descriptions of the core attributes and \nfeatures of a design, not the detailed engineering and design calculations and documents.   \nVIII.D.5.7.1. Design for Competitive Transmission Line Facilities:  \nFor each Competitive Transmission Line Facility, reasonably descriptive \nfacility design proposals must include, if applicable, and as further described by \nthe applicable RFP, the following:"},{"page":710,"startToken":196006,"endToken":196211,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\n(a)\nThe estimated length of the Competitive Transmission Line \nFacility in miles and the basis for the estimate;  \n(b)\nThe proposed conductor type, size, and, if applicable, bundling \nconfiguration;  \n(c)\nThe proposed default or typical structure design attribute(s) (e.g., \nsteel vs. wood vs. aluminum vs. concrete, monopole vs. H-frame \nvs. lattice, single circuit vs. double circuit, self-supporting vs. \nguyed, structural calculation assumptions, etc.) to be used for \ntangent, running angle, in-line dead-end, and angle dead-end \nstructures when feasible and/or for the majority of the Competitive \nTransmission Line Facilities;  \n(d)\nThe estimated positive sequence line impedance and pi-equivalent \nshunt susceptance; \n(e)\nThe calculated normal and emergency seasonal thermal loading \nratings, including the basis for such calculations; \n(f)\nThe proposed type of lightning protection system to be used when \nfeasible and/or for the majority of the Competitive Transmission \nLine Facilities (e.g., shield wires vs. surge arresters, etc.) and key \nattributes (e.g., shielding angle, arrester location and type, etc.); \n(g)\nThe proposed grounding method to be used when feasible and/or \nfor the majority of the Competitive Transmission Line Facilities"},{"page":711,"startToken":196211,"endToken":196409,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\n(e.g., ground rods only, counterpoise, etc.) and key attributes (e.g., \ntargeted structure footing grounding resistance, etc.);  \n(h)\nThe proposed method to address or mitigate adverse impacts of \ngalloping conductors and/or Aeolian vibration, if any (e.g., \nStockbridge dampers, special conductors, etc.);\n(i)\nThe continuous rating of any load carrying switchgear installed on \nthe Competitive Transmission Line Facilities; and  \n(j)\nThe assumed communications systems to be used for the \nCompetitive Transmission Line Facilities to facilitate protective \nrelaying (e.g., fiber optic, power line carrier, microwave, etc.).\nVIII.D.5.7.2. Design for Competitive Substation Facilities:  \nFor each Competitive Substation Facility, reasonably descriptive facility \ndesign proposals shall include, if applicable, and as further described, by the \napplicable RFP, the following:  \n(a)\nA detailed one-line diagram; \n(b)\nThe proposed protection systems including protection schemes, \nany anticipated interaction with existing/other facilities and \nconceptual protection system design (including backup protection \nsystems, if applicable).  Remote system monitoring capability shall \nbe described with major features listed (redundancy, monitored \nparameters, etc.);  \n(c)\nThe detailed specifications for proposed power transformers;"},{"page":712,"startToken":196409,"endToken":196617,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\n(d)\nA description of other substation equipment items, including load \nratings, voltage ratings, fault interrupting ratings, tap data, and \nimpedances as applicable, where other substation equipment \nincludes, but is not limited to, bus sections, circuit breakers, circuit \nswitchers, switches, disconnects, regulating transformers, station \nservice transformers, series and shunt capacitors, series and shunt \nreactors, static VAR compensators, DC conversion equipment, \ninstrument transformers (metering and relaying), wave traps, and \nsurge arresters;  \n(e)\nThe proposed line terminal ratings and basis for calculation, \nincluding limiting element;  \n(f)\nThe basis for load rating calculations on any equipment where \nnameplate continuous ratings are not used; and \n(g)\nA description of the communication system for remote monitoring, \ncontrol and data acquisition facilities, including monitoring and \ncontrol points.  \nVIII.D.5.7.3.\nAdditional reasonably descriptive facility design data:\nAn RFP may require submission of additional facility design data when \ndeemed necessary by the Transmission Provider.  Proposals may also include \nadditional facility data when deemed necessary by RFP Respondents, including \nbut not limited to, optional facility design data listed in the Business Practices \nManuals, which may be considered by the Transmission Provider in the"},{"page":713,"startToken":196617,"endToken":196806,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nevaluation and selection of Proposals.   \nVIII.D.5.8.\nProject Implementation:\nEach Proposal shall contain a description of existing and/or planned project \nimplementation capabilities, relative to the applicable locations and jurisdictions where \nthe Competitive Transmission Facilities will be located, to be used by the RFP \nRespondent(s) to perform the following tasks, as applicable and as further described in \nthe applicable RFP:  \n(a)\nProject management; \n(b)\nRouting/siting evaluation studies for Competitive Transmission Facilities; \n(c)\nRegulatory permitting; \n(d)\nRight-of-way and land acquisition for Competitive Transmission  \nFacilities; \n(e)\nEngineering and surveying required for Competitive Transmission \nFacilities; \n(f)\nMaterial procurement for Competitive Transmission Facilities; \n(g)\nConstruction of Competitive Transmission Facilities;  \n(h)\nCommissioning/energization of Competitive Transmission Facilities; and \n(i)\nSafety during construction of the Competitive Transmission Facilities. \n  VIII.D.5.8.1.Additional Project Implementation Capabilities Data:\nA RFP may require the submission of additional data, when deemed \nnecessary by the Transmission Provider, related to the policies, processes, \nmethods, capabilities, experience, and past performance the RFP Respondent(s)"},{"page":714,"startToken":196806,"endToken":197019,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nProposals may also include additional information regarding project \nimplementation capabilities when deemed necessary by RFP Respondents, \nincluding but not limited to, existing capabilities and past experience regarding \nproject implementation, which may be considered by the Transmission Provider \nin the evaluation and selection of Proposals. \nVIII.D.5.9.\nOperations and Maintenance:\nEach Proposal shall contain a description of existing and/or planned operations, \nmaintenance, repair, and replacement capabilities, relative to the locations and applicable \njurisdictions where the Competitive Transmission Facilities will be located, to be used by \nthe RFP Respondent(s) to perform the following tasks, as applicable and as further \ndescribed in the RFP: \n(a)\nForced outage response for transmission line circuits and substations;  \n(b)\nSwitching for transmission line circuits and substations; \n(c)\nEmergency repair and testing for transmission line circuits and \nsubstations; \n(d)\nPreventative and/or predictive maintenance for transmission line circuits \nand substations, including vegetation management and equipment testing;\n(e)\nMaintenance and management of spare parts, spare structures, and/or \nspare equipment inventories for substations and/or transmission lines,  \nincluding description of any agreements to share spare equipment, spare \nparts, and/or spare structures with other transmission entities;"},{"page":715,"startToken":197019,"endToken":197219,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\n(f)\nReal-time operations monitoring and control capabilities, if the \nCompetitive Transmission Project contains one or more Competitive \nSubstation Facilities; \n(g)\nMajor facility replacements or rebuilds required as a result of catastrophic \ndestruction or natural aging through normal wear and tear, including \nfinancial strategy to facilitate timely replacements and/or rebuilds; and\n(h)\nSafety during operations and maintenance of the Competitive \nTransmission Facilities.\nVIII.D.5.9.1. Local Balancing Authority:\nEach Proposal shall contain a description regarding the RFP Respondent’s \nplan for incorporating the Competitive Transmission Facilities into a Local \nBalancing Authority Area.\nVIII.D.5.9.2. Other Operations and Maintenance Capabilities Data:\nA RFP may require the submission of additional data related to the \npolicies, processes, methods, capabilities, experience, and past performance of the \nRFP Respondents regarding operations, maintenance, repair, and replacement \nwhen deemed necessary by the Transmission Provider.  \nProposals may also include additional information regarding operations, \nmaintenance, repair, and replacement capabilities when deemed necessary by RFP \nRespondents, including but not limited to, existing capabilities and past \nexperience regarding operations, maintenance, repair and replacement, which may"},{"page":716,"startToken":197219,"endToken":197479,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nbe considered by the Transmission Provider in the evaluation and selection of \nProposals.\nVIII.D.5.10.\nParticipation in the Transmission Planning Process:\nWhile not required, RFP Respondents and Proposal Participants who desire to \nhave such participation considered in the evaluation of their Proposal shall state whether \nany RFP Respondent or Proposal Participant, or Affiliate of either, was identified by the \nTransmission Provider eligible to receive planning participation credit for such \nCompetitive Transmission Project for which the Proposal is submitted.  Any Proposal \nstating that an Affiliate of a RFP Respondent or Proposal Participant earned the planning \nparticipation credit shall also identify and describe the relationship between the RFP \nRespondent or Proposal Participant to the Affiliate.\nVIII.D.5.11.\nDisclosure of Assignments or Potential Assignments:\nProposals shall include a declaration stating whether or not the RFP \nRespondent(s) will seek to assign the Competitive Transmission Facilities, Competitive \nTransmission Project, or Selected Developer Agreement pursuant to Article 14 of the pro \nforma Selected Developer Agreement.  For all proposed assignments except assignments \nto Project Finance Entities pursuant to Article 14.4 of the Selected Developer Agreement, \nsuch declaration shall include the identity of the proposed assignee(s) and the material \nterms, including timing, of such proposed assignment. If such assignment is conditioned \non the occurrence of future events, then a statement of the conditions under which the \nassignment would occur and their anticipated timing shall be included.  If an assignment"},{"page":717,"startToken":197479,"endToken":197791,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nis contemplated to an Affiliate that does not yet exist, then a description of the \nrelationship that the RFP Respondent and such future Affiliate will have at the time of \nassignment and any commitments that the RFP Respondent intends to make to support \nthe Affiliate shall constitute a sufficient identification of the intended assignee.  \nVIII.D.5.12.\nProposal Attestation:\nEach RFP Respondent shall include an affidavit as part of the Proposal \nsubmission, signed by an officer of its organization, attesting that: (i) it understands that \nthe Transmission Provider’s evaluation of Proposals and designation of a Selected \nProposal is governed by the Tariff and the Business Practices Manuals; (ii) it agrees to be \nbound by the Tariff and to follow the applicable Business Practices Manuals; (iii) it has \nsubmitted the Proposal in good faith; (iv) the information submitted by the organization \nin the Proposal is true to the best of the RFP Respondent’s knowledge and belief; (v) it \nhas complied with all Applicable Laws, and Regulations and Good Utility Practice in \npreparing the Proposal; and (vi) if selected, the Respondent agrees to be bound by its \nProposal.  Furthermore, each Proposal Participant shall include an affidavit as part of the \nProposal signed by an officer of its organization attesting that: (i) the Aggregate ATRR \nfor the Competitive Transmission Project and any required financial information about \nthe Proposal Participant and its inputs into the Aggregate ATRR that has been submitted \nby the organization is true to the best of the Proposal Participant’s knowledge and belief; \n(ii) that Proposal Participant agrees to be bound by any applicable cost containment \nmeasure and (iii) either (a) that it agrees to execute the ISO Agreement and identify the \nCompetitive Transmission Facilities associated with the Competitive Transmission"},{"page":718,"startToken":197791,"endToken":198078,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nProject in Appendix H of the ISO Agreement prior to closing on its conveyed interest \nshould the Transmission Provider designate the Proposal as the Selected Proposal; or (b) \nprior to such closing it will demonstrate that it has already executed the ISO Agreement \nand it agrees to identify the Competitive Transmission Facilities associated with the \nCompetitive Transmission Project in Appendix H of the ISO Agreement.