{"document":{"slug":"filing-er26-3650-miso-irr-attachment-1","title":"Tab A - IRR Tariff Redline.pdf","issued":"2026-08-28","accession":"20260828-5278","docket":"ER26-3650-000","group":"MISO filings","filer":"Midcontinent Independent System Operator, Inc.","kind":"attachment","file":"sources/originals/20260828-5278_02.pdf","url":"https://elibrary.ferc.gov/eLibrary/filelist?accession_Number=20260828-5278","parent":"filing-er26-3650-miso-irr","sha256":"30e33305b3ec59724158df255a62cc35852591e2bd84b0cc9703abadc570cf4d","pages":41,"tokens":9414,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":2,"text":"Tab A"},{"page":2,"startToken":2,"endToken":260,"text":"MISO\n1.C\nFERC Electric Tariff\nDefinitions - C\nMODULES\n80.0.0, 81.0.0\nEffective On: December 4, 2026\nCalculated Demand Response Resource-Type I Output:  The hourly average Actual Energy \nInjection for each associated Demand Response Resource – Type I for the Hour for the \npurposes of assessing Excessive/Deficient Energy Deployment Charges. \nCalculated Demand Response Resource-Type II Output:  (i) For a DRR-Type II Resource that \nis providing Regulating Service, the Dispatch Interval Actual Energy Injections; or (ii) \nFor a DRR-Type II Resource that is not providing Regulation Service, the average \nDispatch Target for Energy for the DRR-Type II Resource, expressed in MW and scaled \nby Actual Energy Injection.\nCalendar Day:  Any day of the week, including Saturday, Sunday or a Federal holiday.\nCandidate ARR (CARR):  ARR nominations submitted by Market Participants to be considered \nthroughout the Annual ARR Allocation process.\nCandidate Baseload ARR:  Candidate ARR rights equal to each Market Participant’s Baseload \nUsage in an ARR Zone.  \nCandidate Peak ARR:  Candidate ARR rights equal to each Market Participant’s Peak Usage in \nan ARR Zone.\nCandidate MTPS ARR:  MTPS ARR nominations submitted by the Transmission Provider to be \nconsidered during the Annual ARR Allocation process.\nCapacity:  The instantaneous rate at which Energy can be delivered, received or transferred, \nincluding Energy associated with Operating Reserve, Up Ramp Capability, Down Ramp \nCapability, and Short-Term Reserve, measured in MW.\nCapacity Deficiency Charge:  A charge that is assessed to an LSE that has provided notification \nprior to the Planning Resource Auction that it will meet its Initial PRMR in part or in"},{"page":3,"startToken":260,"endToken":527,"text":"MISO\n1.C\nFERC Electric Tariff\nDefinitions - C\nMODULES\n80.0.0, 81.0.0\nEffective On: December 4, 2026\nwhole by paying the Capacity Deficiency Charge so that the Transmission Provider does \nnot clear associated Zonal Resource Credits (ZRC) for the associated Initial PRMR \nthrough the PRA process.\nCapacity Export Limit (CEL):  The amount of Planning Resources in MWs for an LRZ or ERZ \ndetermined by the Transmission Provider that can be reliably exported from that LRZ or \nERZ for each Season.\nCapacity Import Limit (CIL):  The amount of Planning Resources in MWs for an LRZ \ndetermined by the Transmission Provider that can be reliably imported into that LRZ for \neach Season.\nCapacity Replacement Non-Compliance Charge: The charge assessed to a Market Participant \nfor failing to replace ZRCs that were designated for RAR and did not fulfill their \nperformance obligations as set forth in Module E-1.\nCapacity Resources:  The Generation Resources, Demand Response Resource- Type I, Demand \nResponse Resource-Type II, Dispatchable Intermittent Resources, External Resources, \nIntermittent Generation, or Electric Storage Resources that are available to meet Demand.  \nCarved Out GFA(s):  Any Grandfathered Agreement(s) that the Commission has identified as \n“carved out” pursuant to Appendix B of the Commission’s September 16, 2004 order, \nMidwest Independent Transmission System Operator, Inc., 108 FERC ¶ 61,236 (2004) or \nthat meet the criteria in Section 38.8.3(A).b, and set forth in Attachment P to this Tariff, \nas that Attachment may be amended from time to time.\nCash Collateral Agreement:  A Credit Support Document taking the form found in Exhibit III of \nAttachment L of this Tariff."},{"page":4,"startToken":527,"endToken":801,"text":"MISO\n1.C\nFERC Electric Tariff\nDefinitions - C\nMODULES\n80.0.0, 81.0.0\nEffective On: December 4, 2026\nCash Deposit:  Cash collateral provided to Transmission Provider to secure Applicant’s and/or \nTariff Customer’s performance under the terms and conditions of Transmission \nProvider’s Tariff, and/or other agreements.\nCatastrophic Generator Outage:  A forced outage that results in a unit being, or reasonably \nexpected to be unavailable for a minimum of six (6) continuous months, which is not the \nresult of a planned maintenance outage.\nCategory A Tariff Customer:  A Tariff Customer who grants a continuing first-priority security \ninterest to the Transmission Provider in all right, title and interest in any and all accounts \nreceivable and other rights of payment of the Tariff Customer for goods and services \nprovided under, or otherwise arising under, pursuant to or in connection with, the Tariff \nand/or any of the Agreements.\nCategory B Tariff Customer:  Any Tariff Customer who does not grant a Receivable Security \nInterest to the Transmission Provider.\nChange in Total System Cost:  The net change in variable operational costs, which include fuel, \nvariable O&M, variable environmental costs, and other variable costs as mutually agreed \nupon by the Transmission Provider and the Market Participant, measured in dollars as a \nresult of changing the output of one or more units in response to a redispatch request \nfrom the Transmission Provider.\nCharge:  The withdrawal of energy from the Transmission System by an Electric Storage \nResource for the purpose of storing the energy for injection back into the Transmission \nSystem at a later time.\nCleared Zonal Resource Credits (Cleared ZRCs):  Zonal Resource Credits that have cleared the"},{"page":5,"startToken":801,"endToken":1064,"text":"MISO\n1.C\nFERC Electric Tariff\nDefinitions - C\nMODULES\n80.0.0, 81.0.0\nEffective On: December 4, 2026\nPlanning Resource Auction, were used in a Fixed Resource Adequacy Plan, were used in \na Reliability Based Demand Curve Opt Out, or are currently being used to replace ZRCs.\nCoincident Peak Demand:  The Demand in MWs, for an LSE and/or EDC, that occurs \ncoincident to the peak Demand for each Season in the Transmission Provider Region, \nwhere all Demand has been augmented to include any known reductions in Demand \nrelated to LMRs.