ER27-25-000 · 2026-10-23 · Sierra Club, NRDC and other clean energy and community groups

Protest of Clean Energy Advocates and Community Organizations

1 
UNITED STATES OF AMERICA 
BEFORE THE 
FEDERAL ENERGY REGULATORY COMMISSION 
 
Midcontinent Independent 
System Operator, Inc. 
 
) 
) 
) 
Docket No. ER27-25-000 
 
PROTEST OF CLEAN ENERGY ADVOCATES AND COMMUNITY 
ORGANIZATIONS 
Pursuant to Rule 211 of the Rules of Practice and Procedure of the Federal Energy 
Regulatory Commission (“FERC” or “Commission”)1, Clean Energy Advocates2  and 
Community Organizations3 respectfully submit this protest in response to the October 2, 2026 
filing of the Midcontinent Independent System Operator, Inc. (“MISO”) in the above-captioned 
docket, which proposes revisions to MISO’s Open Access Transmission, Energy and Operating 
Reserve Markets Tariff (“Tariff”) to establish a Large Load Addition Resource Study (“LARS”) 
process.4 For the reasons explained below, the Commission should reject the LARS proposal. 
 
 
 
1 18 C.F.R. § 385.211. 
2 Clean Energy Advocates are Sierra Club, Natural Resources Defense Council, and Sustainable 
FERC Project, Clean Grid Alliance, Clean Wisconsin, and Fresh Energy. 
3 Community Organizations are Community Collaboration on Climate Change and Michigan 
Environmental Justice Coalition. 
4 Midcontinent Indep. Sys. Operator, Inc., Large Load Addition Resource Study Process, Docket 
No. ER27-25-000 (Oct. 2, 2026), Accession No. 20261002-5074 (“LARS Filing”). Citations to 
the “Transmittal Letter” are to the transmittal letter accompanying the LARS Filing. Citations to 
the “Drake Testimony” are to the Prepared Direct Testimony of Christina Drake, Director, 
Generation Interconnection, MISO, submitted as Tab C to the LARS Filing.

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TABLE OF CONTENTS 
I. 
Introduction ............................................................................................................................ 3 
II. 
Background ............................................................................................................................ 3 
A. 
Large Load Growth and Interconnection .......................................................................... 3 
B. 
The Show Cause Order ...................................................................................................... 4 
1. Study procedures for large loads ........................................................................................ 5 
2. Cost shifting ........................................................................................................................ 6 
3. Generation serving electrically proximate load .................................................................. 6 
C. 
The LARS Proposal ........................................................................................................... 7 
D. 
The Stakeholder Process ................................................................................................. 12 
III. Arguments ............................................................................................................................ 13 
A. 
LARS creates a cost shift from large loads and their generation to other customers ...... 13 
1. LARS assigns upgrade costs to the pricing zone .............................................................. 14 
2. LARS shifts costs to interconnection customers in the DPP ............................................ 18 
3. Generation-load pair failures shift costs to other ratepayers ............................................ 21 
B. 
LARS violates open access principles and enables undue discrimination ...................... 22 
1. MISO’s LARS proposal is unduly discriminatory ........................................................... 23 
C. 
LARS is an unjustified departure from the Commission’s pro forma interconnection 
procedures and does not accomplish the purposes of Order No. 2023 ........................... 33 
D. 
MISO’s LARS proposal is not responsive to Commission direction regarding 
“electrically proximate” generation and load from the Show Cause Order .................... 37 
E. 
LARS threatens reliability and efficient planning ........................................................... 39 
1. Parallel independent studies produce unreliable results and reliability risks ................... 40 
2. Siloed, expedited processes are already driving MISO’s largest transmission investments 
outside regional planning .................................................................................................. 41 
3. Integrated planning processes are available and MISO should adopt them ..................... 43 
IV. Conclusion ........................................................................................................................... 45

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I. 
Introduction 
As the Commission has recognized, integrated planning processes can help ensure that 
generation and transmission can be arranged to supply nearby large customers reliably, at lower 
cost, and with faster engineering study processes, ultimately resulting in more just and 
reasonable rates without harming other existing or future customers or suppliers. Better load and 
generation interconnection processes are clearly needed. MISO’s LARS proposal does not 
achieve that end, nor does it improve other interconnection processes. Instead of improving the 
coordination of generation and transmission planning, MISO’s LARS proposal is a new, 
permanent parallel interconnection study process that will shift costs from large loads to other 
existing and future transmission customers and resource owners, create and worsen reliability 
concerns, and allow for unchecked and harmful anti-competitive discrimination. The 
Commission should reject LARS because it is not just and reasonable and is unduly 
discriminatory or, in the alternative, issue a deficiency letter requiring MISO to demonstrate how 
LARS can be made just and reasonable.  
II. 
Background 
A. Large Load Growth and Interconnection 
MISO estimates that annual load growth will be 1 to 3 percent per year from 2025 
through 2044.5 MISO integrates new generation and load through separate processes on different 
schedules.6 New generation enters either through MISO’s cluster-based Definitive Planning 
Phase (“DPP”) or its temporary, serialized Expedited Resource Addition Study (“ERAS”). The 
DPP operates on a 365-day timeline and ERAS operates quarterly. New load is accounted for 
 