\nVIII.D.6.\nAdditional Data Requests:\nIf, during the evaluation of Proposals, the Transmission Provider determines that \nadditional information is required to evaluate the Proposals, the Transmission Provider \nwill request, in writing, the additional data from all RFP Respondents, along with the \ntimeframe that this data must be submitted.  If the additional data is not submitted within \nthe specified timeframe, the Proposal be deemed invalid and will not be evaluated or \nconsidered further by the Transmission Provider.  This timeframe shall not be less than \nten (10) Business Days from when the Transmission Provider issues the additional data \nrequest.  This data request will not extend the evaluation timeframe defined in Section \nVIII.E.2 of Attachment FF of the Tariff.\nVIII.D.7.\nProposal Clarifications and Corrections:\nThe Transmission Provider will have the right, but not the obligation, during the \nCompetitive Developer Selection Process described in Section VIII of Attachment FF of \nthe Tariff, to request a RFP Respondent(s) to provide clarifications, corrections, or \nfurther supporting information to its submitted Proposal(s), along with the timeframe that \na response must be submitted.  The RFP Respondent(s) shall be responsible for any \nclarifications, corrections, or further supporting information the Transmission Provider"},{"page":719,"startToken":198078,"endToken":198360,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nrequires that relates to the Proposal Participants.  In the event the RFP Respondent agrees \nto provide said clarification(s), corrections, or further supporting information, the RFP \nRespondent shall provide these within the time set forth by the Transmission Provider \nwhich shall be no less than ten (10) Business Days of the Transmission Provider’s \nrequest.  If the Transmission Provider accepts the RFP Respondent’s clarification(s), \ncorrections, or further supporting information. These shall immediately become a part of \nthe submitted Proposal; or upon the Transmission Provider’s request, the RFP \nRespondent shall immediately update its Proposal to reflect the accepted clarification(s), \ncorrections, or further supporting information.  In the event that the RFP Respondent \ndeclines to provide the requested clarification(s), corrections, or further supporting \ninformation, the Transmission Provider shall evaluate the Proposal as submitted.\nVIII.D.8.\nWithdrawing Submitted Proposals:\nPrior to the Proposal Submission Deadline, a RFP Respondent may withdraw a \nProposal that was submitted to the Transmission Provider by informing the Transmission \nProvider as soon as practical in writing.  Any deposits submitted to the Transmission \nProviders associated with the withdrawn Proposal will be returned in full and the \nwithdrawn Proposal will not be considered or evaluated by the Transmission Provider.\nA RFP Respondent may withdraw its submitted Proposal after the Proposal \nSubmission Deadline by informing the Transmission Provider in writing, as soon as \npractical, but no later than such time that the Transmission Provider publicly announces \nthe Selected Proposal for the RFP.  Upon receiving a withdrawal notification, the \nTransmission Provider will stop its evaluation and consideration of the Proposal.  A"},{"page":720,"startToken":198360,"endToken":198618,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nwithdrawn Proposal will not relieve the RFP Respondent from its obligations for the pro \nrata costs associated with the full evaluation period nor will the RFP Respondent be \nafforded any refund other than those funds remaining once the Competitive Developer \nSelection Process has been completed for the RFP.\nVIII.D.9.\nConfidential Treatment of Proposals:\nThe Transmission Provider will treat information and documents, or portions of \ndocuments, received from RFP Respondents and/or Proposal Participants, whether \nreceived as Part of a Proposal, a response to a request for clarification or additional \ninformation pursuant to Sections VIII.D.6 and VIII.D.7 of this Attachment FF, or \notherwise, as either Project confidential information pursuant to Section VIII.D.9.a, or \nnon-confidential information pursuant to Section VIII.D.9.b, as set forth below.\nVIII.D.9.a\nConfidential Information:\nExcept as provided in Section VIII.D.9.d, the Transmission Provider will not, \nwithout the prior written consent of the respective RFP Respondent and/or the Proposal \nParticipant, publicly disclose or share any of the following confidential information with \nany individual except for employees of the Transmission Provider or an independent \ncontractor of the Transmission Provider who require access to such information to \nperform their duties and have executed the Transmission Provider’s non-disclosure \nand/or CEII agreement:\n(i)\nAll detailed breakdowns of costs, including but not limited to, the itemized costs \nfor labor and materials;"},{"page":721,"startToken":198618,"endToken":198825,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\n(ii)\nAll details of an RFP Respondent and/or Proposal Participant’s financing \narrangements;\n(iii)\nAll detailed design, routing, siting, or specialty construction techniques; and\n(iv)\nAny other information or portions of documents that are clearly labeled and \nspecifically designated as ”CONFIDENTIAL,” except for: (1) the items specified \nin Section VIII.D.9.b  of this Attachment FF; and (2) information and/or items \nwhich the Transmission Provider is otherwise required, or explicitly authorized by \nanother provision of the Tariff, to make publicly available.\nVIII.D.9.b\nNon-Confidential Information:\nThe following categories of information shall not be considered confidential or \nmaintained as Confidential Information:\n(i)\nThe identity of RFP Respondents and Proposal Participants;\n(ii)\nThe high-level design for Competitive Transmission Facilities;\n(iii)\nThe total estimated cost of the Competitive Transmission Project;\n(iv)\nThe estimated forty (40) year Annual Transmission Revenue Requirement \n(“ATRR”);\n(v)\nInformation relating to any cost-containment measures, and rate-incentives;\n(vi)\nInformation regarding the proposed in-service dates of the Competitive \nTransmission Facilities;\n(vii)\nThe final evaluation score assigned to each Proposal, with the names of the RFP \nRespondents and Proposal Participants redacted or masked;"},{"page":722,"startToken":198825,"endToken":199079,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\n(viii)\nAll timetables and milestones agreed to between a Selected Developer(s) and the \nTransmission Provider in the Selected Developer Agreement;\n(ix)\nAll publicly available information; \n(x)\nAny information for which a RFP Respondent or Proposal Participant has \nprovided consent to release; and\n(xi)\nAny information the Transmission Provider is required to make publicly available \npursuant to Section VIII.D.9.d of this Attachment FF.\nVIII.D.9.c\nUse of Non-Confidential Information–Post-Evaluation Report:\nThe Transmission Provider may use the non-confidential information of RFP \nRespondents and Proposal Participants to prepare the public post-evaluation selection \nreport for a Competitive Transmission Project required by Section VIII.E.2 of this \nAttachment FF as is reasonably necessary to explain the basis for the Transmission \nProvider’s selection of a Selected Developer.  In all cases, the Confidential Information \nand non-confidential information that was not disclosed in the post-evaluation selection \nreport or the publicly posted version of the Selected Developer Agreement shall not \notherwise be disclosed by the Transmission Provider except as required by Section \nVIII.D.9.d of this Attachment FF. \ni.\nUse of Selected Developer Non-Confidential Information\nThe Transmission Provider may use the non-confidential information of the RFP \nRespondent(s) and Proposal Participants whose Proposal is selected to prepare: (1) \nappendices for a Selected Developer Agreement memorializing the commitments and \nsalient features of the Selected Proposal; and (2) a post-evaluation selection report that"},{"page":723,"startToken":199079,"endToken":199385,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nexplains the basis for the Transmission Provider’s selection of the Selected Proposal \npursuant to the comparative analysis required by Sections VIII.E, VIII.E.1, VIII.E.1.1, \nVIII.E.1.2, VIII.E.1.3, and VIII.E.1.4 of this Attachment FF to the Tariff.  The \nTransmission Provider may use such information to the extent reasonably necessary to \nexplain why the selection of the Selected Proposal is proper based on the comparative \nanalysis required by the Tariff, including discussions of features of the Selected Proposal \nthat the Transmission Provider determined to be important in selecting the Selected \nProposal. \nii.\nUse of Non-Confidential Information of RFP Respondents \nand Proposal Participants whose Proposals are Not Selected \nThe Transmission Provider may disclose the non-confidential information of RFP \nRespondents and Proposal Participants whose Proposals were not selected as the Selected \nProposal only to the extent reasonably necessary to explain why the selection of the \nSelected Proposal is proper based on the comparative analysis required by Sections \nVIII.E, VIII.E.1, VIII.E.1.1, VIII.E.1.2, VIII.E.1.3, and VIII.E.1.4 of this Attachment FF \nto the Tariff.  The Transmission Provider may disclose the non-confidential information \ncontained in Section VIII.D.9.b(i) and VIII.D.9.b(ix)-(xi) without masking the \nidentity(ies) of the entity(ies) to whom such non-confidential information pertains.  The \nTransmission Provider may disclose the non-confidential information contained in \nSection VIII.D.9.b(ii)-(viii) for RFP Respondents and Proposal Participants whose \nProposals were not selected as the Selected Proposal but must mask the identities of such \nparties, either through aggregation or the redacting of names, as appropriate for"},{"page":724,"startToken":199385,"endToken":199666,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ncomparative purposes. \nVIII.D.9.d\nOther Disclosures of Proposal Information:\nThe Transmission Provider will disclose any information submitted in Proposals \nor in response to a request for clarifications and or additional information, whether \nconfidential or non-confidential, that it is otherwise required by or subject to another \nTariff provision, Commission rule or order, or court order, as ordered by state or federal \nagencies, as reasonably deemed by the Transmission Provider is required to be disclosed \nin connection with a dispute between the Transmission Provider and the entity or entities \nto which such confidential information pertains, or the defense of litigation or a dispute. \nIn addition, the Transmission Provider may disclose confidential information contained \nin the Selected Proposal in filings before the Federal Energy Regulatory Commission to \nthe extent necessary to explain or enforce commitments made in a Selected Developer \nAgreement provided that the Transmission Provider, consistent 18 C.F.R. Section \n388.112, requests that that the information be treated as confidential and non-public by \nthe Commission and its staff and that the information be withheld from public disclosure.\nThe Transmission Provider may disclose confidential or non-confidential \ninformation submitted in Proposals or in response to a request for clarifications and/or \nadditional information to Federal Energy Regulatory Commission staff to the extent \nnecessary to discuss the Transmission Provider’s implementation of the Competitive \nDeveloper Selection Process without first obtaining an order provided that the \nTransmission Provider: (1) clearly communicates the confidential nature of the \ninformation shared; and (2) consistent with 18 C.F.R. Section 388.112, requests that the"},{"page":725,"startToken":199666,"endToken":199987,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ninformation be treated as confidential and non-public by the Commission and its staff and \nthat the information be withheld from public disclosure.\nVIII.D.10.\nProposal Validation – Review for Completeness:\nThe Transmission Provider will review each submitted Proposal for completeness and \nvalidate whether the RFP Respondent(s) is/are listed as a Qualified Transmission Developer.  \nWithin thirty (30) Calendar Days of the Proposal Submission Deadline, the Transmission \nProvider will notify each RFP Respondent if the Transmission Provider identifies that their \nProposal is incomplete.  Except when any of the RFP Respondents involved in a Proposal were \nnot listed as a Qualified Transmission Developer on the date the Proposal was submitted, the \nRFP Respondent(s) will have a single Proposal Cure Period set for by the Transmission Provider \nof not less than ten (10) Business Days from the date of such notification to submit the requested \ninformation to cure any deficiencies in their Proposal.  