\nCo-located Resources:  Two or more Generators located behind the same point of \ninterconnection that participate separately in the Energy and Operating Reserve Markets \nand share an Interconnection Service Limit.\nCombined Reliability Systems:  The Reliability Coordination Customer Transmission Facilities \nand all other transmission facilities for which the Transmission Provider performs \nReliability Coordination Services under Part I of Module F.\nCommercial Model:  A presentation of the relationships between Market Participants and their \nResources, Commercial Pricing Nodes and the Network Model in the Energy and \nOperating Reserve Markets.\nCommercial Operation Date:  Shall have the meaning set forth in Attachment X of this Tariff.\nCommercial Pricing Node (CPNode):  An Elemental Pricing Node or an Aggregate Price Node \nin the Commercial Model used to schedule and settle Market Activities.  Commercial \nPricing Nodes include Resources, Hubs, Load Zones and/or Interfaces.\nCommercially Significant Voltage and Local Reliability Issue:  Transmission System voltage or \nother local reliability concerns that result in Voltage and Local Reliability Commitments.  \nThese issues are designated for reasons including, but not limited to, occurrence"},{"page":6,"startToken":1064,"endToken":1312,"text":"MISO\n1.C\nFERC Electric Tariff\nDefinitions - C\nMODULES\n80.0.0, 81.0.0\nEffective On: December 4, 2026\nfrequency, monetary impact, or other criteria as defined in Schedule 44.  A Local \nBalancing Authority or an interested Market Participant may request that the \nTransmission Provider evaluate a Voltage and Local Reliability Issue for designation as \ncommercially significant.\nCommission:  The Federal Energy Regulatory Commission, also known as FERC, or its \nsuccessor.\nCommitment Status: A specification submitted by a Market Participant in its Generation Offer, \nExternal Asynchronous Resource Offer, Demand Response Resource-Type I Offer, \nDemand Response Resource-Type II Offer, or Electric Storage Resource Offer for each \nHour to indicate whether or how the Transmission Provider is authorized to commit the \nResource or deploy the Resource for Operating Reserves for the Hour.\nCommon Bus:  A single Bus to which two or more Resources are connected in an electrically \nequivalent manner where such Resources are treated as a single Resource for compliance \nmonitoring purposes.\nCommon Information Model (CIM):  The format adopted by the NERC Data Exchange \nWorking Group that will be used by the Congestion Management Customer and the \nTransmission Provider to exchange Energy Management System models once a year.\nComparable FTRs:  FTRs that are identical in all material respects except for the quantity of \nMW specified. \nCompetitive Developer Qualification Process:  The process utilized to certify Qualified \nTransmission Developers pursuant to Section VIII.B of Attachment FF of the Tariff.\nCompetitive Developer Selection Process:  The process utilized to solicit Proposals, evaluate"},{"page":7,"startToken":1312,"endToken":1558,"text":"MISO\n1.C\nFERC Electric Tariff\nDefinitions - C\nMODULES\n80.0.0, 81.0.0\nEffective On: December 4, 2026\nProposals, and designating a Selected Proposal and Selected Developer(s) pursuant to \nSection VIII of Attachment FF of the Tariff.\nCompetitive Substation Facility:  A transmission substation facility contained within an Eligible \nProject that is subject to the Competitive Developer Selection Process in accordance with \nSection VIII.A of Attachment FF of the Tariff.\nCompetitive Transmission Executive Committee:  A committee consisting of three (3) or more \nexecutive staff of the Transmission Provider, including at least one (1) officer, that is \ncharged with overseeing all Transmission Provider staff and consultants involved in \nevaluating Transmission Developer Applications and Proposals in response to a posted \nRequest for Proposal.  The Competitive Transmission Executive Committee will have \nexclusive and final decision-making authority over: (i) the certification and termination \nof Qualified Transmission Developers; and (ii) the evaluation and selection of Proposals, \nresulting in designating Selected Developers.  The Competitive Transmission Executive \nCommittee shall possess the specific technical, financial, and regulatory expertise \nnecessary for evaluation of Transmission Developer Applications and Proposals.\nCompetitive Transmission Facility:  A Competitive Substation Facility or Competitive \nTransmission Line Facility.\nCompetitive Transmission Line Facility:  A transmission line facility contained within an \nEligible Project that is subject to the Competitive Developer Selection Process in \naccordance with Section VIII.A of Attachment FF of the Tariff. \nCompetitive Transmission Process:  The process utilized to certify Qualified Transmission \nDevelopers, identify Competitive Transmission Projects, solicit Proposals, evaluate"},{"page":8,"startToken":1558,"endToken":1805,"text":"MISO\n1.C\nFERC Electric Tariff\nDefinitions - C\nMODULES\n80.0.0, 81.0.0\nEffective On: December 4, 2026\nProposals, and designating a Selected Proposal and Selected Developer(s) pursuant to \nSection VIII of Attachment FF of the Tariff.  The Competitive Transmission Process \nincludes the Competitive Developer Qualification Process and Competitive Developer \nSelection Process.\nCompetitive Transmission Project:  The Competitive Transmission Facilities contained within \nan Eligible Project. \nCompetitively Sensitive Information:  Information that is not public and the unauthorized \ndisclosure of which could have anti-competitive effects, provide a competitor with an \nunfair or improper competitive advantage, or unfairly or improperly result in competitive \nharm, detriment, prejudice, disadvantage or injury to the legitimate proprietary rights, \nbusiness or commercial interests, market position, or ability to bargain freely, of the \nlawful owners, possessors or users of such information.\nCompleted Application:  An Application that satisfies all of the information and other \nrequirements of the Tariff, including any required deposit.\nComposite Credit Score:  A composite numerical score scaled from 1.00 to 6.99, representing \nthe sum of the Qualitative and Quantitative score as calculated by the Transmission \nProvider’s credit scoring model in Attachment L of this Tariff.\nComputational Load:  Large Load comprised of 25 MW or more of Demand from information \ntechnology equipment, such as servers, storage, and networking hardware.