5 Transmittal Letter at 2-4. 
6 Drake Testimony at 3–4.

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through the MISO Transmission Expansion Plan (“MTEP”) or the Expedited Project Review 
(“EPR”). Where MTEP operates on an 18-month cycle, EPR provides approval in roughly 90 
days. MISO acknowledges that “large loads have overtaken the EPR process.”7 The 89 EPR 
requests approved in MTEP26 accounted for roughly 54 percent of the approximately $14.7 
billion of transmission investment approved in that cycle.8 
A generator may be treated as an alternative to a transmission solution only once that 
generator has a signed interconnection agreement (“GIA”).9 This poses a timing problem. A 
large load whose transmission solution depends on a new generator cannot obtain MTEP 
approval until the generator has completed the DPP or ERAS interconnection queues. MISO 
describes this “timing problem” as the problem the LARS parallel study process is designed to 
solve.10 
B. The Show Cause Order 
On June 18, 2026, the Commission instituted a proceeding under section 206 of the 
Federal Power Act (“the Act” or “FPA”), preliminarily finding that MISO’s Tariff “appears to be 
unjust and unreasonable because it lacks provisions that address, with sufficient clarity and 
consistency, how MISO and/or the Transmission Owners will timely study . . . the provision of 
transmission service to Eligible Customers on behalf of large loads.”11 The Commission directed 
MISO to show cause why the Tariff remains just and reasonable without provisions addressing 
 
7 Id. at 26. 
8 MISO, MTEP26 Report Review, Planning Advisory Committee, at 4, 8 (Oct. 7, 2026), 
available at 
https://cdn.misoenergy.org/20261007%20PAC%20Item%2006%20MTEP26%20Report%20Rev
iew785938.pdf. 
9 Drake Testimony at 12. 
10 Id. at 3–4, 12. 
11 Midcontinent Indep. Sys. Operator, Inc., 195 FERC ¶ 61,212, at P 39 (June 24, 2026) (“Show 
Cause Order”).

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(a) application, study, and ongoing operational requirements for Eligible Customers serving large 
loads; (b) transparency concerning large-load-driven Network Upgrade costs and a pro forma 
cost recovery agreement “to mitigate the risk of cost shifting among transmission customers”; (c) 
co-location arrangements; (d) transmission services for co-located, behind-the-meter, and 
flexible large loads; and (e) “the rates, terms, and conditions of service applicable to 
interconnection customers serving electrically proximate large load or co-located load.”12 Three 
parts of the Show Cause Order bear directly on LARS: study procedures, cost shifting, and 
proximate loads. 
1. Study procedures for large loads 
The Commission found that the Tariff lacks “sufficiently clear and consistent provisions 
regarding the study process” for large loads, pointing to the “ad hoc study process” reflected in 
Transmission Owner study agreements “not reflected in MISO’s Tariff,” and identified the 
elements such provisions should contain. These include: 
(1) A definition of large load. 
(2) A rolling application process with non-refundable fees, escalating readiness 
requirements, and disclosure of duplicative requests. 
(3) Study procedures that account for large-load behavior and flexibility. 
(4) Evaluations of alternative transmission technologies “in all instances,” with a 
written demonstration whenever traditional Network Upgrades are selected 
instead. 
(5) A 60-to-90-day study deadline. 
(6) Ongoing operational requirements. 
 
12 Show Cause Order at P 33.

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(7) Pro forma transmission service agreement provisions.13 
2. Cost shifting 
The Commission found that the Tariff “appears to be unjust and unreasonable because it 
lacks adequate mechanisms to mitigate the risk of cost shifting among transmission customers,” 
and identified two remedies. First, public posting of the Network Upgrades needed to serve large 
loads and their costs.14 Second, a pro forma cost recovery agreement requiring the Eligible 
Customer to make “a minimum contribution toward the transmission owner’s transmission 
revenue requirement,” sized to the megawatts of service requested and secured by credit support, 
so that large-load-driven costs are not “paid by other transmission customers that neither caused 
the need for nor benefit commensurately from those Network Upgrades.”15 
3. Generation serving electrically proximate load 
The Commission defined an “electrically proximate large load” as one “sufficiently 
electrically close to the interconnection customer’s requested point of interconnection” that the 
combined impact of generator and load “will be effectively the same as if they were located at 
the same substation (e.g., large load that is located no more than two substations away from the 
generating facility),” and invited revisions “appropriately tailored to MISO’s transmission 
system.”16 It found that MISO’s Tariff is deficient because it lacks a study process or 
interconnection service that reflects “an interconnection customer’s commitment in an 
interconnection agreement to limit the generating facility’s output” while serving such a load.17 
 