Proposals that are not complete at the end \nof the Proposal Cure Period will be deemed invalid and will not be evaluated or considered \nfurther by the Transmission Provider.  Such Proposals will be refunded ninety percent (90%) of \nthe initial proposal deposit specified in Section V.III.D.2 of Attachment FF of the Tariff, if such \ninitial proposal deposit was submitted to the Transmission Provider.  Proposals that include a \nRFP Respondent that was not listed as a Qualified Transmission Developer on the date the \nProposal was submitted will also be deemed invalid and will not be evaluated or considered \nfurther by the Transmission Provider.   The Transmission Provider will provide a written \nexplanation to RFP Respondents identifying why the Proposal has been disqualified.\nVIII.D.11.\nPosting List of RFP Respondents and Proposals Participants:\nThe Transmission Provider will post a list of the RFP Respondents and Proposal"},{"page":726,"startToken":199987,"endToken":200306,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nParticipants that submitted completed Proposals in response to an issued RFP on its website after \nthe end of the Proposal Cure Period.  \nVIII.D.12.\nRFP Respondent’s Qualified Transmission Developer status:\nRFP Respondents are required to maintain their status as a Qualified Transmission \nDeveloper throughout the duration of the Competitive Developer Selection Process.   In the \nevent that the Transmission Provider determines that a RFP Respondent has ceased to be a \nQualified Transmission Developer, the Transmission Provider shall send a written notice of such \nfact to the RFP Respondent, which notice shall state the reason(s) for loss of Qualified \nTransmission Developer status.  The RFP Respondent shall have thirty (30) Calendar Days from \nthe Transmission Provider’s notification of loss of Qualified Transmission Developer status to \nremove the grounds for such loss of status.  Any Proposal involving a RFP Respondent that \nceases to be a Qualified Transmission Developer will be deemed invalid and will not be \nevaluated or considered further by the Transmission Provider if such failure remains uncured \nmore than thirty (30) Calendar Days from the date of the notice to the RFP Respondent.  A \nProposal shall not be deemed invalid if the RFP Respondent cures the loss of Qualified \nTransmission Developer status within the thirty (30) Calendar Day period.  If one or more RFP \nRespondents who have submitted a Joint-Developer Proposal pursuant to Section VIII.D.4.2 is \ndisqualified after the cure period, the Joint-Developer Proposal shall be disqualified unless all of \nthe RFP Respondents have acknowledged and agreed to be jointly and severally liable for all \naspects of the submitted Joint-Developer Proposal. If all RFP Respondents submitting a Joint \nDeveloper Proposal have acknowledged and agreed to be jointly and severally liable for all \naspects of the submitted Joint-Developer Proposal, then the remaining RFP Respondents shall"},{"page":727,"startToken":200306,"endToken":200596,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nassume the obligations of the RFP Respondent that has failed to cure a loss of Qualified \nTransmission Developer status and the Joint-Developer Proposal shall not be disqualified. The \nTransmission Provider will provide a written explanation to RFP Respondents identifying why \nthe Proposal has been disqualified or, in the event that all RFP Respondents involved in a Joint-\nDeveloper Proposal have acknowledged and agreed to be jointly and severally liable for all \naspects of the submitted Joint-Developer Proposal, stating that the remaining RFP Respondents \nmust assume the obligations of the RFP Respondent that has lost its Qualified Transmission \nDeveloper status.\nVIII.E.\nEVALUATION OF PROPOSALS\nThe Transmission Provider will have one hundred and sixty-five (165) Calendar Days \nfrom the Proposal Submission Deadline to evaluate all completed Proposals.  Only those \nProposals that were submitted prior to the Proposal Submission Deadline and cured of any \ndeficiencies pursuant to Section VIII.D.10 of Attachment FF of the Tariff and otherwise have not \nbeen withdrawn or deemed invalid will be evaluated by the Transmission Provider based on a \ncomparative analysis using the evaluation criteria below and as further described in the Business \nPractices Manuals and applicable RFP.  Specific methods used to evaluate various aspects of a \nProposal shall be described in the Business Practices Manuals.  This comparative analysis \nevaluation will be conducted by Transmission Provider and/or independent consultants \ncompetent in the areas of finance, transmission facility design, transmission project \nimplementation, and transmission operations, maintenance, repair, and replacement.  In \nconducting the comparative analysis evaluation of Proposals, the Transmission Provider and any \nindependent expert consultants will be overseen by the Competitive Transmission Executive"},{"page":728,"startToken":200596,"endToken":200838,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nCommittee, which will have the exclusive and final authority to determine Selected Proposal.  \nThe Transmission Provider may decline to accept any or all Proposals that do not meet the \nTariff’s requirements for the project classification in question or will not sufficiently address the \nTransmission Issue(s) the RFP was intended to address.  If no Proposals are received from \nQualified Transmission Developers or selected by the Transmission Provider, the Competitive \nTransmission Project may be cancelled or assigned to the applicable Member(s), as defined \nbelow:\n(a)\nOwnership and the responsibility to construct facilities which are connected to a \nsingle Member’s system belong to that Member; \n(b)\nOwnership and the responsibilities to construct facilities which are connected \nbetween two (2) or more Members’ facilities belong equally to each Member, \nunless such Members otherwise agree; and\n(c)\nOwnership and the responsibility to construct facilities which are connected \nbetween a Member(s)’ system and a system or systems that are not part of the \nTransmission Provider belong to such Members(s) unless the Member(s) and the \nnon-Transmission Provider party or parties otherwise agree.\nVIII.E.1.\nProposal Evaluation Criteria:  \nIn evaluating Proposals, the Transmission Provider will consider the following \ngeneral aspects and weighting for each Competitive Transmission Project evaluated:  \n(a)\nCompetitive Transmission Line Projects:\nThe following weights will be applied to Competitive Transmission"},{"page":729,"startToken":200838,"endToken":200984,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nProjects containing only Competitive Transmission Line Facilities:\n(i)\nCost and reasonably descriptive facility design quality:  30%\n(ii)\nProject implementation capabilities:  35%\n(iii)\nOperations, maintenance, repair, and replacement capabilities:  \n30%\n(iv)\nTransmission Provider planning process participations:  5%\n(b)\nCompetitive Substation Projects:\nThe following weights will be applied to Competitive Transmission \nProjects containing only Competitive Substation Facilities:\n(i)\nCost and reasonably descriptive facility design quality:  30%\n(ii)\nProject implementation capabilities:  30%\n(iii)\nOperations, maintenance, repair, and replacement capabilities:  \n35%\n(iv)\nTransmission Provider planning process participations:  5%\n(c)\nMixed Competitive Transmission Facility Projects:\nThe following weights will be applied to Competitive Transmission \nProjects containing both Competitive Transmission Line Facilities and \nCompetitive Substation Facilities:\n(i)\nCost and reasonably descriptive facility design quality:  35%\n(ii)\nProject implementation capabilities:  30%"},{"page":730,"startToken":200984,"endToken":201151,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\n(iii)\nOperations, maintenance, repair, and replacement capabilities:  \n30%\n(iv)\nTransmission Provider planning process participations:  5%\nVIII.E.1.1.\nCost and Reasonably Descriptive Facility Design:\nWhen considering cost and reasonably descriptive facility design quality, \nthe Transmission Provider shall evaluate, at a minimum and to the extent \napplicable, the following: \n(a)\nEstimated project cost; \n(i)\nEstimated project cost(s), as set forth in Section VIII.D.5.3 \nof this Attachment FF; and \n(ii)\nCost estimate rigor, which shall include financial \nassumptions and supporting information to clearly \ndemonstrate a thorough analysis in support of the cost \nestimate.   \n(b)\nEstimated annual transmission revenue requirement:\n(i)\nThe estimated annual transmission revenue requirement(s), \nas described in Section VIII.D.5.4 of this Attachment FF; \nand\n(ii)\nEstimated annual transmission revenue requirement rigor, \nwhich shall include financial assumptions and supporting \ninformation to clearly demonstrate a thorough analysis in"},{"page":731,"startToken":201151,"endToken":201334,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nsupport of the estimated annual transmission revenue \nrequirement.\n(c) \nCost Containment\n(i) \nBinding cost containment measures as described in Section \nVIII.D.5.5 of this Attachment FF if a Proposal contains any \nsuch measures relating to the estimated project cost; and\n(ii)\nBinding cost containment measures as described in Section \nVIII.D.5.5 of this Attachment FF if a Proposal contains any \nsuch measures relating to the estimated annual transmission \nrevenue requirement(s).\n(d)\nElectrical design:\n(i)\nReasonably descriptive facility electrical design quality; \nand \n(ii)\nReasonably descriptive facility electrical design rigor, \nwhich shall include facility studies performed and other \nspecific supporting data that clearly documents and \nsupports consideration and attention given to the proposed \nreasonably descriptive facility electrical designs.  For \nreasonably descriptive facility electrical design, the \nTransmission Provider shall consider the items set forth in \nSections VIII.D.5.7.1 through VII.D.5.7.3 of this \nAttachment FF, as each is applicable to the electrical design"},{"page":732,"startToken":201334,"endToken":201512,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nof Competitive Transmission Facilities discussed in the \nProposal.\n(e)\nStructural design:\n(i)\nReasonably descriptive facility structural design quality; \nand\n(ii)\nReasonably descriptive facility structural design rigor, \nwhich shall include facility studies performed and other \nspecific supporting data that clearly documents and \nsupports consideration and attention given to the proposed \nreasonably descriptive facility structural designs.  For \nreasonably descriptive facility structural design, the \nTransmission Provider shall consider the items set forth in \nSections VIII.D.5.7.1 through VII.D.5.7.3 of this \nAttachment FF, as each is applicable to the structural \ndesign of Competitive Transmission Facilities discussed in \nthe Proposal.\nVIII.E.1.2.\nProject Implementation Capabilities:  \nWhen considering project implementation capabilities, the Transmission \nProvider shall evaluate, at a minimum and to the extent applicable, the existing \nand/or planned capabilities, competencies, previous applicable experience and \ndemonstrated ability, and processes regarding the following project \nimplementation categories relative to the locations and jurisdictions where the"},{"page":733,"startToken":201512,"endToken":201668,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nCompetitive Transmission Facilities associated with the Competitive \nTransmission Project are to be located, including: \n(a)\nProject schedule and management:\n(i)\nProject implementation schedule, as required by Section \nVIII.D.5.2 of this Attachment FF; and\n(ii)\nProject management. \n(b)\nRegulatory permitting, and route/site evaluation:\n(i)\nRegulatory permitting; \n(ii)\nRoute and site evaluation; and\n(iii)\nRight of way and land acquisition. \n(c)\nConstruction;\n(i)\nEngineering and surveying; \n(ii)\nMaterial procurement; \n(iii)\nFacility construction; and\n(iv)\nFinal facility commissioning. \n(d)\nFinancing and capital resource plan;\n(i)\nThe information and documentation from the detailed \nfinancing plan required by Sections VIII.D.5.6(1)-(7) of this \nAttachment FF; and\n(e)\nSafety, as described in Section VIII.D.5.9(h) of this Attachment \nFF.\nVIII.E.1.3.