\nConfidential Information:  Any proprietary or commercially or competitively sensitive \ninformation, trade secret or information regarding a plan, specification, pattern, \nprocedure, design, device, list, concept, policy or compilation relating to the present or"},{"page":9,"startToken":1805,"endToken":2051,"text":"MISO\n1.C\nFERC Electric Tariff\nDefinitions - C\nMODULES\n80.0.0, 81.0.0\nEffective On: December 4, 2026\nplanned business of a Transmission Customer, Market Participant, or other user, which is \ndesignated as confidential by the entity supplying the information, whether conveyed \norally, electronically, in writing, through inspection, or otherwise, that is received by the \nTransmission Provider and is not disclosed except under the terms of a Confidential \nInformation policy. \nCongestion Management Customer:  Any entity taking Interconnected Operations and \nCongestion Management Service under Part II of Module F.\nCongestion Management Process (CMP):  The process described in Attachment LL of the \nTariff.\nConstraint Contribution Factor:  Factor that represents the impact that an incremental Actual \nEnergy Injection or Actual Energy Withdrawal of one MW has on a given Active \nTransmission Constraint.\nConstraint Generation Shift Factor Cutoff:  A Generation Shift Factor level defined for each \ntransmission constraint that determines the generating units to be included in a Broad \nConstrained Area, Narrow Constrained Area or Dynamic NCA associated with the \nconstraint.  Generation Resources with a Generation Shift Factor whose absolute value is \ngreater than the Constraint Generation Shift Factor Cutoff are included in the Broad \nConstrained Area, Narrow Constrained Area or Dynamic NCA.\nConstraint Management Charge Allocation Factor:  A factor that is used to apportion Real-\nTime Revenue Sufficiency Guarantee Credits in an Hour between (i) the Real-Time \nRevenue Sufficiency Guarantee Constraint Management Charge and (ii) the Real-Time \nRevenue Sufficiency Guarantee Day-Ahead Schedule Deviation Charge and the Real-"},{"page":10,"startToken":2051,"endToken":2297,"text":"MISO\n1.C\nFERC Electric Tariff\nDefinitions - C\nMODULES\n80.0.0, 81.0.0\nEffective On: December 4, 2026\nTime Revenue Sufficiency Guarantee Headroom Charge.\nContingency Reserve:  Spinning Reserve and Supplemental Reserve provided by Resources \navailable to the Transmission Provider to use in the event of a system contingency as \nspecified in Schedule 5-Spinning Reserve and Schedule 6– Supplemental Reserve of this \nTariff. \nContingency Reserve Deployment Failure Charge:  A charge assessed to any Resource that \nfails to achieve in a Contingency Reserve Deployment Period at least one hundred \npercent (100%) of the Contingency Reserve Deployment Instruction target.\nContingency Reserve Deployment Instruction:  An instruction issued by the Transmission \nProvider to Resources with cleared Contingency Reserve to deploy a specific MW \nquantity of cleared Contingency Reserve as communicated via Setpoint Instructions or \nother electronic means.\nContingency Reserve Deployment Period:  The period of time the Resource has to deploy \nContingency Reserve following the issuance of a Contingency Reserve Deployment \nInstruction that is equal to ten minutes. \nContingency Reserve Offer Price Cap:  The maximum price permitted for a Spinning Reserve \nOffer, an On-Line Supplemental Reserve Offer, an Off-Line Supplemental Reserve Offer \nor a Supplemental Reserve Offer in the Energy and Operating Reserve Markets.\nContinuing Error:  A continuing software, system or other execution that is inconsistent with \nthe Tariff.\nControl:  The possession, directly or indirectly, of the power to direct the management or \npolicies of a person or an entity.  A voting interest of ten percent (10%) or more shall"},{"page":11,"startToken":2297,"endToken":2525,"text":"MISO\n1.C\nFERC Electric Tariff\nDefinitions - C\nMODULES\n80.0.0, 81.0.0\nEffective On: December 4, 2026\ncreate a rebuttable presumption of Control.\nControllable Devices:  Devices that may include phase shifters, DC lines, and back-to-back \nAC/DC converters. \nCo-optimized Zonal Contingency Reserve Requirement: The minimum amount of Contingency \nReserve the Transmission Provider needs to procure within a Reserve Zone as determined \nbased upon co-optimization with Post Reserve Deployment Constraints.\nCo-optimized Zonal Operating Reserve Requirement:  The sum of the Co-optimized Zonal \nContingency Reserve Requirement and Co-optimized Zonal Regulating Reserve \nRequirement.\nCo-optimized Zonal Regulating Reserve Requirement: The minimum amount of Regulating \nReserve the Transmission Provider needs to procure within a Reserve Zone as determined \nbased upon co-optimization with Post Reserve Deployment Constraints.\nCo-optimized Zonal Short-Term Reserve Requirement: The minimum amount of Short-Term \nReserve the Transmission Provider needs to procure within a Reserve Zone as determined \nbased upon co-optimization with Post Reserve Deployment Constraints.\nCo-optimized Zonal Spinning Reserve Requirement:  The minimum amount of Spinning \nReserve the Transmission Provider needs to procure within a Reserve Zone as determined \nbased upon co-optimization with Post Reserve Deployment Constraints.\nCoordinated Flowgate:  A Flowgate that is subject to the Transmission Provider’s or \nCoordination Customer’s operational control and through which flows are affected by \ntransmission over transmission facilities within its operational control, or with respect to \nwhich Transmission Provider serves as a Reliability Authority."},{"page":12,"startToken":2525,"endToken":2805,"text":"MISO\n1.C\nFERC Electric Tariff\nDefinitions - C\nMODULES\n80.0.0, 81.0.0\nEffective On: December 4, 2026\nCoordinated Transaction Schedule:  An Interchange Schedule to purchase Energy in the Real-\nTime Energy and Operating Reserve Market from a Source Point in either the MISO \nBalancing Authority Area or PJM Balancing Authority Area and sell it at a Sink Point in \nthe other balancing authority area that is cleared if the forecasted LMP at the Sink Point \nminus the forecasted LMP at the Source Point is greater than or equal to the dollar value \nspecified in the bid associated with the Interchange Schedule.\nCoordinating Owner:  Any entity that is not subject to the jurisdiction of the Commission but \nparticipating in the ISO through the execution of a coordination agreement which \nincludes provisions for the elimination of rate pancaking.  The terms and provisions of a \nCoordinating Owner’s coordination agreement shall supersede the similar terms and \nprovisions of this Tariff where applicable.\nCoordination Customer:  Any customer taking Coordination Services from the Transmission \nProvider pursuant to Module F of the Tariff.  