13 Id. at PP 39, 48–50, 57–65. 
14 Id. at PP 71–77. 
15 Id. at P 82. 
16 Id. at P 112. 
17 Id. at P 113.

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Referencing SPP’s High Impact Large Load Generation Assessment (“HILLGA”) 
process, the Commission stated that such a generator’s interconnection service “should be of an 
interim nature until the interconnection customer obtains” Energy Resource Interconnection 
Service (“ERIS”) or Network Resource Interconnection Service (“NRIS”), and noted that 
MISO’s system “may warrant consideration of a more limited definition of electrically 
proximate.”18 The Commission directed that any responsive filing to the Show Cause Order 
address whether such generators would participate in MISO’s energy, ancillary services, and 
capacity markets, with what restrictions, and how they would be accredited.19 
The Commission “strongly encourage[d]” MISO to address these directives through 
filings under section 205, but specified that any such filing “should also explain which of the 
Commission’s above directives their filing addresses and how it resolves them.”20 
C. The LARS Proposal 
On October 2, 2026, MISO filed proposed revisions to Attachment X (the Generator 
Interconnection Procedures, or “GIP”), Appendices 1 and 6 to Attachment X, and Attachment FF 
to establish the Large Load Addition Resource Study, with a requested effective date of 
December 2, 2026 and a first study period in the first quarter of 2027.21 MISO described LARS 
as “expedited review of the addition of 200 MW or greater loads together with new generation 
resources that are electrically proximate to those loads,” conducted in a parallel study process 
lasting up to 120 days that builds on EPR and ERAS.22 Unlike ERAS, however, LARS “will be a 
permanent MISO study process.”23 
 
18 Id. at P 115. 
19 Id. at P 127. 
20 Id. at P 36. 
21 Transmittal Letter at 2, 53. 
22 Id. at 1–2. 
23 Id. at 11.

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LARS creates at least two major changes to how generation interconnection and 
transmission planning function in MISO. First, LARS creates an exception to the EPR 
requirement described above in which a generator can be considered an alternative transmission 
solution only after it has a GIA. Under MISO’s proposed process, a generator that has submitted 
a valid LARS application and holds a five-year or longer contract (e.g., Power Purchase 
Agreement or similar off-take agreement) with the large load “may be considered as an 
alternative transmission solution” in the load study even though it does not have a GIA.24 
Second, the proposed process creates a new, 120-day serial generator interconnection track 
outside of the DPP and ERAS, through which the paired generator receives NRIS under a new 
form of agreement called the Large Load Generator Interconnection Agreement (“LLGIA”).25 
MISO presents LARS as responsive to the Show Cause Order’s electrically proximate directive 
and resource adequacy concerns, and as independent of “[t]he cost shifting issues raised in the 
Commission’s Show Cause Order,” which “will be addressed in future filings.”26 
Four entities drive the LARS process. Only the entity that procures transmission service 
for a large load may initiate and submit a LARS Application.27 This entity is called a “LARS 
Associated Transmission Customer,” which MISO states is often a Load Serving Entity 
(“LSE”).28 MISO’s proposal does not set any criteria, timelines, or disclosure obligations on a 
LARS Associated Transmission Customer’s decision whether to sponsor a particular generator 
and load. A generator-load pair, however, has no path into LARS without such sponsorship.29 
 
24 Id. at 48. 
25 Transmittal Letter at 11; Drake Testimony at 12–13. 
26 Drake Testimony at 39–41. 
27 Transmittal Letter at 6. 
28 Id. 
29 Id. at 6–8. MISO retained this structure over stakeholder objections, citing “mixed feedback.” 
MISO Large Load Working Group, MISO Response to Feedback, at 7 (Sept. 28, 2026), 
available at

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Second, the Interconnection Customer develops a generating facility, demonstrates that it will 
provide energy to the LARS Associated Load, and signs the LLGIA.30 Third, the Transmission 
Owner coordinates with the Interconnection Customer to identify a “definitive Point of 
Interconnection,” supplies the initial transmission solutions that are evaluated in the load study, 
and constructs the necessary Network Upgrades.31 Finally, the “LARS Associated Load” is 
defined as a single load of at least 200 MW at one Point of Withdrawal.32 
 