\nOperations, Maintenance, Repair, and Replacement \nCapabilities:"},{"page":734,"startToken":201668,"endToken":201848,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nWhen considering operations, maintenance, repair and replacement \ncapabilities, the Transmission Provider shall evaluate, at a minimum and to the \nextent applicable, the existing and/or planned capabilities, competencies, and \nprocesses regarding the following operations and maintenance categories relative \nto the locations and jurisdictions where the Competitive Transmission Facilities \nassociated with the Competitive Transmission Project are to be located:\n(a)\nNormal operations:\n(i)\nReal-time operations monitoring and control;   \n(ii)\nSwitching; and \n(iii)\nPlan for incorporating the Competitive Transmission \nFacilities into a Local Balancing Authority Area as required \nby Section VIII.D.5.9.1 of this Attachment FF.\n(b)\nNon-normal operations:\n(i)\nForced outage response;\n(ii)\nEmergency repair; and\n(iii)\nCapabilities to perform major facility replacements or \nrebuilds required to restore the Competitive Transmission \nFacilities as a result of catastrophic destruction, as required \nby Section VIII.D.5.9(g) of this Attachment FF.\n(c)\nMaintenance activities: \n(i) \nSpare parts; \n(ii) \nPreventative and/or predictive maintenance and testing; and"},{"page":735,"startToken":201848,"endToken":202072,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\n(iii) \nCapabilities to perform major facility replacements or \nrebuilds required as a result of natural aging through \nnormal wear and tear, as required by Section VIII.D.5.9(g) \nof this Attachment FF.\n(d) \nFinancial capabilities and strategy \n(i)\nFinancial capabilities and strategy to facilitate major \nfacility replacements or rebuilds required to restore the \nCompetitive Transmission Facilities as a result of \ncatastrophic destruction, as required by Section \nVIII.D.5.6(8) of this Attachment FF; and\n(ii) \nFinancial capabilities and strategy to facilitate major \nfacility replacements or rebuilds required as a result of \nnormal wear and tear, as required by Section VIII.D.5.6(8) \nof this Attachment FF.\n(e) Safety, as described in Sections VIII.D.5.9(h) of this Attachment.\nVIII.E.1.4.\nTransmission Provider Planning Process Participation:  \nWithin thirty (30) Calendar Days after the date, the Transmission Provider \nBoard approves an MTEP containing a Competitive Transmission Project, MISO \nwill publicly post a list on its website identifying the entities that have meet the \nrequirements to earn planning participation for such Competitive Transmission \nProject.   Such determination shall be based on relevant planning studies \nperformed by such entities and the results supplied to the Transmission Provider"},{"page":736,"startToken":202072,"endToken":202364,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nduring the planning process, as well as documentation of transmission project \nideas submitted by such entities to the Transmission Provider to address the same \nTransmission Issues being addressed by the Competitive Transmission Project for \nwhich an RFP will be issued.  In evaluating Proposals, the Transmission Provider \nshall determine whether any RFP Respondent or Proposal Participant (including \nAffiliates) qualified to receive such credit.  Credit shall be awarded for a Proposal \nwhere any RFP Respondent or Proposal Participant named in such Proposal, or an \naffiliate of either, qualifies to receive such credit.  \nVIII.E.2.\nProposal Selection and Posting Selection Report:\nThe Transmission Provider will post the name of the Selected Developer(s) on its \nwebsite within one hundred and sixty-five (165) Calendar Days of the Proposal \nSubmission Deadline.  Upon posting of the name of the Selected Developer(s), the \nobligation of RFP Respondents not named as the Selected Developer or notified that they \nhave been designated as the Alternate Selected Developer(s) pursuant to Section VIII.H \nof this Attachment FF to hold their Proposals open shall cease.  Within thirty (30) \nCalendar Days after the designation of a Selected Proposal and the Selected  \nDeveloper(s) for a Competitive Transmission Project, the Transmission Provider will \npost on its website a report in which it explains the basis for designating the Selected \nProposal and Selected Developer(s) for each Competitive Transmission Project.  The \nreport will set forth the results of the comparative analysis undertaken by the \nTransmission Provider, the basis for Transmission Provider’s decision(s), and the date(s) \nby which state approval(s) to construct must be achieved based upon when construction"},{"page":737,"startToken":202364,"endToken":202649,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nmust begin to timely meet the Transmission Issue(s) to be addressed by the Competitive \nTransmission Project and taking into account the project implementation schedule(s) \nprovided by the Selected Developer(s) in its Selected Proposal.  \nVIII.E.3.\nProposal Selection Dispute Resolution:\nAny disputes regarding the developer selection will be referred to the Dispute \nResolution Process under Attachment HH of this Tariff.\nVIII.F.\nSELECTED DEVELOPER AGREEMENT\nRFP Respondents identified in a Selected Proposal shall execute the pro forma Selected \nDeveloper Agreement, or request the submission of an unexecuted Selected Developer \nAgreement with the Commission, no later than sixty (60) Calendar Days after the Transmission \nProvider posted the name of the Selected Developer(s) on its website.  Any Proposal \nParticipant(s) identified in the Selected Proposal shall execute the Proposal Participant \nacknowledgement of the pro forma Selected Developer Agreement by the same sixty (60) \nCalendar Day deadline.  The Selected Developer Agreement establishes the terms and conditions \nunder which the Selected Developer will construct and implement the Competitive Transmission \nFacilities specified in its Selected Proposal.  The Selected Developer Agreement shall be \nexecuted by the Selected Developer and the Transmission Provider, by an authorized officer or \nequivalent official with the authority to bind their respective organizations.  The Selected \nDeveloper(s) for each Competitive Transmission Project, including where the Selected \nDeveloper is a Member, will be required to sign the Selected Developer Agreement or request it \nbe submitted unexecuted with the Commission.  All executed Selected Developer Agreements \nthat conform to the pro forma template in Appendix 1 of Attachment FF of the Tariff, will be"},{"page":738,"startToken":202649,"endToken":202943,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nreported to the Commission in the Transmission Provider’s next Electric Quarterly Report after \nthe executed Selected Developer Agreement becomes effective on a non-provisional basis.  Any \nrequest to file the Selected Developer Agreement unexecuted shall be filed with the Commission, \ntogether with an explanation of any matters as to which the Selected Developer and the \nTransmission Provider disagree, as soon as practicable, but no later than fifteen (15) Calendar \nDays after receiving the request to file the Selected Developer Agreement unexecuted.  An \nunexecuted Selected Developer Agreement should contain terms and conditions deemed \nappropriate by the Transmission Provider for the Competitive Transmission Project.  If the \nSelected Developer and the Transmission Provider agree to proceed with design, procurement, \nand construction of the Competitive Transmission Project under the agreed-upon terms of the \nunexecuted Selected Developer Agreement, they may proceed pending Commission action.\nIf the Selected Developer Agreement contains information determined to be confidential \npursuant to Section VIII.D.9 of Attachment FF of the Tariff, the Transmission Provider will post \nand/or file publicly only a redacted version of the Selected Developer Agreement.\nVIII.G.\nOBLIGATION TO CONSTRUCT COMPETITIVE TRANSMISSION \nPROJECT\nThe Selected Developer(s) will assume the responsibility and obligation to construct the \nCompetitive Transmission Facilities it is selected to construct.  If the Selected Developer(s) is/are \nfinancially incapable of carrying out its construction responsibilities, alternate construction \narrangements shall be identified.  Depending on the specific circumstances, such alternate \narrangements shall include solicitation of Transmission Owners to take on financial and/or \nconstruction responsibilities.  If the delay in construction adversely affects the Transmission \nSystem reliability, the Transmission Provider shall coordinate with and support the affected"},{"page":739,"startToken":202943,"endToken":203233,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nTransmission Owner(s) regarding any mitigation measures that may be required by the \nApplicable Reliability Standards.  \nHowever, in the event that a MTEP Appendix A Competitive Transmission Project \napproved by the Transmission Provider Board is being challenged through the Dispute \nResolution process under Attachment HH of the Tariff or a court proceeding, the obligation of \nthe Selected Developer(s) to build the specific Competitive Transmission Project (subject to \nrequired approvals) is waived until the Competitive Transmission Project emerges from the \nDispute Resolution process or court proceedings as an approved Competitive Transmission \nProject.  In the event that selection of the Selected Developer to construct a project is being \nchallenged through the Dispute Resolution Process under Attachment HH of the Tariff, the \nobligation of the Selected Developer to construct the project pursuant to the Selected Developer \nAgreement is not waived.  \nVIII.H. \nALTERNATE SELECTED DEVELOPER(S)\nAt the same time that the Transmission Provider posts the name of the Selected \nDeveloper(s) on its website, as specified in Attachment FF Section VIII.E.2, the Transmission \nProvider shall also notify the Alternate Selected Developer(s) that it has been selected as the \nAlternate Selected Developer(s). Upon this notification, each Alternate Selected Developer shall \nbe required to hold their Proposal open for acceptance by the Transmission Provider for a period \nof one hundred (100) Calendar Days thereafter, unless released earlier by the Transmission \nProvider. The Transmission Provider shall release the Alternate Selected Developer(s) from its \nobligation to hold its Proposal open promptly upon the Selected Developer(s) satisfying all \nconditions necessary for the Selected Developer Agreement to become effective."},{"page":740,"startToken":203233,"endToken":203505,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nIf a Selected Developer does not execute the Selected Developer Agreement or request\nthat the Selected Developer Agreement be filed unexecuted, and provide the required Project\nFinancial Security within ninety (90) Calendar Days after the Transmission Provider posted the\nname of the Selected Developer(s) on its website, the Transmission Provider shall proceed to\ndesignate the Alternate Selected Developer(s) as the Selected Developer(s) for the Competitive \nTransmission Project.  Should this be required, the Transmission Provider shall notify the\nAlternate Selected Developer(s) and publicly announce the Alternate Selected Developer(s) as \nthe Selected Developer(s).  The Alternate Selected Developer(s) shall then be required to assume\nthe obligations of the Selected Developer for the Competitive Transmission Project and shall\nhave the same period of time to execute or request the unexecuted filing of the Selected \nDeveloper Agreement and provide the required Project Financial Security as the originally \ndesignated Selected Developer(s).\nVIII.I OBLIGATION TO NEGOTIATE INTERCONNECTION AGREEMENTS\nThe Selected Developer(s) and any Transmission Owner(s) whose facilities will \ninterconnect to the Competitive Transmission Facilities that the Selected Developer is obligated to \nconstruct shall each take commercially reasonable efforts to finalize and execute any required \nTransmission-to-Transmission Interconnection Agreements at least one hundred and twenty \n(120) calendar days before the scheduled in service date of the Competitive Transmission \nProject. \nIX.\nVARIANCE ANALYSIS  \nAfter the Transmission Provider Board approves an Eligible Project for inclusion in\nAppendix A of the MTEP, certain circumstances or events may significantly affect the cost,"},{"page":741,"startToken":203505,"endToken":203813,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nschedule, and or the ability of Selected Developers and Transmission Owners to complete and\nplace into service the facilities comprising an Eligible Project for which they are responsible as \nspecified in the MTEP. Under these circumstances or events, the Transmission Provider may\nneed to perform a Variance Analysis in order to further understand the reasons for such \ncircumstances or events and to evaluate any potential impacts that they may have on the \nsuccessful completion of the Project or on the Transmission System.