The term Coordination Customer includes:  \nReliability Coordination Customer, and Congestion Management Customer.\nCoordination Services:  The services provided by the Transmission Provider pursuant to Module \nF of the Tariff.  Coordination Services include Reliability Coordination Service and \nInterconnected Operations and Congestion Management Service.\nCorporate Guaranty:  A legal document taking the form found in Exhibit I of Attachment L of \nthis Tariff used by an Affiliate of an Applicant and/or Tariff Customer that guarantees the \nobligations of such Applicant or Tariff Customer. \nCost Allocation Zone:  The zones identified in Attachment WW of this Tariff used for allocating \nthe costs of Market Efficiency Projects."},{"page":13,"startToken":2805,"endToken":3085,"text":"MISO\n1.C\nFERC Electric Tariff\nDefinitions - C\nMODULES\n80.0.0, 81.0.0\nEffective On: December 4, 2026\nCost of Congestion:  The Marginal Congestion Component of LMP at the sink minus the \nMarginal Congestion Component of LMP at the source.\nCost of Losses:  Marginal Losses Component of LMP at the sink minus the Marginal Losses \nComponent of LMP at the source.\nCost of New Entry (CONE):  The capital, operating, financial and other costs of acquiring a new \nGeneration Resource within the Transmission Provider Region for any designated LRZ.\nCouncil of the City of New Orleans (CNO):  The governmental body with the power of \nsupervision, regulation, and control over public utilities providing service within the City \nof New Orleans, i.e., Entergy New Orleans, pursuant to the Constitution of the State of \nLouisiana and the Home Rule Charter of the City of New Orleans.  CNO shall have all \nthe rights and responsibilities granted herein to states, state public utility commissions, \nstate agencies, and State Regulatory Authorities.\nCounterflow ARR:  ARR allocated during the LTTR Restoration and Termination Stage of an \nAnnual ARR Allocation based on a Counterflow ARR Entitlement.\nCounterflow ARR Entitlement:  Any Stage 1A eligible ARR Entitlement’s portion that was not \nnominated in Stage 1A of a Market Participant’s year 1 Annual ARR Allocation but that \nthe Transmission Provider deems to provide counterflow necessary to enable curtailed \nStage 1A CARRs to be restored (fully or partly) during the LTTR Restoration and \nTermination Stage of an Annual ARR Allocation.\nCredit and Security Agreement:  A Credit Support Document taking the form found in Exhibit \nV of Attachment L of this Tariff.\nCredit Policy:  The Transmission Provider’s creditworthiness requirements and credit evaluation"},{"page":14,"startToken":3085,"endToken":3365,"text":"MISO\n1.C\nFERC Electric Tariff\nDefinitions - C\nMODULES\n80.0.0, 81.0.0\nEffective On: December 4, 2026\nprocedures as contained in Attachment L of this Tariff. \nCredit Support Documents:  Any agreement or instrument in any way guaranteeing or securing \nany or all of a Tariff Customer’s obligations under this Tariff (including, without \nlimitation, the Credit Policy), any agreement entered into under, pursuant to, or in \nconnection with this Tariff or any agreement entered into under, pursuant to, or in \nconnection with this Tariff or the Credit Policy, and/or any other agreement to which the \nTransmission Provider and the Tariff Customer are parties, including, without limitation, \nany Corporate Guaranty, Cash Collateral Agreement, Letter of Credit, Credit and \nSecurity Agreement or agreement granting a security interest. \nCritical Energy Infrastructure Information (CEII):  Confidential information described in 18 \nC.F.R § 388.113(c)(1), as may be amended from time to time.\nCurtailment:  A reduction in firm or non-firm Transmission Service in response to a transfer \ncapability shortage as a result of system reliability conditions pursuant to Section 14.7 or \nSection 27A of this Tariff.\nCustomer Load Aggregation:  A Load Zone approved by the Transmission Provider for the \npurposes of submitting Bids to or scheduling into the Energy and Operating Reserve \nMarkets and for settlement of Market Activities. \nCyber Exigency:  A suspicious electronic act or event that has the potential to compromise \nreliability within the Transmission Provider Region or other electrical facilities directly \nor indirectly connected to the Transmission System and whose severity reasonably \nrequires that the Transmission Provider obtain expert assistance not normally called upon \nto counter such an electronic act or to resolve such an event."},{"page":15,"startToken":3365,"endToken":3683,"text":"MISO\n1.L\nFERC Electric Tariff\nDefinitions - L\nMODULES\n51.0.0, 52.0.0\nEffective On: December 4, 2026\nLarge Load:  Load with Demand of 50 MW or more associated with any facility or aggregation \nof facilities located at a single substation behind one or more Point(s) of Withdrawal from \nthe Transmission System that is owned, operated, or controlled by: (a) a single entity, or \n(b) a group of entities that will coordinate with respect to the profile of the Load.  Large \nLoad does not include Load used exclusively for charging an Electric Storage Resource.\nLarge Load Equipment:  Any of the facilities, devices, or equipment that constitutes a part of a \nLarge Load, or are used to interconnect the Large Load to the Transmission System.\nLegitimate Risks:  Business operation risks, incurred by a Market Participant, that increase as a \nresult of providing any of the products described in the Tariff.  These risks include, but \nare not limited to, the risk of repair expenses; business interruption due to outages \nresulting from either a failure to start, or unplanned outages that occur when the facility is \nin service; regulatory restrictions; and disruptions from labor relations problems.  These \nrisks are in the nature of marginal costs included in Reference Levels.  In contrast, the \nrisk associated with fuel purchase price is not a component of Reference Levels, but \nrather a basis for the Fuel Cost Uncertainty Adder and some of the conduct thresholds \nunder Module D. \nLetter of Credit:  A Credit Support Document taking the form found in Exhibit II of Attachment \nL to this Tariff. \nLine Outage Distribution Factor (LODF):  The percent of flow on line A, which is transferred \nto line B for the loss of line A.\nLoad:  A term that refers to either an end-user of Energy, net of system losses, or the amount of \nEnergy (MWh) consumed by such end-user within the Transmission Provider Region."