A LARS Application must include an executed agreement with a term of at least five 
years, “evidencing that the output of the Generating Facility . . . shall be used to provide energy 
to the LARS Associated Load.”33 The Interconnection Customer must request NRIS of at least 
200 MW and no more than 150 percent of the LARS Associated Load’s expected peak demand, 
demonstrate 100 percent site control, and pay an application fee of $250,000 and an entry 
milestone of $30,000 per MW.34 Aside from the 150 percent cap, nothing requires the paired 
generation to be sized to any particular share of the load’s demand. Nor do the eligibility criteria 
require any demonstration of a reliability or resource adequacy need. The Point of 
Interconnection must be in the same Local Resource Zone (“LRZ”) as the load’s Point of 
Withdrawal.35 A LARS Associated Load may be served by more than one Interconnection 
Customer, though MISO will accept only ten LARS Applications total per study period.36 The 
generator’s commercial operation date and the load’s full in-service date must fall within three 
 
https://cdn.misoenergy.org/LLWG%20Large%20Load%20Addition%20Resource%20Study%20
Response%20(LLWG-2026-6)%20(20260827)784877.pdf. 
30 Transmittal Letter at 6. 
31 Id. at 6–8. 
32 Id. at 7. 
33 Id. at 27. 
34 Id. at 7, 10, 25. 
35 Id. at 10. 
36 Id. at 9, 11.

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years of the application, subject to a further three-year extension under the LLGIA.37 MISO 
acknowledges that it “does not have a requirement that loads bring generation,” and characterizes 
LARS as “an incentive for Load to bring Generation.”38 
MISO will accept applications on a rolling, “serial ‘first-come, first-served’” basis and 
study up to ten generation/load pairs in each of the three study periods per year.39 On the 
generation side, each generator is studied “individually in a serial fashion” in its own model.40 
The LARS base model includes existing generators, generators with executed GIAs, and 
approved MTEP and EPR projects, but excludes DPP projects without an executed GIA.41 On 
the load side, the study is “built upon MISO’s existing EPR process.”42 All ten load-generation 
pairs are represented together in a single MTEP-based model, the Transmission Owners’ initial 
solutions are evaluated, and MISO establishes a planning-level solution.43 Although the load-
generation pair must be located in the same LRZ, “MISO will look at the full impacts of the 
generation/load pair on MISO’s Transmission System using the same study criteria and 
processes applicable to NRIS evaluations of other Interconnection Requests.”44 If there is an 
overallocation because transmission capacity is ultimately found to have been allocated to both a 
LARS generator and a DPP generator, the resulting constraint “will be formalized in a future 
MTEP project,”45 “neither will be required to pay additional costs,”46 and the MTEP project’s 
 
37 Drake Testimony at 10. 
38 Transmittal Letter at 10. 
39 Drake Testimony at 13, 22. 
40 Transmittal Letter at 32. 
41 Id. at 12. 
42 Id. at 13–14. 
43 Id. at 13–14. 
44 Id. at 13. 
45 Id. 
46 Drake Testimony at 33.

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cost “will be allocated based on existing Tariff rules, which is likely to be the load within the 
transmission pricing zone where the transmission upgrade is required.”47  
With respect to cost allocation, MISO allocates mitigations to the Baseline Reliability 
Project (“BRP”) or “Other” project types except for mitigation violations observed in the 
generation study, which are assigned to the Interconnection Customer as Generator 
Interconnection Project (“GIP”) upgrades.48 BRP and Other upgrades are constructed by the 
Transmission Owner and the costs are recovered through transmission rates under the existing 
provisions of Attachment FF rather than funded by the Interconnection Customer. According to 
MISO, these costs will most likely be allocated to “the load within the transmission pricing zone 
where the transmission upgrade is required.”49 
LARS generators receive full NRIS, allowing them to “qualify as a Network Resource for 
capacity and resource adequacy needs” and to “participate in the Planning Reserve Auction.”50 
The LLGIA does not require output to be tied to the load except insofar as the generator cannot 
inject until some portion of the load is in service.51 Once the load is fully in service, the LLGIA 
does not limit the generator’s output in any way.52 While the generator’s output is not limited by 
its paired load, the generator and load must remain contractually paired for at least fifteen years 
after the load begins taking service.53 MISO justifies the fifteen-year term as “a standard duration 
for large load contracts” and as sufficient “to deter entities from invoking the needs of a specific 
 
47 Transmittal Letter at 13. 
48 Id. at 31–32. 
49 Id. at 13. 
50 Drake Testimony at 12–13. 
51 Id. at 26–30. 
52 Id. at 18. 
53 Transmittal Letter at 15–17.