\nIX.A. Applicability and Scope of Variance Analysis\nThe provisions set forth in this Section IX of Attachment FF are only applicable to \nEligible Projects (and the facilities that comprise these projects) approved by the Transmission \nProvider Board for inclusion in Appendix A of the MTEP after December 1, 2015. These\nprovisions become applicable upon: (i) the date the Transmission Provider Board approves the\nrespective Eligible Project for facilities that are not Competitive Transmission Facilities; or (ii)\nthe date the Selected Developer Agreement has been executed or filed unexecuted with the \nCommission for Competitive Transmission Facilities. Facilities comprising Eligible Projects\nshall remain subject to the provisions of Attachment FF Section IX until such facilities have been\nplaced into service and placed under the Transmission Provider’s functional control. \nIX.B. Variance Analysis Governance\nThe Competitive Transmission Executive Committee shall have the exclusive and final \nauthority to oversee and implement Variance Analysis, including the decision to implement any \nof the appropriate Variance Analysis Outcomes pursuant to Section IX.E of this Attachment FF. \nSuch exclusive and final authority shall: (1) be subject to the Dispute Resolution provisions of \nSection IX.G of this Attachment FF and to Attachment HH; and (2) shall not prejudice any rights"},{"page":742,"startToken":203813,"endToken":204054,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nor obligations the Transmission Provider, Selected Developer(s), and incumbent Transmission\nOwner(s) have to make filings before the Commission.\nIX.C.  Grounds for Variance Analysis\nThe following circumstances or events shall trigger the Transmission Provider’s Variance \nAnalysis for facilities included in an Eligible Project.  \nIX.C.1.\nCost Increase\nIf the Transmission Provider determines that the estimated cost to \ncomplete an entity’s portion of an approved Eligible Project (e.g. the \ncompetitively bid facilities of the Competitive Transmission Project or the \nfacilities assigned to an incumbent Transmission Owner included in an Eligible \nProject(s) either has exceeded or is projected to exceed the Baseline Cost Estimate \nas set forth in Section IX.C.1.1 by twenty-five percent (25%)) or more, the \nTransmission Provider shall initiate a Variance Analysis.\nThe Transmission Provider will not consider any portion of cost increases \nunder this section to the extent that the Selected Developer has agreed to \ninternalize such costs through an accepted binding  containment mechanism(s). \nHowever in the event that the accepted binding cost-containment mechanism(s) \nare applied and the remaining estimated cost increase still has exceeded or is \nprojected to exceed the threshold, the Transmission Provider shall initiate a \nVariance Analysis.\nIX.C.1.1.\nBaseline Cost Estimate\nThe Baseline Cost Estimate for an entity’s portion of an Eligible"},{"page":743,"startToken":204054,"endToken":204294,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nProject shall be set as follows: (i) for Competitive Transmission Facilities \nthe Baseline Cost Estimate shall be the project cost estimate provided in \nthe Selected Proposal as agreed to in the Selected Developer Agreement; \nand (ii) for the facilities assigned to an incumbent Transmission Owner \nincluded in the Eligible Project not eligible for the Competitive \nTransmission Process, as described in Attachment FF Section VIII.A of \nthe Tariff, the Baseline Cost Estimate shall be the project cost estimate \nprovided by the respective Transmission Owner through their status \nupdate provided upon achieving Milestone #2 pursuant to the Business \nPractices Manuals.  The Baseline Cost Estimate for facilities included in \nan Eligible Project shall be adjusted appropriately based upon any \napproved change orders or as necessary based on the outcome of any \nVariance Analysis conducted for such facilities.\nIn the event that an entity’s portion of an Eligible Project is \nreassigned pursuant to Section IX.E.3 of this Attachment FF, the \nTransmission Provider shall adjust the Baseline Cost Estimate to reflect \nthe cost estimates and supporting information submitted to the \nTransmission Provider by the applicable Transmission Owner during \nVariance Analysis.  The Transmission Provider shall include such \ninformation in any filing made to the Commission pursuant to Section \nIX.D.4.E of this Attachment FF.  \nIX.C.2.\nSchedule Delays"},{"page":744,"startToken":204294,"endToken":204552,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nIf the Transmission Provider determines that the in-service date of \nfacilities included in an approved Eligible Project has been or is projected to be \ndelayed beyond the in-service date as established in MTEP Appendix A, the \nTransmission Provider shall meet with the Selected Developer(s), incumbent\nTransmission Owner(s), if applicable, interconnecting Transmission Owner(s), \nand any entities responsible for facilities to which the delayed facilities \ninterconnect to discuss whether such delay creates a significant risk of one or \nmore NERC reliability standards violations as well as any other material issues, \nincluding service obligations, economic or public policy needs that may be \njeopardized as a result of the delay. If any such issues are identified, the \nTransmission Provider shall, in consultation with these entities, develop a plan, as \nnecessary, to address potential NERC reliability standards violations as well as \nany other issues that may be of material concern arising from the delay of the \ntransmission facilities.   \nIf the potential NERC reliability standards violations, or other issues of \nmaterial concern, cannot be adequately addressed by the entity responsible for \nconstructing the delayed facilities, the Transmission Provider will take \nappropriate action; including but not limited to, determining that Reassignment is \nnecessary to complete the transmission solution as set forth in Section IX.E.3 of \nthis Attachment FF.\nIX.C.3. \nDefault under the Selected Developer Agreement\nIf the Transmission Provider determines that a Selected Developer is in"},{"page":745,"startToken":204552,"endToken":204779,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nDefault under a Selected Developer Agreement for an Eligible Project pursuant to \nthe terms thereof.  \nIX.C.4 \nInability to Complete Facilities\nIf the Transmission Provider makes a determination that a Selected \nDeveloper or an incumbent Transmission Owner will be unable to complete \nfacilities for which it has been designated to construct; where such determination \nmay be based on, but is not limited to the following:\na.\nA Selected Developer’s or an incumbent Transmission Owner’s inability \nto secure necessary approvals, permits, certificates, financing, resources, \nneeded expertise and/or third party support identified in the Selected \nProposal, property rights, rights of way, or is otherwise unable or unlikely \nto construct the facilities;\nb.\nA Selected Developer’s or an incumbent Transmission Owner’s \nnotification to the Transmission Provider that it is unable or unwilling to \nproceed with construction of its facilities for which it has been designated \nto construct;\nc.\nA Selected Developer or an incumbent Transmission Owner’s \nabandonment of the facilities it has been designated to construct;\nd.\nA determination by the Transmission Provider that a Selected Developer is \nno longer a Qualified Transmission Developer; and\ne.\nA determination by the Transmission Provider that reassignment is \nnecessary pursuant to Section IX.E.3 of this Attachment FF."},{"page":746,"startToken":204779,"endToken":205032,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nIn selecting the appropriate Variance Analysis Outcome to apply where \nthe Transmission Provider has determined that a Selected Developer or an \nincumbent Transmission Owner will be unable to complete the facilities for which \nit has been designated to construct, the Transmission Provider will consider, but is \nnot limited to considering the following, in addition to the general factors set forth \nin Section IX.D.2.1:\n(i)\nThe reasons that the Selected Developer or the Transmission Owner was \nunable or was unlikely to construct the facilities;\n(ii)\nWhether the facilities are still needed;\n(iii)\nWhether a Mitigation Plan, as further described in Section IX.E.2 of this \nAttachment FF, is available that could remedy the ground(s) for Variance \nAnalysis, including consideration of the extent to which it will cost; and\n(iv)\nWhether reassignment, as further described in Section IX.E.3 of this \nAttachment FF, is available, including the impacts of reassigning the \nfacilities to another entity.\nIX.C.5 \nUndisclosed Assignments \nIf the Transmission Provider determines that the Selected Developer has \nassigned the Competitive Transmission Facilities, Competitive Transmission \nProject, or Selected Developer Agreement to an entity not disclosed in its \nProposal as required by Section VIII.D.5.12 or on terms materially different than \nthose disclosed in the Proposal, except for assignments to a Project Finance Entity \npursuant to Article 14.4 of the Selected Developer Agreement."},{"page":747,"startToken":205032,"endToken":205295,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nIX.D.\nVariance Analysis Procedure\nVariance Analysis shall commence when the Transmission Provider makes an \ninitial determination that one or more of the grounds for Variance Analysis as described \nin Section IX.C of this Attachment FF exists.  The Transmission Provider will adhere to \nthe following steps, as further detailed in the applicable Business Practices Manuals, in \nperforming a Variance Analysis:\nIX.D.1.\nInitial Inquiry and Confirmation of Grounds for Variance \nAnalysis\nUpon making an initial determination that one or more of the grounds for \nVariance Analysis as described in Section IX.C of this Attachment FF exists, the \nTransmission Provider shall notify the applicable Selected Developer or \nTransmission Owner in writing that Variance Analysis has commenced, including \nthe ground(s) for commencing Variance Analysis, and a brief description of the \nTransmission Provider’s concerns.  The applicable Selected Developer or \nincumbent Transmission Owner shall be provided an opportunity to be heard by \nthe Transmission Provider and present to the Transmission Provider its position \non whether the identified ground(s) for Variance Analysis exist and what outcome \nit believes is appropriate along with supporting facts and documentation.  If the \nTransmission Provider determines that the ground(s) for Variance Analysis do not \nexist after considering the Selected Developer or Transmission Owner’s response \nand any other relevant information, the Transmission Provider shall terminate the \nVariance Analysis.  If the Transmission Provider continues to believe that \nreasonable grounds for Variance Analysis exist after considering the Selected"},{"page":748,"startToken":205295,"endToken":205548,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nDeveloper or Transmission Owner’s response and any other relevant information, \nthe Transmission Provider shall continue to commence Variance Analysis and so \nnotify the Selected Developer or Transmissions Owner.\nIX.D.2.\nDetermination of Variance Analysis Outcome\nIf the Transmission Provider continues to believe that reasonable \nground(s) for Variance Analysis exists pursuant to the process described in \nSection IX.D.1 of this Attachment FF, the Transmission Provider shall further \ninvestigate the circumstances or events and the relevant facts surrounding the \nfacilities identified in Section IX.D.1 above.  Upon completing its investigation, \nthe Transmission Provider shall make a determination of which Variance Analysis \nOutcome to apply, as described in Section IX.E of this Attachment FF.  In \ndetermining which Variance Analysis Outcome to apply, the Transmission \nProvider shall consider the general factors set forth in Section IX.D.2.1 and the \nappropriate factors of Sections IX.E of this Attachment FF.\nIX.D.2.1.\nGeneral Factors in Variance Analysis Outcome \nDetermination\nBefore deciding to impose any Variance Analysis Outcome \nauthorized by the Tariff in Sections IX.E of this Attachment FF, the \nTransmission provider shall consider the following factors:\nA.\nThe causes of, or reasons for, the circumstances or events \ntriggering Variance Analysis, including the degree of fault of the \napplicable Selected Developer or incumbent Transmission Owner;\nB.\nThe potential impacts to the Transmission System and the MTEP,"},{"page":749,"startToken":205548,"endToken":205773,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nincluding potential reliability, economic, or public policy impacts;\nC.\nThe degree of completion of the Eligible Projects or facilities;\nD.\nA comparison of the estimated costs of each outcome;\nE.\nA comparison of the degree to which each outcome will likely \nresult in the successful completion of or increase the ability to \ncomplete the facilities and/or Eligible Projects; and \nF.\nA comparison of the degree to which each outcome will alleviate \nthe ground(s) for Variance Analysis.\nIX.D.3.\nImplementation of Variance Analysis Outcome\nUpon completing the procedures detailed in Section IX.D.2 of this \nAttachment FF, the Transmission Provider shall perform the following as further \ndetailed in the Business Practices Manuals:\nA.