},{"page":16,"startToken":3683,"endToken":3965,"text":"MISO\n1.L\nFERC Electric Tariff\nDefinitions - L\nMODULES\n51.0.0, 52.0.0\nEffective On: December 4, 2026\nLoad Forecast:  An estimate of the amount of Energy (MWh) or Capacity (MW) to be \nconsumed within the Transmission Provider’s Region, prepared by the Transmission \nProvider based upon input from Local Balancing Authorities and Load Serving Entities, \nand used in the Transmission Provider’s scheduling and dispatch decisions to ensure \nreliable operation of the MISO Balancing Authority. \nLoad Modifying Resource:  A Demand Resource or Behind the Meter Generation Resource. \nLoad Modifying Resource Market Participant (LMR MP):  A Market Participant that has the \nrights to control the energy demand or the energy production from a Load Modifying \nResource.\nLoad Ratio Share:  Ratio of a Transmission Customer’s Network Load in a Zone to the total \nLoad in that pricing Zone computed in accordance with Module B, Section 34.2 of this \nTariff.\nLoad Serving Entity (LSE):  Any entity that has undertaken an obligation to serve Load for end-\nuse customers by statute, franchise, regulatory requirement or contract for Load located \nwithin or attached to the Transmission System, including but not limited to purchase-\nselling entities and retail power marketers with the obligation to serve Load.  Where a \ndistribution cooperative or a municipal distribution system otherwise covered by the prior \nsentence is a wholesale customer of a generation and transmission cooperative or a \nmunicipal Joint Action Agency, the generation and transmission cooperative, a state or \nfederal agency or municipal Joint Action Agency may act as the Load Serving Entity for \nsuch distribution cooperative or municipal distribution system.  Where retail Load \nswitching occurs in a state, the entity with the obligation to serve Load is the LSE"},{"page":17,"startToken":3965,"endToken":4234,"text":"MISO\n1.L\nFERC Electric Tariff\nDefinitions - L\nMODULES\n51.0.0, 52.0.0\nEffective On: December 4, 2026\nLoad Shedding:  The systematic reduction of system demand by temporarily decreasing Load in \nresponse to a Transmission System Emergency, Local Transmission Emergency, or \nMISO Balancing Authority Area or Sub-Area Capacity shortages, system instability, or \nvoltage control considerations under Module B and Module C, of this Tariff. \nLoad Zone:  A Zone determined by Market Participants representing an aggregate area of \nconsumption for a single Load Serving Entity within the MISO Balancing Authority Area \nand used for the purposes of scheduling, reporting Actual Energy Withdrawal volumes, \nand settling Energy transactions at aggregated Load levels, approved and maintained by \nthe Transmission Provider to facilitate transactions.\nLocal Balancing Authority (LBA):  An operational entity or a Joint Registration Organization \nwhich is (i) responsible for compliance to NERC for the subset of NERC Balancing \nAuthority Reliability Standards defined in the Balancing Authority Agreement for their \nlocal area within the MISO Balancing Authority Area, (ii) a Party to Balancing Authority \nAgreement, excluding MISO, and (iii) shown in Appendix A to the Balancing Authority \nAgreement. \nLocal Balancing Authority Area:  Shall have the meaning set forth in the Balancing Authority \nAgreement.\nLocal Clearing Requirement (LCR):  The minimum amount of Seasonal Accredited Capacity \nfor an LRZ that is required to meet its LOLE for each Season while fully using the Zonal \nImport Ability for such LRZ and accounting for controllable exports. \nLocal Clearing Requirement Charge: A charge that is assessed to Load Serving Entities \nwhenever an LRZ’s Auction Clearing Price for a Season is increased due to its LCR"},{"page":18,"startToken":4234,"endToken":4505,"text":"MISO\n1.L\nFERC Electric Tariff\nDefinitions - L\nMODULES\n51.0.0, 52.0.0\nEffective On: December 4, 2026\nbeing greater than the sum of individual Final PRMR of the LSEs.\nLocal Reliability Requirement (LRR):  The minimum amount of Unforced Capacity for an LRZ \nto meet its LOLE for each Season, without considering transmission ties to systems \noutside of the LRZ. \nLocal Resource Zone (LRZ):  A geographic area within the Transmission Provider Region that \nis prescribed by the Transmission Provider, based upon the criteria in Section 68A.3, to \naddress congestion that limits Planning Resource deliverability.\nLocal Resource Zone Peak Demand:  The Demand in MWs, for an LSE and/or EDC, in a Local \nResource Zone that occurs coincident to the peak Demand for each Season in the Local \nResource Zone, where all Demand has been augmented to include any known reductions \nin Demand related to LMRs.\nLocal Short-Term Reserve: Short-Term Reserve available to the Transmission Provider to \naddress transmission constraints in any Reserve Zone(s). \nLocal Short-Term Reserve Requirements: The amount of Local Short-Term Reserve, as \ndetermined pursuant to Module C of the Tariff, that the Transmission Provider is required \nto procure in a Reserve Zone.\nLocal Transmission Emergency:  Transmission System conditions or events that have the \npotential to exceed or have exceeded operating limits that do not pose a risk of cascading \nto the interconnection but require emergency-level actions.\nLocational Marginal Price (LMP):  A price for Energy at a given Commercial Pricing Node in \nthe Transmission Provider Region which is the marginal cost of serving demand at the \nCommercial Pricing Node while meeting Zonal and Market-Wide Operating Reserve"},{"page":19,"startToken":4505,"endToken":4785,"text":"MISO\n1.L\nFERC Electric Tariff\nDefinitions - L\nMODULES\n51.0.0, 52.0.0\nEffective On: December 4, 2026\nRequirements, Up Ramp Capability requirements, Down Ramp Capability requirements, \nand Short-Term Reserve Requirements.  Such price may be either Ex Ante or Ex Post. \nLong-Term Firm Point-To-Point Transmission Service:  Firm Point To Point Transmission \nService under Module B of this Tariff with a term of one (1) year or more.\nLong Term Transmission Rights (LTTR):  ARRs allocated in Stage 1A of the Annual ARR \nAllocation process.  LTTRs carry annual rollover rights lasting ten (10) years or more. \nLook Ahead Commitment (LAC):  A process performed during the Real-Time Energy and \nOperating Reserve Market that develops Resource commitment and decommitment \noptions that may be used by the Transmission Provider to ensure sufficient Resources \nwill be available to meet Load Forecast, Operating Reserve, Up Ramp Capability, Down \nRamp Capability, Short-Term Reserve and other demand requirements for the near term \nintra-hour intervals.