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large load as a pretext to bypass the DPP queue and receive unrestricted Interconnection Service 
on an accelerated timeline.”54 
D. The Stakeholder Process 
MISO developed LARS in eleven weeks. It first presented the concept to its Large Load 
Working Group (“LLWG”) on July 16, 2026.55 After presenting revisions at different meetings, 
MISO presented final language on September 23 and filed on October 2.56 
Stakeholders raised, and MISO declined to address, several of the concerns presented in 
this protest. The Environmental Sector objected to the Transmission Customer’s gatekeeping 
role, to the LRZ-wide scope of the pairing requirement, and to LARS’s failure to meet the Show 
Cause Order’s electrically proximate standard, and asked that generators and loads be jointly 
liable for upgrade costs if a pairing ends early. Energy Futures Group presented the Generator 
and Load Interconnection Process (“GALIP”), which would study large loads and their 
generation together within the DPP, with full cost-causation-based allocation of upgrade costs 
and both firm and non-firm service options for load.57 MISO declined to pursue GALIP, stating 
that it “does not believe in a ‘one size fits all’ approach to interconnection” and that GALIP 
“aimed to shoehorn a parallel generation/load study process into the existing DPP process.”58 
 
54 Id. at 17. 
55 Drake Testimony at 41. 
56 Id. at 41–43. 
57 Energy Futures Group, Generator and Load Interconnection Process (GALIP) (Aug. 27, 2026), 
available at 
https://cdn.misoenergy.org/20260827%20LLWG%20Item%2013%20Generator%20Load%20Int
erconnection%20Process%20(GALIP)%20Proposal_Energy%20Futures%20Group777224.pdf. 
58 Drake Testimony at 43–44.

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III. 
Arguments 
A. LARS creates a cost shift from large loads and their generation to other 
customers 
It is a long-standing principle of Commission ratemaking that “all approved rates reflect 
to some degree the costs actually caused by the customer who must pay them,” and that 
compliance is measured “by comparing the costs assessed against a party to the burdens imposed 
or benefits drawn by that party.”59 In the Show Cause Order, the Commission preliminarily 
found that MISO’s Tariff violates that principle because it “lacks adequate mechanisms to 
mitigate the risk of cost shifting among transmission customers” when large loads drive network 
upgrades.60 LARS does not supply those mechanisms. By MISO’s own account, LARS adopts 
no cost allocation methodology, and “[t]he cost shifting issues raised in the Commission’s Show 
Cause Order will be addressed in future filings.”61  
Instead, LARS builds cost shifting into the process in four ways. First, it assigns the 
network upgrades that a generator-load pair requires to the transmission pricing zone rather than 
to the pair. Second, it studies LARS generators in models that exclude the DPP queue, and 
resolves the resulting double-allocation of transmission capacity through MTEP projects paid for 
by zonal load and through curtailment of DPP generators that paid for their own upgrades. Third, 
it allows either half of a pair to leave the system after fifteen years and the generator to fail at any 
time, leaving zonal load to pay for whatever transmission must then be built. Fourth, it defers the 
cost recovery agreement, financial security, and transparency measures the Commission 
identified as necessary. The Commission should reject LARS or, at a minimum, decline to make 
 
59 Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1368 (D.C. Cir. 2004) (quoting 
KN Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992)); Ill. Commerce Comm’n v. 
FERC, 576 F.3d 470, 476 (7th Cir. 2009). 
60 Show Cause Order at P 66. 
61 Drake Testimony at 41.

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it effective until the cost provisions MISO has promised are filed, accepted if consistent with the 
Order to Show Cause principles, and incorporated into the LARS Tariff provisions. 
1. LARS assigns upgrade costs to the pricing zone 
As explained above, LARS sorts network upgrades identified in its load and generation 
studies into three categories: violations in only the load study, violations in only the generation 
study, and violations in both studies. Violations that occur only in the load study or in both the 
load and generation studies are assigned the BRP or Other project types and their costs are 
allocated to all loads in the Transmission Owner’s pricing zone. Only when a violation occurs in 
the generation study alone will MISO assign the costs of the mitigations to the Interconnection 
Customer as a GIP upgrade.62 MISO calls this a “cost allocation hierarchy—transitioning from 
GIP to BRP when appropriate.”63 This hierarchy represents impermissible cost shifts.  
When the costs of mitigation are assigned to BRP or Other project types, those costs are 
allocated to the Transmission Owner in whose pricing zone the project is located. Those costs are 
then recovered through the Transmission Owner’s rates, paid for by every transmission customer 
in the zone. MISO explains that the costs will fall on “the load within the transmission pricing 
zone where the transmission upgrade is required.”64 In contrast, when the same generator 
interconnects through the DPP, the Interconnection Customer funds the Network Upgrades its 
interconnection requires. LARS, therefore, takes a category of costs usually assigned to 
generators and assigns them to existing load. It is not as though the beneficiaries are unknown or 
diffuse. Rather, the beneficiaries are simply the generator and the large load, for which the 
generator is the “alternative transmission solution.”65 MISO has failed to show how the LBA or 
 