\nInform the applicable Selected Developer(s) or incumbent \nTransmission Owner and any other affected parties of the Variance \nAnalysis Outcome in writing;\nB.\nPost a description of the Variance Analysis Outcome and the \nreason(s) it was selected on the Transmission Provider’s website, \nredacting any confidential information and or Critical Energy \nInfrastructure Information (CEII) as necessary.  The Transmission  \nProvider shall be authorized to publicly disclose confidential \ninformation, limited in scope to the specific information needed to \nexplain the reason(s) Variance Analysis was triggered and why the"},{"page":750,"startToken":205773,"endToken":205979,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nTransmission Provider selected the Variance Analysis Outcome for \nimplementation;\nC.\nImplement the Variance Analysis Outcome in coordination with \nthe applicable Selected Developer(s), incumbent Transmission \nOwner(s), and any other affected parties;\nD.\nIf implementation of the Variance Analysis Outcome results in a \nmitigation plan to be placed into effect that alters the schedule, \ncost, design, or scope of a Competitive Transmission Facility, the \nTransmission Provider and Selected Developer shall amend the \nSelected Developer Agreement to include the requirements of the \nmitigation plan or the Transmission Provider shall file such plan \nwith the Commission unexecuted; and\nE.\nIf implementation of the Variance Analysis Outcome results in \nReassignment or Cancellation of Competitive Transmission \nFacilities, the Transmission Provider shall file a Notice of \nTermination with the Commission to terminate the Selected \nDeveloper Agreement pursuant to the provisions of the Selected \nDeveloper Agreement.  In the event that the Transmission Provider \nfiles a Notice of Termination pursuant to Section IX.E of this \nAttachment FF or otherwise discusses confidential information in \nthe course of administrative or judicial proceedings, the \nTransmission Provider may request that the information be treated"},{"page":751,"startToken":205979,"endToken":206177,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nas confidential and non-public pursuant to 18 C.F.R. §1b.20 and \n388.112.\nIX.E. Variance Analysis Outcomes\nIn determining which Variance Analysis outcome to apply, the Transmission \nProvider shall apply the procedures specified in Section IX.D of this Attachment FF.\nIX.E.1.\nNo Action\nThe Transmission Provider may determine to take no action when \nVariance Analysis is triggered.  In determining whether to take no action in \nVariance Analysis, the Transmission Provider will consider, but is not limited to, \nthe following:\nA.\nThe causes of, or reasons for, the circumstances or events \ntriggering Variance Analysis, including the degree of fault of the \napplicable Selected Developer or incumbent Transmission Owner;\nB.\nThe potential impacts to the Transmission System and the MTEP, \nincluding any potential reliability, economic, or public policy \nimpacts;\nC.\nThe degree of completion of the Eligible Projects or facilities; and\nD.\nThe cost and impacts of implementing another Variance Analysis \nOutcome pursuant to Sections IX.E.2 through IX.E.4 of this \nAttachment FF as compared to taking no action."},{"page":752,"startToken":206177,"endToken":206436,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nIX.E.2.\nMitigation Plan(s)\nThe Transmission Provider may allow a Selected Developer or incumbent \nTransmission Owner to alleviate the ground(s) for the Variance Analysis through \na mitigation plan.  If the Transmission Provider determines that a delay in the \napplicable facilities and/or Eligible Project’s in-service date may cause the \nTransmission Provider or one or more Transmission Owners, Selected \nDevelopers, or non-Members to violate any Applicable Reliability Standards, the \nTransmission Provider shall identify the potential violation(s) and direct the \nimpacted entities to develop a mitigation plan in coordination with the \nTransmission Provider.  The Transmission Provider, the impacted Transmission \nOwners(s) and/or Selected Developers, as applicable, shall take any and all \nreasonable actions necessary to meet the requirements of the mitigation plan and \nApplicable Reliability Standards.\nMitigation plans may also be utilized to address ground(s) for Variance \nAnalysis arising under Sections IX.C.1 through IX.C.5 that do not involve a delay \nof the in-service date that potentially causes violations of Applicable Reliability \nStandards, should the Transmission Provider determine it is appropriate.  In \ndetermining whether to require a mitigation plan, the Transmission Provider will \nconsider the factors set forth in Sections IX.D.2.1 and IX.E.1 of this Attachment \nFF as well as, but not limited to:\nA.\nThe extent to which the ground(s) for Variance Analysis can be \nremedied through a mitigation plan, if successfully implemented,"},{"page":753,"startToken":206436,"endToken":206662,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nincluding the extent to which cost can be restored to baseline and \nthe required in-service date realized;\nB.\nThe willingness of the Selected Developer(s) or incumbent \nTransmission Owner(s) to implement the mitigation plan, \nincluding their willingness to bear the costs thereof;\nC.\nThe resources and ability of the Selected Developer(s) or \nincumbent Transmission Owner(s) to successfully implement the \nmitigation plan; and\nD.\nWhether the Transmission Owner(s) that would receive the \nreassigned facilities would be better able to alleviate the ground(s) \nfor Variance Analysis than the Selected Developer.\nThe mitigation measures may include, without limitation, any one or \ncombination of the following components: (i) an updated implementation plan; \n(ii) an operating procedure; or (iii) alternative facilities and or projects to mitigate \nreliability violations.  If a mitigation plan is used, the Transmission Provider and \nSelected Developer shall work together to amend the Selected Developer \nAgreement to reflect the mitigation plan. In the event that the Selected Developer \nor incumbent Transmission Owner refuses to execute the Transmission Provider’s \nproposed mitigation plan or offer a substitute plan reasonably acceptable to the \nTransmission Provider, the Transmission Provider may elect either to file its \nproposed mitigation plan with the Commission unexecuted, select an alternate"},{"page":754,"startToken":206662,"endToken":206915,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nVariance Analysis Outcome or, in if the Selected Developer is a signatory to the \nISO Agreement, proceed thereunder.\nIX.E.3.\nReassignment\nThe Transmission Provider may determine to reassign Competitive Transmission \nFacilities in accordance with Section IX.E.3.1 of this Attachment FF.  Reassignment shall \nalso be proper if a Selected Developer fails to maintain its Qualified Transmission \nDeveloper status after the expiration of any applicable cure period.  If a Selected \nDeveloper is the incumbent Transmission Owner whose service area is the service area \nfor which the facilities triggering Variance Analysis are located, the Transmission \nProvider shall seek recourse through the ISO Agreement or FERC, as appropriate.  In all \nother cases, the Transmission Provider will consider the factors set forth in Sections \nIX.D.2.1, IX.E.1, and IX.E.2 of this Attachment FF as well as the following, in \ndetermining whether Reassignment is applied including but not limited to:  \nA.\nWhether a mitigation plan would be sufficient to alleviate the ground(s) \nfor Variance Analysis;\nB.\nThe actions that the incumbent Transmission Owner(s), to whom the \nfacilities would be reassigned to if the Transmission Provider selects the \nReassignment Variance Analysis Outcome, would reasonably be required \nto take to successfully complete the facilities;\nC.\nThe incremental costs of the Reassignment Variance Analysis Outcome; \nand\nD.\nThe extent of any potential delay that the Reassignment Variance Analysis"},{"page":755,"startToken":206915,"endToken":207148,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nOutcome may cause and any potential impacts on reliability.\nIf the Transmission Provider selects the Reassignment Variance Analysis \nOutcome, the Selected Developer(s) shall be obligated to work cooperatively and \nin good faith with the Transmission Provider, the incumbent Transmission \nOwner(s), and the affected Transmission Owner(s) and/or non-MISO \ntransmission owners, to implement the transition.\nIX.E.3.1.\nProcedure for Reassignment\nPrior to making any determination to reassign facilities or projects, \nthe Transmission Provider shall consult with the entity or entities to which \nsuch facilities or projects would be assigned to ascertain: (1) the \nwillingness of such entities to develop, own, operate, and maintain such \nfacilities or project; (2) the estimated costs submitted by such entities and \nthe certainty of such estimates; and (3) the proposed schedule submitted \nby such entity or entities for developing the reassigned facilities or \nprojects and the degree of certainty of such schedule.  Reassigned facilities \nand or projects will be offered to the applicable Transmission Owner(s), as \ndefined below:  \nA.\nOwnership and the responsibility to construct facilities which are \nconnected to a single Transmission Owner’s system belong to that \nTransmission Owner; \nB. \nOwnership and the responsibilities to construct facilities which are \nconnected between two (2) or more Owners’ facilities belong equally to"},{"page":756,"startToken":207148,"endToken":207410,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\neach Transmission Owner, unless such Transmission Owners otherwise \nagree; and \nC.\nOwnership and the responsibility to construct facilities which are \nconnected between a Transmission Owner(s)’ system and a system or \nsystems that are not part of the Transmission Provider belong to such \nTransmission Owner(s) unless the Transmission Owner(s) and the non-\nTransmission Provider party or parties otherwise agree.  \nIf the applicable Transmission Owner(s) decline to construct the reassigned facilities and \nor Eligible Project, the Transmission Provider will reassign, as applicable, the facilities \nand/or Eligible Projects through the Competitive Transmission Developer Selection \nProcess, as described in Section VIII of Attachment FF of the Tariff.\nIX.E.4.\nCancellation of Facilities and or Projects\nThe Transmission Provider may determine to cancel Eligible Projects \nand/or facilities comprising such projects.  In determining whether to cancel \nEligible Projects or facilities, the Transmission Provider will consider the factors \nset forth in Sections IX.D.2.1, IX.E.1, IX.E.2, and X.E.3 of this Attachment FF.\nIX.F. Variance Analysis Confidentiality\nThe Transmission Provider shall not disclose to the public that a Variance \nAnalysis has commenced until such time as it has confirmed its initial determination that \na ground for Variance Analysis exists pursuant with Section IX.D.1 of this Attachment \nFF.  Notwithstanding the preceding sentence, the Transmission Provider shall be allowed \nto disclose that it is commencing a Variance Analysis to third parties, including"},{"page":757,"startToken":207410,"endToken":207681,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ninterconnecting Transmission Owners, Selected Developers, or non-Members from \nwhom the Transmission Provider requires information to determine whether the \nground(s) for Variance Analysis exist.  However, no confidential information will be \ndisclosed when the Transmission Provider solicits information from third parties unless \nand to the extent such disclosure is needed to obtain information necessary to determine \nany potential NERC reliability standards violations, service obligation issues, and \neconomic or public policy needs that may be jeopardized.\nIn the event that the Transmission Provider determines pursuant to Section IX.D.1 \nof this Attachment FF that ground(s) for Variance Analysis do not exist, the Transmission \nprovider shall treat any information collected pursuant to Section IX.D.1 as Project \nConfidential Information.  In the event that the Transmission Provider determines \npursuant to IX.D.1 of this Attachment FF that ground(s) for Variance Analysis do exist, \nthe Transmission provider shall be authorized to share Project Confidential Information \nwith such third parties as the Transmission Provider determines are reasonably necessary \nin order to enable the Transmission Provider to obtain needed input and information to \nidentify any potential system reliability impacts of Variance Analysis Outcomes, \nincluding impacts from any potential NERC reliability standards violations, service \nobligation issues, and economic or public policy needs that may be jeopardized.  