\nLoss of Load Expectation (LOLE):  An estimate of the average number of days with supply \ninterruption to end use customers, whether for a single hour or multiple hours in a day. \nLoss of Load Probability Curve:  The probability of shedding firm Load under varying levels of \nContingency Reserve shortages, to be used in accordance with Schedule 28. This curve is \nfurther described in the Transmission Provider’s Business Practices Manual for the \nEnergy and Operating Reserves Markets (BPM-002).\nLoss Pools:  A single Local Balancing Authority Area or an aggregation of Local Balancing \nAuthority Areas, including those Local Balancing Authority Areas operated by \nCoordinating Owners consistent with the terms and provisions of the Coordinating \nOwners agreement, designated by the Transmission Provider for the purposes of"},{"page":20,"startToken":4785,"endToken":4835,"text":"MISO\n1.L\nFERC Electric Tariff\nDefinitions - L\nMODULES\n51.0.0, 52.0.0\nEffective On: December 4, 2026\ncalculating and distributing Day Ahead and Real Time Hourly Marginal Losses Revenue \nSurplus.\nLost Opportunity Cost:  The LMP revenues that were not realized relative to a theoretical future \noperating point."},{"page":21,"startToken":4835,"endToken":5124,"text":"MISO\n1.P\nFERC Electric Tariff\nDefinitions - P\nMODULES\n69.0.0, 71.0.0\nEffective On: December 4, 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":22,"startToken":5124,"endToken":5375,"text":"MISO\n1.P\nFERC Electric Tariff\nDefinitions - P\nMODULES\n69.0.0, 71.0.0\nEffective On: December 4, 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":23,"startToken":5375,"endToken":5660,"text":"MISO\n1.P\nFERC Electric Tariff\nDefinitions - P\nMODULES\n69.0.0, 71.0.0\nEffective On: December 4, 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":24,"startToken":5660,"endToken":5904,"text":"MISO\n1.P\nFERC Electric Tariff\nDefinitions - P\nMODULES\n69.0.0, 71.0.0\nEffective On: December 4, 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":25,"startToken":5904,"endToken":6161,"text":"MISO\n1.P\nFERC Electric Tariff\nDefinitions - P\nMODULES\n69.0.0, 71.0.0\nEffective On: December 4, 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":26,"startToken":6161,"endToken":6462,"text":"MISO\n1.P\nFERC Electric Tariff\nDefinitions - P\nMODULES\n69.0.0, 71.0.0\nEffective On: December 4, 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":27,"startToken":6462,"endToken":6757,"text":"MISO\n1.P\nFERC Electric Tariff\nDefinitions - P\nMODULES\n69.0.0, 71.0.0\nEffective On: December 4, 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":28,"startToken":6757,"endToken":6967,"text":"MISO\n1.P\nFERC Electric Tariff\nDefinitions - P\nMODULES\n69.0.0, 71.0.0\nEffective On: December 4, 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":29,"startToken":6967,"endToken":7003,"text":"MISO \nv \nFERC Electric Tariff \nREQUIREMENTS FOR LARGE LOAD \nMODULES \n31.0.0 \nEffective On: December 4, 2026\nMISO\nV\nFERC Electric Tariff\nREQUIREMENTS FOR LARGE LOAD\nMODULES\n31.0.0\nEffective On: December 4, 2026"},{"page":30,"startToken":7003,"endToken":7300,"text":"MISO\n37A\nFERC Electric Tariff\nApplicability of Large Load Reliability Requirements\nMODULES\n31.0.0\nEffective On: December 4, 2026\nI.\nApplicability of Large Load Reliability Requirements\nThe Transmission Customer taking Transmission Service on behalf of a Large Load shall \nbe responsible for complying with each of the requirements of this Section 37A applicable to \neach Large Load it represents.\nExcept as set forth in Section 37A.II, all Large Load shall be subject to the Basic Facility \nData, Modeling, Telemetry, Forecast Data, and Audit requirements set forth in Sections 37A.1 \nthrough 37A.4 and section 37A.8 of the Tariff. \nExcept as set forth in Section 37A.II, Computational Load, shall be subject to the Phasor \nMeasurement Unit, Ride-Through and Ramp requirements set forth in Sections 37A.5 through \n37A.7 of the Tariff.  The Transmission Provider shall determine whether Computational Load is \nassociated with a Large Load based on information provided by the Transmission Customer to \nthe Transmission Provider for such purpose, as set forth in the Business Practices Manual for \nLarge Load.\nA Transmission Customer taking Transmission Service on behalf of a Large Load shall \ndemonstrate its ability to effectuate compliance with each of the requirements of this Section \n37A.  The Transmission Customer shall provide the Transmission Provider with documentation \nnecessary for the Transmission Provider to verify compliance with the requirements of this \nSection 37A.  Such documentation may include applicable agreement(s), if any, between the \nTransmission Customer and the entity or entities that own, operate or use the Large Load, or an \nattestation signed by an authorized officer of the Transmission Customer demonstrating that the \nTransmission Customer will be provided access to all information reasonably required to enable \nthe Transmission Customer to comply with and for the requirements of this Section 37A,"},{"page":31,"startToken":7300,"endToken":7585,"text":"MISO\n37A\nFERC Electric Tariff\nApplicability of Large Load Reliability Requirements\nMODULES\n31.0.0\nEffective On: December 4, 2026\nincluding compliance with the terms of any operating protocols adopted by the Transmission \nProvider, Transmission Owner and/or the Transmission Customer for a specific Large Load.  \nFailure to comply with the requirements established in this Section 37A may result in a \ndelayed Service Commencement Date, a period of time needed for corrective action, operational \nlimitations, or other remediation action(s) by Transmission Provider as may be necessary to \nmaintain Transmission System reliability.  The process by which Transmission Provider will \ndetermine whether any such measures are appropriate, which may include the period of time \nduring which corrective action must be undertaken, shall be as set forth in the Business Practices \nManual for Large Load.\nII.\nTransition Provisions\n1)\nFor purposes of these transition provisions, Load associated with a transmission \nproject shall be defined as meeting the “MTEP/EPR Condition” if the project has \neither: (a) been approved by the Transmission Provider Board in MTEP 2026, or a \nprior MTEP; or, (b) been submitted to the Transmission Provider for Expedited \nProject Review (EPR) on or prior to June 18, 2026, in accordance with \nAttachment FF of the Tariff.