62 Drake Testimony at 27–28. 
63 Transmittal Letter at 14. 
64 Id. at 13. 
65 Id. at 47-48.

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LRZ suddenly benefit from the needed upgrades simply because violations show up in the load 
and the generation studies. And in none of these situations is the cost assigned directly to the 
large load that is driving the need for the upgrades. This kind of cost shifting is exactly the sort 
of thing the Commission found unjust and unreasonable in the Show Cause Order. 
LARS is likely to shift the cumulative upgrades needed to support the transmission 
system, because of the serialized LARS study process. Each LARS generator is studied 
“individually in a serial fashion” in its own model.66 Unlike a DPP cluster study, which identifies 
the upgrades a group of generators needs together and allocates their costs among the cluster, the 
LARS generation study never captures the combined effect of the ten generators and loads in a 
study period, let alone of the thirty pairs that may enter LARS each year. In fact, constraints that 
emerge from the cumulative injection of LARS generators or cumulative impacts of LARS large 
loads are most likely to appear in a load study where all ten pairs are studied together. In that 
case, however, as explained above, those mitigations will be classified as BRP or Other. 
Otherwise, the problems will reveal themselves in a later MTEP study. Either way, costs will be 
allocated not to the load-generation pair, but to all load in the zone. 
The pricing zone that pays for upgrades caused by LARS projects may not even be the 
LBA in which the LARS Associated Load takes service. While load-generation pairs must be in 
the same LRZ, MISO studies “the full impacts of the generation/load pair on MISO’s 
Transmission system” without confining the study to that zone.67 A single LRZ can span 
multiple LBAs, Transmission Owner pricing zones, and states. Because MISO declined to limit 
the generation/load pairs to a single LBA or to a set number of substations, the result is that 
customers of one Transmission Owner, in one state, can be assigned the cost of upgrades 
 
66 Id. at 12, 31. 
67 Id. at 10–13.

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required because a data center in another state chose to contract with a generator sited near them. 
The state regulator responsible for protecting those customers has no jurisdiction over the load 
that caused the cost, and the retail large load tariffs states are adopting to protect their ratepayers 
cannot reach a load in another state.68 This is textbook cost shifting, which the Commission has 
recently noted as a concern in the large load context.69 
Transmission upgrade costs associated with LARS generation should not be assigned to 
load generally, because both the driver and the beneficiaries of the upgrade are a specific 
generator-load pair.70 The NRIS service for a LARS Interconnection Customer hinges on the 
consumption of the LARS associated load. MISO acknowledges this tight connection by 
terminating the LLGIA, and sending the generator back to the DPP for new interconnection 
service if the load leaves or shrinks within fifteen years.71 A generator whose interconnection 
service is contingent on one load’s consumption is not a system resource whose upgrades benefit 
the zone. 
MISO insists that the LARS Associated Transmission Customer “remains responsible for 
the identified BRPs and Other assigned projects even if such LARS Associated Load does not 
commence service.”72 Yet the Tariff contains no mechanism through which a Transmission 
Customer pays for the BRP or an Other project. A Transmission Customer’s only 
 
68 Cf. Show Cause Order at P 83 n.189 (cost recovery directive is “in no way intended to preempt 
or interfere with the ability of states to implement ratepayer protection measures designed to 
mitigate cost shifting among retail customers, such as through state-jurisdictional large load 
tariffs.”). Those measures presuppose that the ratepayers who bear the cost and the load that 
caused it are subject to the same regulator. 
69 See Show Cause Order at PP 66, 81–82. 
70 See Drake Testimony at 17 (describing the “contractual association, study association, and 
operational association” between the LARS Associated Generation and LARS Interconnection 
Customer). 
71 Transmittal Letter at 16. 
72 Id. at 35–36.

17 
“responsibility” for those costs is the one it already has to pay the Transmission Owner’s zonal 
rate in the same proportion as every other network customer in the zone. A Transmission 
Customer that “remains responsible” for a $200 million BRP after its load fails to materialize 
remains responsible for nothing more than its ordinary transmission bill. That is precisely the gap 
the Commission identified when it found that, “[a]bsent such cost recovery agreements, . . . there 
is no mechanism to help ensure that Eligible Customers taking transmission service on behalf of 
large loads (as opposed to other transmission customers) bear the risk of, and are ultimately 
responsible for, the costs incurred to provide them with the requested transmission service, 
including the costs of any needed Network Upgrades.”73 Rather than responding to the 
Commission’s call to fill this gap in cost recovery agreements, MISO merely states that the “cost 
shift is consistent with MISO’s existing processes.”74 Yet it is these existing processes that the 
Commission preliminarily found unjust and unreasonable because they lack “adequate 
mechanisms to mitigate the risk of cost shifting among transmission customers.”75 
MISO states that “a pro forma cost shifting agreement will need to be executed and new 
terms in transmission services agreements will need to be met,” that it will file those terms by 
November 16, and that “LARS can be implemented based on the Tariff revisions filed herein and 
need not await these future filings.”76 But nothing in the proposed Tariff requires a LARS 
Associated Transmission Customer to execute any such agreement, post any security for the BRP 
and Other upgrades assigned to the zone, or take any defined transmission service. The only 
party that posts security in LARS is the generator, and only for the GIP upgrades that LARS 
 
73 Show Cause Order at P 81. 
74 Transmittal Letter at 13. 
75 Show Cause Order at P 66. 
76 Transmittal Letter at 14 & n.66.