The \nTransmission Provider shall consult with the Selected Developer and or the incumbent \nTransmission Owner prior to sharing any such confidential information for the purposes \nof discussing reasonable confidentiality safeguards.\nIX.G. Variance Analysis Dispute Resolution"},{"page":758,"startToken":207681,"endToken":207945,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nAll disputes by the affected Selected Developer or Transmission Owner shall be \naddressed in accordance with the provisions of Attachment HH, except that disputes \ninvolving the termination of a Selected Developer Agreement shall be addressed in \naccordance with the Dispute Resolution provisions of the Selected Developer Agreement. \nIX.H\nProject Financial Security\nThe Transmission Provider may utilize Project Financial Security to cover the \ncosts of Variance Analysis resulting from Default under the Selected Developer \nAgreement.  In such event, the Transmission Provider may draw upon such funds after \nconfirming that a Default exists pursuant to Section IX.D.1 of this Attachment FF.  The \nTransmission Provider shall utilize such funds to offset any costs reasonably incurred by \nthe Transmission Provider in performing a Variance Analysis, transitioning the \nCompetitive Transmission Project to a new Selected Developer and/or incumbent \nTransmission Owner(s), and otherwise distribute such funds as determined by the \nCommission to cover Variance Analysis and transition costs.  Costs for which Project \nFinancial Security funds may be used include reasonable consultant fees, attorneys’ fees, \ncosts of litigation and or regulatory proceedings, and staffing costs directly attributable to \ntaking actions under the Variance Analysis provisions of the Tariff.  The Transmission \nProvider shall track its use of Project Financial Security and provide an informational \nfiling to the Commission within six (6) months after the Transmission Provider concludes \nimplementation of the selected outcome.\nX. Interregional Coordination and Cost Allocation with the Southeastern Regional \nTransmission Planning Region"},{"page":759,"startToken":207945,"endToken":208183,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nThe public utility transmission providers in the Southeastern Regional Transmission Planning \nregion (“SERTP”) and the Midcontinent Independent System Operator region (“MISO”) shall \nundertake the interregional transmission coordination and cost allocation procedures under \nSection X of this Attachment FF. \nWhere the regional transmission planning process is referenced as part of this \ninterregional transmission coordination process the applicable regional transmission planning \nprocess for the Transmission Provider is described in Attachment FF; and is described for the \nSERTP in attachment K of the applicable SERTP transmission provider.\nA.\nInterregional Transmission Coordination\n1.\nAnnual Meeting: Representatives of the SERTP and staff of the \nTransmission Provider will meet no less than once per year to facilitate the \ninterregional \ncoordination \nprocedures \ndescribed \nbelow \n(as \napplicable).  \nRepresentatives of the SERTP and staff of the Transmission Provider may meet \nmore frequently during the evaluation of interregional transmission project(s) \nproposed for purposes of interregional cost allocation between the SERTP and the \nTransmission Provider transmission planning regions.\n2.\nWebsite Posting of Information on Interregional Coordination: The \nTransmission Provider shall utilize the regional planning website for \ncommunication of information related to these coordinated interregional \ntransmission planning procedures. The Transmission Provider shall coordinate \nwith the SERTP with respect to the posting of materials to the regional planning \nwebsite related to the interregional coordination procedures between the SERTP"},{"page":760,"startToken":208183,"endToken":208405,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nand the Transmission Provider transmission planning regions. The Transmission \nProvider shall, at a minimum, provide the following on the regional planning \nwebsite:\na.\nInterregional coordination and cost allocation procedures between the \nSERTP and Transmission Provider;\nb.\nLinks to where stakeholders can register (if applicable/available) for the \nstakeholder committees or distribution lists of the SERTP; \nc.\nDocuments related to joint evaluation of interregional transmission projects; \nand\nd.\nStatus report on interregional transmission projects selected for purposes of \ninterregional cost allocation between the SERTP and the Transmission \nProvider.\nB.\nModel and Data Exchange \nAt least annually, the Transmission Provider and the SERTP shall exchange their then-\ncurrent regional transmission plans including power-flow models and associated data \nused in the regional transmission planning processes to develop such transmission \nplan(s).   This exchange will occur when such data is available in each of the regional \ntransmission planning processes, typically during the first calendar quarter of each year. \nAdditional transmission-based models and data may be exchanged between the SERTP \nand the Transmission Provider as necessary and if requested.  For purposes of their \ninterregional coordination activities, the Transmission Provider and SERTP will \nexchange only data and models used in the development of their then-current regional"},{"page":761,"startToken":208405,"endToken":208625,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ntransmission process and plans. This data will be posted on the pertinent regional \ntransmission planning process’ websites, consistent with the posting requirements of the \nrespective regional transmission planning processes, and subject to the applicable \ntreatment of confidential data and Critical Energy Infrastructure Information (CEII).  The \nTransmission Provider shall notify SERTP of such posting.   \nC.\nIdentification and Joint Evaluation of Proposed Interregional Transmission \nProjects\n1.\nIdentification of Interregional Transmission Projects:  At least \nbiennially, the Transmission Provider and the SERTP shall meet to review the \nrespective regional transmission plans.  Such plans include each region’s \ntransmission needs as prescribed by each region’s planning process.  This review \nshall occur on a mutually agreeable timetable, taking into account each region’s \nregional transmission planning process timeline.  If through this review, the \nTransmission Provider and the SERTP identify a potential interregional \ntransmission project that may be more efficient or cost-effective than regional \ntransmission projects, the Transmission Provider and the SERTP shall jointly \nevaluate the potential interregional transmission project pursuant to Section \nX.C.4. \n2.\nIdentification of Interregional Transmission Projects by Stakeholders:  \nStakeholders and transmission developers (pursuant to Section X.D.1) may also \npropose interregional transmission projects that may be more efficient or cost-"},{"page":762,"startToken":208625,"endToken":208907,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\neffective than regional transmission projects pursuant to the procedures in each \nregion’s regional transmission planning processes.   \n3.\nIdentification of Interregional Transmission Projects by Developers:\nInterregional transmission projects proposed for interregional cost allocation \npurposes (“Interregional CAP”) must be submitted in both the Transmission \nProvider and the SERTP regional transmission planning processes. The project \nsubmittal must satisfy the requirements of Section X.D.1 except for the benefit-to-\ncost ratio requirements of Section X.D.1.a.ii3. The submittal must identify the \npotential transmission project as interregional in scope and identify the \nTransmission Provider and the SERTP as regions in which the project is proposed \nto interconnect. The Transmission Provider will verify whether the submittal for \nthe potential interregional transmission project satisfies all applicable \nrequirements.  Upon finding that the proposed interregional transmission project \nsatisfies all such applicable requirements, the Transmission Provider will notify \nthe SERTP.  Once the potential project has been proposed through the regional \ntransmission planning processes in both regions, and upon both regions so \nnotifying one another that the project is eligible for consideration pursuant to their \nrespective regional transmission planning processes, the Transmission Provider \nand the SERTP will jointly evaluate the proposed interregional projects pursuant \nto Sections X.C and X.D. \n3 A transmission developer is not responsible for determining the benefit-to-cost ratio referenced in Section \nX.D.1.a.ii in a project submittal.  However, an interregional transmission project proposed for Interregional CAP \nmust ultimately satisfy the benefit-to-cost ratio requirements in accordance with the provisions of Section X.D.1.a.ii \nand X.D.3."},{"page":763,"startToken":208907,"endToken":209137,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\n4.\nEvaluation of Interregional Transmission Projects:  The Transmission \nProvider and the SERTP shall act through their respective regional transmission \nplanning processes in the joint evaluation of potential interregional transmission \nprojects identified pursuant to Sections X.C.1 and X.C.2 to determine whether the \ninclusion of any potential interregional transmission projects in each region’s \nregional transmission plan would be more efficient or cost-effective than regional \nprojects.  Such analysis shall be consistent with accepted transmission planning \npractices of the respective regions and the methods utilized to produce each \nregion’s respective regional transmission plan(s).  The Transmission Provider will \nevaluate potential interregional transmission projects consistent with Section I.C.6 \nand Section II of Attachment FF. \n5.\nReview of Proposed Interregional Transmission Projects:  Initial \ncoordination activities regarding potential interregional transmission projects will \ntypically begin during the third quarter of each calendar year.  The Transmission \nProvider and the SERTP will exchange status updates regarding interregional \ntransmission projects that are newly proposed or that are currently under \nconsideration as needed.  These status updates will generally include, if \napplicable: (i) an update of the region’s evaluation of the proposal(s); (ii) the \nlatest calculation of benefits (as identified pursuant to  Section X.D.2); and (iii) \nthe anticipated timeline for future assessments."},{"page":764,"startToken":209137,"endToken":209350,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\n6.\nCoordination of Assumptions Used in Joint Evaluation:  The \nTransmission Provider and the SERTP will coordinate assumptions and data used \nin joint evaluations, as necessary, including items such as:\na.\nExpected timelines and milestones associated with the joint \nevaluation;\nb.\nStudy assumptions;\nc.\nModels; and\nd.\nBenefit calculations (as identified pursuant to Section X.D.2). \n \nD.\nInterregional Cost Allocation:  If an interregional transmission project is \nproposed for Interregional CAP in the SERTP and the Transmission Provider \ntransmission planning regions, then the following cost allocation and benefits \ncalculations, as identified pursuant to Section X.D.2, shall apply to the project: \n1. Interregional Transmission Projects Proposed for Interregional Cost \nAllocation Purposes: \na.\nFor a transmission project to be eligible for Interregional CAP \nwithin the SERTP and the Transmission Provider, the project must:  \ni.\nInterconnect to transmission facilities in both the SERTP and \nTransmission Provider regions. The facilities to which the project \nis proposed to interconnect may be either existing facilities or \ntransmission projects included in the regional transmission plan \nthat are currently under development4 \n4 For the MISO region, “under development” refers to Appendix A projects under development approved by the"},{"page":765,"startToken":209350,"endToken":209583,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nii.\nHave a combined benefit-to-cost ratio of 1.25 or higher to the \nSERTP and Transmission Provider regions, as calculated in \nSection X.D.3; and \niii.\nMeet the threshold and qualification criteria for transmission \nprojects potentially eligible to be included in the respective \nregional transmission plans for purposes of cost allocation in the \nTransmission Provider and the SERTP, pursuant to their respective \nregional transmission planning processes.\nb.\nOn a case-by-case basis, the Transmission Provider and the SERTP \nmay consider an interregional transmission project that does not satisfy all \nof the criteria specified in this Section X.D.1, but that: (i) meets the \nthreshold criteria for a project proposed to be included in the regional \ntransmission plan for purposes of cost allocation in only one of the two \nregions; and (ii) would be interconnected to transmission facilities in both \nthe SERTP and Transmission Provider regions.  