\n2)\nA Transmission Customer taking Transmission Service on behalf of a Large Load \nshall ensure that all Large Load shall be subject to all the requirements as set forth \nin this Section 37A, provided that:\n(a)\nFully Exempt Large Load:\nA Large Load that has a Service Commencement Date on or prior to \nDecember 4, 2026, shall be exempt from all requirements set forth in this \nSection 37A with respect to the portion of the Large Load that has"},{"page":32,"startToken":7585,"endToken":7855,"text":"MISO\n37A\nFERC Electric Tariff\nApplicability of Large Load Reliability Requirements\nMODULES\n31.0.0\nEffective On: December 4, 2026\nprocured Transmission Service as of the Service Commencement Date.  \nAny modification or series of modifications to a Load that meets the \nMTEP/EPR Condition, which results in a cumulative increase of 25 MW \nor more in Transmission Service for such Load and with a Service \nCommencement Date after December 4, 2026, shall be subject to \nsubsection (2)(b) below.\n(b)\nPartially Exempt Large Load:\n(i) A Large Load, or a portion of a Large Load, that does not have a \nService Commencement Date prior to December 4, 2026, but that meets \nthe MTEP/EPR Condition as defined herein shall be subject to the \nrequirements set forth in Sections 37A.1 through 37A.5 and Section \n37A.8, and shall be exempt from the requirements set forth in Sections \n37A.6 through 37A.7.\n(ii) A Large Load, or a portion of Large Load, that does not have a Service \nCommencement Date prior to December 4, 2026, and that has not met the \nMTEP/EPR Condition but has submitted Load associated with a \ntransmission project to the Transmission Provider for EPR on or after June \n19, 2026, but on or before October 31, 2026, shall be subject to all \nrequirements set forth in this Section 37A, provided that Transmission \nProvider may waive the requirements set forth in Section 37A.6 based \nupon a determination that: a) exemption from such requirements would \nnot have an adverse reliability impact; and, b) compliance with such \nrequirements would result in significant costs.  The Business Practices"},{"page":33,"startToken":7855,"endToken":8018,"text":"MISO\n37A\nFERC Electric Tariff\nApplicability of Large Load Reliability Requirements\nMODULES\n31.0.0\nEffective On: December 4, 2026\nManual for Large Load shall set forth the process and documentation \nnecessary for Transmission Provider to determine whether such criteria \nhave been met.\n(c)\nNon-Exempt Large Load:\nA Large Load, or a portion of a Large Load, that does not meet the \nMTEP/EPR Condition shall be subject to all applicable requirements set \nforth in this Section 37A.\n3)\nNotwithstanding any of the provisions above the Transmission Provider has the \nright to require compliance with any or all requirements of this Section 37A if the \nTransmission Provider determines that operation of a Large Load results in a \nmaterial adverse effect on Transmission System reliability.  The process by which \nTransmission Provider will make such a determination and which, if any, of the \nrequirements of this Section 37A are to be applied shall be as set forth in the \nBusiness Practices Manual for Large Load."},{"page":34,"startToken":8018,"endToken":8237,"text":"MISO\n37A.1\nFERC Electric Tariff\nLarge Load Information and Basic Facility Data Requirements\nMODULES\n31.0.0\nEffective On: December 4, 2026\nLarge Load Information and Basic Facility Data Requirements\nA Transmission Customer taking Transmission Service on behalf of a Large Load shall \nbe responsible for providing the Transmission Provider with basic information, one-line \ndiagrams, and a description of the electrical characteristics of the Large Load for all Large Load \nEquipment, in the format and consistent with the timelines specified in the Business Practice \nManual for Large Load.  Any changes to the characteristics of a Large Load and/or Large Load \nEquipment, including any changes to the modeling details for the Large Load, shall be provided \nto the Transmission Provider in a timely manner, consistent with the Business Practices Manual \nfor Large Load. Such changes may include, but are not limited to, Load MW amounts, firm and \nnon-firm MW amounts, any dispatchable Load MWs, power factor, metering, telemetry, breaker \nconfiguration, staged Load additions and annual energy as further set forth in the Business \nPractices Manual for Large Load. \nA Transmission Customer taking Transmission Service on behalf of a Large Load must \ncoordinate with the Transmission Owner where the Large Load Point(s) of Withdrawal is located \npursuant to the Transmission Provider’s load interconnection guidance and applicable NERC \nstandards."},{"page":35,"startToken":8237,"endToken":8463,"text":"MISO\n37A.2\nFERC Electric Tariff\nLarge Load Modeling Requirements\nMODULES\n31.0.0\nEffective On: December 4, 2026\nLarge Load Modeling Requirements \nA Transmission Customer taking Transmission Service on behalf of a Large Load shall \nprovide the Transmission Provider with verified and complete electrical models of the Large \nLoad, as well as detailed Load profiles, for modeled Loads, in the format and consistent with the \ntimelines specified in the Business Practice Manual for Transmission Planning.  Such model \ninformation must include sufficient detail for the Transmission Provider to evaluate system \nperformance under contingency conditions in accordance with currently active versions of \nTransmission System Planning Performance Standards.\nFollowing completion of applicable studies and prior to the Service Commencement Date \nof the Large Load, the Transmission Customer shall submit final verified models to the \nTransmission Provider in accordance with the Business Practices Manual for Large Load.  The \nTransmission Customer shall provide notice to the Transmission Provider of any material \nmodifications to the Large Load and shall not implement any such proposed modifications until \nstudied and approved by the Transmission Provider in accordance with the Business Practices \nManual for Large Load.\nThe final models of a Large Load shall reflect the as-built configuration and actual \noperating characteristics of the Large Load and Large Load Equipment.  The Transmission \nCustomer shall maintain and update models as required by the Transmission Provider."},{"page":36,"startToken":8463,"endToken":8658,"text":"MISO\n37A.3\nFERC Electric Tariff\nLarge Load Telemetry Requirements\nMODULES\n31.0.0\nEffective On: December 4, 2026\nLarge Load Telemetry Requirements\nPrior to the later of the Service Commencement Date of a Large Load or September 1, \n2027, a Transmission Customer taking Transmission Service on behalf of a Large Load must \nprovide real-time telemetry for the Large Load, either directly, through the applicable \nTransmission Owner, or other Transmission Provider-approved communication path, in the form \nand manner as set forth in the Business Practices Manual for Large Load. \nIndividual metering will be required for all Large Load and any Generation Resource(s) \nserving such Large Load that is located behind the same Point(s) of Withdrawal to the \nTransmission System as the Large Load and meeting thresholds outlined in the Business \nPractices Manual for Large Load.  