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defines as the residual.77 The Commission’s statutory deadline to act on LARS will arrive before 
comments on the November 16 filings are due. A process that assigns upgrade costs to zonal 
load now, on the strength of an agreement whose terms are not before the Commission, has not 
been shown to be just and reasonable. 
2. LARS shifts costs to interconnection customers in the DPP 
LARS shifts costs to interconnection customers in the DPP, to the disadvantage of 
generators in the DPP compared to those related to LARS projects. In the DPP, MISO models 
the system headroom by assuming that all higher-queued generating facilities will enter 
operation.78 By contrast, in LARS, MISO proposes to model only DPP projects with a signed 
GIA.79 These differing approaches risk MISO allocating transmission headroom twice.80 Rather 
than reconcile the double-allocation, MISO proposes that “[b]oth [projects] will be allowed to 
proceed, and neither will be required to pay additional costs due to the overallocation.”81 Failing 
to coordinate DPP and LARS shifts costs onto DPP customers. 
LARS generators are studied as though the DPP queue does not exist. They are assigned 
none of the upgrades that their injections require in combination with the queued projects ahead 
of them. Those upgrades are left to the DPP customers, who are assigned them on the assumption 
that the headroom in their models would still exist when they reach commercial operation. When 
LARS and DPP generators both come online and the system cannot deliver to both, the result is a 
reliability gap. This leads to unplanned curtailments and degraded operating conditions, which 
will result in instances where the DPP customer would have been able to export energy and 
 
77 See Proposed GIP §§ 3.3.1, 3.12.2, 3.12.4; Proposed Attachment FF § I.D.1.b.ii; Transmittal 
Letter at 10, 25. 
78 Transmittal Letter at 12. 
79 Id. at 12–13. 
80 Drake Testimony at 32–33. 
81 Id. at 32–33.

19 
receive market payments, but for the LARS customer causing unmitigated congestion. While 
interconnection customers do not have a right to any particular system topology, a decrease in 
available headroom and degraded operating conditions represent cost shifts to generators in the 
DPP, because that same headroom is instead being allocated to LARS projects. 
In the long term, MISO proposes that the constraints caused by the double-allocation of 
headroom will be “formalized in a future MTEP project”82 whose cost falls on “the load within 
the transmission pricing zone.”83 Reliance on future MTEP projects, however, is both 
insufficient and too late. MISO’s reliance on later MTEP cycles will not cure the reliability gap 
caused by the double-allocation.84 LARS projects, not having been studied with the advanced 
Phase 3 DPP interconnection projects reaching commercial operation in the same time frame, 
may cause costly reliability upgrades in that future MTEP cycle, yet those costs will now become 
shifted to other transmission customers and market participants.85 While this presents its own set 
of cost-shifting concerns, it also does not address the fact that these further upgrades identified in 
later MTEP cycles might take years to construct. During this time, the LARS generator would 
not face operating restrictions, while a DPP project operating before its Network Upgrades are 
complete is subject to Quarterly Operating Limits and Annual ERIS/NRIS limits.86  
 
82 Id. at 33. 
83 Transmittal Letter at 13. 
84 See Affidavit of Warren Hess ¶¶ 2–3, attached to Protest of Clean Energy Organizations, 
Docket No. ER25-1674-000 (Apr. 7, 2025), Accession No. 20250407-5242 (explaining that 
excluding late-stage DPP projects from an expedited interconnection study produces reliability 
gaps, and that resolving the resulting overallocation of transmission headroom through the 
annual MTEP process does not cure them because of the limited scope of NRIS studies). 
85 Because LARS projects are studied without the DPP queue, the costs a LARS pair would bear 
if its full impacts were known are understated, and the balance is assigned to zonal load through 
later MTEP projects. 
86 See GIP § 11.6 (Quarterly Operating Limit studies for Interconnection Customers operating 
before their Network Upgrades are complete); Proposed LLGIA art. 9.7.4.7 (operating limits on 
a LARS Generating Facility apply only while the LARS Associated Load phases in); Transmittal