The facilities to which the \nproject is proposed to interconnect may be either existing facilities or \ntransmission projects included in the regional transmission plan that are \ncurrently under development. \nc.\nThe transmission project must be proposed for purposes of cost \nallocation in both the SERTP and the Transmission Provider. The project \nsubmittal must satisfy all criteria specified in the respective regional \nMISO Board of Directors."},{"page":766,"startToken":209583,"endToken":209796,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ntransmission processes, including the respective timeframes for submittals \nproposed for cost allocation purposes. If a project is proposed by a \ntransmission developer, the transmission developer must also satisfy the \nqualification criteria specified by each region. \n2. Calculation of Benefits for Interregional Transmission Projects Proposed \nfor Interregional Cost Allocation Purposes:\nThe benefits used to establish \nthe allocation of costs of a transmission project proposed for Interregional \nCAP between the SERTP and the Transmission Provider shall be determined \nas follows: \na.\nEach transmission planning region, acting through its regional \ntransmission planning process, will evaluate proposals to determine \nwhether the proposed project(s) addresses transmission needs that are \ncurrently being addressed with projects in its regional transmission plan \nand, if so, which projects in the regional transmission plan could be \ndisplaced by the proposed project(s). \nb. Based upon its evaluation, each region will quantify its benefits based \nupon the transmission costs that each region is projected to avoid due to its \ntransmission projects being displaced by the proposed interregional \ntransmission project as follows: \ni.\nfor the SERTP, the total avoided costs of projects included \nin the then-current regional transmission plan that would be"},{"page":767,"startToken":209796,"endToken":210038,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ndisplaced if the proposed interregional transmission project \nwas included; and \nii.\nfor the Transmission Provider, the total avoided costs of \nprojects included in the then-current regional transmission \nplan that would be displaced if the proposed interregional \ntransmission project was included.  \nThe benefits calculated pursuant to this Section X.D.2 are not necessarily \nthe same as the benefits used for purposes of regional cost allocation. \n3. Calculation of Benefit-to-Cost Ratio for an Interregional Transmission \nProject Proposed for Interregional CAP:  \nPrior to any regional benefit-to-cost ratio calculation pursuant to either \nregional transmission planning process, the combined interregional benefit-to-\ncost ratio, referenced in Section X.D.1.a, shall be calculated for an \ninterregional transmission project proposed for Interregional CAP.  Such \ncalculation shall be performed by dividing the sum of the present value of the \navoided project cost determined in accordance with Section X.D.2.b.i for the \nSERTP region and the present value of avoided project cost determined in \naccordance with Section X.D.2.b.ii for the Transmission Provider region by \nthe present value of the proposed interregional transmission project’s total \nproject cost. The present values used in the cost calculation shall be based on \na common date, comparable cost components, and the latest cost estimates \nused in the evaluation of the interregional transmission project.  The combined"},{"page":768,"startToken":210038,"endToken":210277,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ninterregional benefit-to-cost ratio will be assessed in addition to, not in the \nplace of, the SERTP’s and the Transmission Provider’s respective regional \nbenefit-to-cost ratio assessment(s) (if applicable) as specified in the respective \nregional processes. \n4. Inclusion in Regional Transmission Plans:  An interregional transmission \nproject proposed for Interregional CAP in the transmission planning regions \nof the SERTP and the Transmission Provider will be included in the \nrespective regional transmission plans for purposes of cost allocation after: \na.\nEach region has performed all evaluations, as prescribed in its regional \ntransmission planning process, necessary for a project to be included in its \nregional transmission plan for purposes of cost allocation including any \nregional benefit-to-cost ratio calculations.  Each region shall utilize the \nbenefit calculation(s) as defined in such region’s regional transmission \nplanning process (for purposes of clarity, these benefits are not necessarily \nthe same as the benefits determined pursuant to Section X.D.2).  Each \nregion shall utilize the cost calculation(s) as defined in such region’s \nregional transmission planning process.  The anticipated percentage \nallocation of costs of the interregional transmission project to each region \nshall be based upon the ratio of the region’s benefits to the sum of the \nbenefits, both as determined pursuant to Section X.D.2, identified for both \nthe SERTP and the Transmission Provider."},{"page":769,"startToken":210277,"endToken":210529,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nb. Each region has obtained all approvals, as prescribed in its regional \nprocess, necessary for a project to be included in the regional transmission \nplan for purposes of regional cost allocation. \n5. Allocation of Costs Between the SERTP and the Transmission Provider \nRegions:  The cost of an interregional transmission project, selected for \npurposes of cost allocation in the regional transmission plans of both the \nSERTP and the Transmission Provider, will be allocated as follows: \na.\nEach region will be allocated a portion of the interregional transmission \nproject’s costs in proportion to such region’s benefit as calculated pursuant \nto Section X.D.2 to the sum of the benefits identified for both the SERTP \nand the Transmission Provider calculated pursuant to Section X.D.2.\ni.\nThe benefits used for this determination shall be based upon \nthe benefit calculation most recently performed – pursuant to \nthe method described in Section X.D.2 – before each region \nincluded the project in its regional transmission plan for \npurposes of cost allocation and as approved by each region. \nb. Costs allocated to each region shall be further allocated within each region \npursuant to the cost allocation methodology contained in its regional \ntransmission planning process.\n6. Milestones of Required Steps Necessary to Maintain Status as Being \nSelected for Interregional Cost Allocation Purposes:  Once selected in the \nrespective regional transmission plans for purposes of cost allocation, the"},{"page":770,"startToken":210529,"endToken":210750,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\ntransmission owners in the SERTP planning region that will be allocated costs \nof the transmission project,  the Transmission Provider, and the transmission \ndeveloper(s) must mutually agree upon an acceptable development schedule \nincluding milestones by which the necessary steps to develop and construct \nthe interregional transmission project must occur.  These milestones may \ninclude (to the extent not already accomplished) obtaining all necessary \nrights-of-way and requisite environmental, state, and other governmental \napprovals and executing a mutually-agreed upon contract(s) between the \napplicable transmission owners in the SERTP planning region, the \nTransmission Provider and the transmission developer.  If such critical steps \nare not met by the specified milestones and then afterwards maintained, then \nthe Transmission Provider and the SERTP may remove the transmission \nproject from the selected category in the regional transmission plans for \npurposes of cost allocation.\n7. Interregional Transmission Project Contractual Arrangements:  The \ncontracts referenced in Section X.D.6 will address terms and conditions \nassociated with the development of the proposed interregional transmission \nproject included in the regional transmission plans for purposes of cost \nallocation, including but not limited to:\na.\nEngineering, procurement, construction, maintenance, and operation of the \nproposed transmission project, including coordination responsibilities of \nthe parties;"},{"page":771,"startToken":210750,"endToken":210960,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nb. Emergency restoration and repair;\nc.\nThe specific financial terms and specific total amounts to be charged by \nthe transmission developer of the transmission project to each beneficiary, \nas agreed to by the parties;\nd. Creditworthiness and project security requirements;\ne.\nMilestone reporting, including schedule of projected expenditures;\nf.\nReevaluation of the transmission project; and\ng. Non-performance or abandonment.\n8. Removal from Regional Transmission Plans:  An interregional transmission \nproject may be removed from the SERTP’s or the Transmission Provider’s \nregional transmission plan(s) for Interregional CAP: (i) if the transmission \ndeveloper fails to meet developmental milestones; (ii) pursuant to the \nreevaluation procedures specified in the respective regional transmission \nplanning processes; or (iii) if the project is removed from one of the region’s \nregional transmission plans pursuant to the requirements of its regional \ntransmission planning process. \na.\nThe Transmission Provider shall notify the SERTP if an interregional \ntransmission project or a portion thereof is likely to be, and/or is actually \nremoved from its regional transmission plan.\nE. Transparency \n1. Stakeholders will have an opportunity to provide input and feedback \nwithin the respective regional transmission planning processes of the"},{"page":772,"startToken":210960,"endToken":211131,"text":"MISO\nATTACHMENT FF\nFERC Electric Tariff\nTransmission Expansion Planning Protocol\nATTACHMENTS\n95.0.0, 97.0.0\nEffective On: October 18, 2026\nSERTP and the Transmission Provider related to interregional \ntransmission \nprojects \nidentified, \nanalysis \nperformed, \nand \nany \ndetermination/results.  Stakeholders may participate in either or both \nregions’ regional transmission planning processes to provide their input \nand feedback regarding the interregional coordination between the SERTP \nand the Transmission Provider.\n2.  The Transmission Provider shall use the existing planning stakeholder \nforums, such as the Planning Advisory Committee and Sub-regional \nPlanning Meetings, to review with stakeholders the interregional activities \nassociated with the SERTP.\n3. The Transmission Provider will post a list, on the Regional Planning \nWebsite, of interregional transmission projects proposed for purposes of \ncost allocation in both the Transmission Provider and the SERTP regions \nthat are not eligible for consideration because they do not satisfy the \nregional project threshold criteria of one or both of the regions as well as \npost an explanation of the thresholds the proposed interregional projects \nfailed to satisfy."}],"sections":[{"p":1,"at":0,"title":"Opening text","method":"opening text","endPage":45,"endAt":122,"startToken":0,"endToken":11154},{"p":45,"at":122,"title":"A. Determination of Deliverability of Generation Resources, Electric Storage","method":"printed heading","endPage":46,"endAt":313,"startToken":11154,"endToken":11432},{"p":46,"at":313,"title":"B. Determination of Deliverability of Intermittent Generation, Dispatchable","method":"printed heading","endPage":47,"endAt":725,"startToken":11432,"endToken":11715},{"p":47,"at":725,"title":"C. Determination of Deliverability of Resources with Provisional Generator","method":"printed heading","endPage":48,"endAt":159,"startToken":11715,"endToken":11807},{"p":48,"at":159,"title":"A. Replacement of Planning Resources","method":"printed heading","endPage":52,"endAt":1014,"startToken":11807,"endToken":12977},{"p":52,"at":1014,"title":"B. Capacity Replacement Non-Compliance Charge and Distribution","method":"printed heading","endPage":65,"endAt":732,"startToken":12977,"endToken":16232},{"p":65,"at":732,"title":"A. Eligibility for Zonal Resource Credits for a Capacity Resource that is a Planning","method":"printed heading","endPage":67,"endAt":344,"startToken":16232,"endToken":16623},{"p":67,"at":344,"title":"B. Eligibility for Zonal Resource Credits for a Capacity Resource that is an","method":"printed heading","endPage":78,"endAt":188,"startToken":16623,"endToken":19278},{"p":78,"at":188,"title":"I. General","method":"printed heading","endPage":78,"endAt":1206,"startToken":19278,"endToken":19425},{"p":78,"at":1206,"title":"II. Tier 1 and Tier 2 Planned Outage Exemption Requirements","method":"printed heading","endPage":79,"endAt":972,"startToken":19425,"endToken":19689},{"p":79,"at":972,"title":"A. Tier 2 Planned Outage exemptions","method":"printed heading","endPage":80,"endAt":1125,"startToken":19689,"endToken":19986},{"p":80,"at":1125,"title":"B. 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