All telemetry shall be provided via Inter-Control Center \nCommunications Protocol (ICCP) and must meet Transmission Provider update requirements as \nspecified in the Business Practices Manual for Large Load.  The Transmission Customer must \nuse commercially reasonable efforts to maintain telemetry availability and accuracy for the Large \nLoad and must promptly correct erroneous data, bad mappings, and ICCP modeling issues."},{"page":37,"startToken":8658,"endToken":8775,"text":"MISO\n37A.4\nFERC Electric Tariff\nLarge Load Forecast Data Requirements\nMODULES\n31.0.0\nEffective On: December 4, 2026\nLarge Load Forecast Data Requirements\nPrior to the later of the Service Commencement Date of a Large Load or September 1, \n2027, a Transmission Customer taking Transmission Service on behalf of a Large Load must \nprovide day(s) ahead and real-time Load Forecasts for a Large Load directly to the Transmission \nProvider to support the Reliability Assessment Commitment (RAC) and Security Constrained \nEconomic Dispatch (SCED) processes, along with other reliability studies.  The Load Forecasts \nshall be updated to reflect the most current information on the expected Demand, in accordance \nwith the Business Practices Manual for Large Load."},{"page":38,"startToken":8775,"endToken":9006,"text":"MISO\n37A.5\nFERC Electric Tariff\nLarge Load Phasor Measurement Unit Requirements\nMODULES\n31.0.0\nEffective On: December 4, 2026\nLarge Load Phasor Measurement Unit Requirements\nThe Transmission Customer taking Transmission Service on behalf of a Computational \nLoad shall be subject to the Phasor Measurement Unit (PMU) requirements set forth in this \nSection 37A.5.  Prior to the later of the Service Commencement Date of a Large Load or \nSeptember 1, 2027, phasor measurement recording and communications equipment must be \ninstalled by the Transmission Owner, at the Transmission Customer’s expense, that is capable, at \na minimum, of gathering phasor measurements as specified in Business Practices Manual for \nLarge Load.  The phasor measurement equipment must be installed at the Transmission Owner’s \nside of the Point(s) of Withdrawal and become part of the Transmission Owner interconnection \nfacilities.  To the extent similar quality equipment is being added or already exists, such as relays \nor digital fault recorders, that can collect data at least at the same rate as PMU and which data is \nsynchronized via a high-accuracy satellite clock, such equipment may be utilized to satisfy this \nrequirement if the equipment is located on the Transmission Owner’s side of the Point(s) of \nWithdrawal.  Phasor measurements must be streamed in the format specified in the Business \nPractices Manual for Large Load and be provided to the Transmission Provider by the \nTransmission Owner."},{"page":39,"startToken":9006,"endToken":9114,"text":"MISO\n37A.6\nFERC Electric Tariff\nLarge Load Ride-Through Requirements\nMODULES\n31.0.0\nEffective On: December 4, 2026\nLarge Load Ride-Through Requirements\nA Transmission Customer taking Transmission Service on behalf of a Computational \nLoad shall be responsible for ensuring that the Computational Load remains connected to the \nTransmission System and continue operation during voltage and frequency disturbances within \nthe performance criteria established by the Transmission Provider in the Business Practices \nManual for Large Load.\nRide-through requirements apply at the Point(s) of Withdrawal and may include \nevaluation, testing, modeling, monitoring, and other compliance measures established by the \nTransmission Provider in the Business Practices Manual for Large Load."},{"page":40,"startToken":9114,"endToken":9272,"text":"MISO\n37A.7\nFERC Electric Tariff\nLarge Load Ramp Requirements\nMODULES\n31.0.0\nEffective On: December 4, 2026\nLarge Load Ramp Requirements\nA Transmission Customer taking Transmission Service on behalf of a Computational \nLoad shall be subject to the ramp requirements set forth in this Section 37A.7.  Ramp limits shall \nbe measured in aggregate across the applicable Point(s) of Withdrawal during stable-state \ntransition, including any reduction/ramp smoothing provided by generation or other resources \nthat meets the eligibility requirements specified in the Business Practices Manual for Large \nLoad.  Computational Load shall be subject to up-ramp and down-ramp limits established by the \nTransmission Provider consistent with the process set forth in the Business Practices Manual for \nLarge Load.  The Computational Load must have an effective up and down ramp rate not \nexceeding the specified limit outlined in the Business Practices Manual for Large Load unless \notherwise directed by the Balancing Authority, Reliability Coordinator, or Transmission \nOperator."},{"page":41,"startToken":9272,"endToken":9414,"text":"MISO\n37A.8\nFERC Electric Tariff\nLarge Load Audit Rights\nMODULES\n31.0.0\nEffective On: December 4, 2026\nLarge Load Audit Rights\nThe Transmission Provider has the right to audit or verify the information provided by a \nTransmission Customer taking Transmission Service on behalf of a Large Load including, but \nnot limited to, information related to the registration, claimed capacity, operations, modeling, \ninverter settings, metering, settlements, Large Load Equipment, and/or any other information \nrelated to the participation of the Large Load under this Tariff.  The Transmission Customer shall \nmaintain individual Large Load data and information related to the registration, Load Forecasts, \noperations, modeling, metering, and/or settlements for five (5) Years.  The Transmission \nProvider shall maintain individual Large Load data and information it receives related to the \nregistration, Load Forecasts, operations, modeling, metering, and/or settlements for five (5) \nYears."}],"sections":[{"p":1,"at":0,"title":"Opening text","method":"opening text","endPage":30,"endAt":129,"startToken":0,"endToken":7023},{"p":30,"at":129,"title":"I. Applicability of Large Load Reliability Requirements","method":"printed heading","endPage":31,"endAt":895,"startToken":7023,"endToken":7433},{"p":31,"at":895,"title":"II. Transition Provisions","method":"printed heading","endPage":41,"endAt":984,"startToken":7433,"endToken":9414}]}