20 
MISO’s only justification for excluding the DPP queue from LARS models is “to reduce 
the number of speculative projects in the modeling process.”87 MISO, however, concedes that 
project withdrawal rates fall sharply as projects advance through the DPP, so that by the GIA 
stage they are “more closely aligned with the MTEP withdrawal rate.”88 MISO’s own consultant 
has found that, of the capacity that withdrew from the 2017–2020 DPP cycles, only about 11 
percent withdrew at Phase 3 or later.89 Nor are large loads somehow immune from withdrawals 
from the EPR process.90 Yet LARS includes EPR projects in its base model and includes the 
LARS Associated Load on the strength of a five-year contract and $250,000 fee, while excluding 
DPP generators that have posted milestone payments, completed two phases of study, and been 
assigned Network Upgrade costs. MISO also never explains why speed in LARS is so critical 
that it justifies this result. When MISO sought comparable modeling shortcuts for ERAS, it 
justified them by reference to specific resource adequacy and reliability needs verified by the 
Relevant Electric Retail Regulatory Authority (“RERRA”). It also limited the process by capping 
ERAS at 68 projects and sunsetting the whole program by the end of 2027. LARS is permanent, 
uncapped, and requires no showing of need at all. 
The same problem can arise on the load side. LARS loads are studied in their own model, 
in parallel with the EPR and MTEP studies of other large loads, and the filing does not say 
 
Letter at 17 (QOL and AERIS limits apply to a LARS Generating Facility only during the 
transition period after its load departs). 
87 Transmittal Letter at 12. 
88 Drake Testimony at 33. 
89 Charles River Associates, MISO Interconnection Queue: M2, M3 and M4 Security Deposits 
and Return Procedures – Evaluation and Suggested Adjustments, 8 (Aug. 26, 2023), available at 
https://cdn.misoenergy.org/20230719%20PAC%20Item%2006%20Charles%20River%20Associ
ates%20Queue%20Reform%20Report629633.pdf.  
90 MISO, EPR Statistics Update, EPR-TSTF (Sept. 8, 2026) (listing withdrawn EPR requests), 
available at https://cdn.misoenergy.org/20261006%20EPR-
TSTF%20Item%2003%20MISO%20EPR%20Statistics785900.pdf.

21 
whether a LARS load will be reflected in concurrent EPR studies or vice versa. MISO’s own 
witness confirms that the LARS load study is interim. The Large Load Project Review process is 
“currently under development,” and MISO is drafting it “such that the load study portion can be 
easily inserted into LARS at a later point in time.” Until then, two large loads studied in parallel 
models can be allocated the same transmission capacity. As on the generation side, MISO will 
rely on MTEP to reconcile these conflicts, resulting in BRP or Other projects paid for by the 
zone. 
3. Generation-load pair failures shift costs to other ratepayers 
Like conflicts between the DPP and LARS processes, generation-load pair failures shift 
costs to other ratepayers. The premise of LARS is that studying the generator and the load 
together leads to fewer upgrades than either would need alone. The generator is treated as an 
alternative transmission solution for the load and the load’s withdrawals are the reason the grid 
can accommodate the generator’s injections.91 However, when that pairing fails, LARS places 
the resulting costs on neither party. If the generator fails to reach commercial operation or retires, 
MISO will rely on MTEP to approve a BRP or Other project at the zone’s expense. If the load 
departs within fifteen years, the generator may continue operating for a year, extended by a full 
DPP cycle, and may then obtain unconditional NRIS through the DPP.92 After fifteen years, the 
generator keeps full NRIS of up to 150 percent of the departed load’s peak demand with no 
further study and no cost at all.93 In each case, the transmission needed to accommodate an 
unpaired injection of that size was never studied and never assigned, and the Tariff leaves it to be 
formalized through MTEP and paid for by zonal load. 
 
91 Drake Testimony at 4. 
92 Transmittal Letter at 16–18. 
93 Id. at 16–18.

22 
This is not the ordinary risk that any generator may someday retire. A retirement removes 
injections from the system and is reviewed through Attachment Y. LARS creates a standing 
injection that was studied only on the assumption of a matched withdrawal, which the Tariff then 
allows to persist after the withdrawal is gone. Up until the fifteenth year, a generator whose 
paired load departs “would need to obtain new Interconnection Service through the DPP to 
continue making injections,” because MISO recognizes that the generator’s service was premised 
on the load.94 Nothing about that premise changes in year fifteen. MISO defends the cutoff as “a 
standard duration for large load contracts” and as long enough “to deter entities from invoking 
the needs of a specific large load as a pretext to bypass the DPP queue.”95 But a deterrent to 
pretext is not a reason to relieve a generator of the costs its unpaired injections impose. The 
customers who will bear those costs in year sixteen are the same customers the Show Cause 
Order is meant to shield from paying the costs of data centers. 
B. LARS violates open access principles and enables undue discrimination 
LARS sets up a generation and load study process that would offer a limited number of 
projects preferential access to the transmission system each year, year after year. It does so in a 
way untethered to any purported system need (that only LARS can address), while allowing self-
interested and often vertically integrated utilities to determine which projects can access the 
process without any mechanism for public, regulatory, or even MISO oversight. The result is a 
never-ending process that would permanently and flagrantly violate longstanding open access 
principles and the FPA’s prohibition against undue discrimination with each LARS cycle. The 
Commission accordingly should reject the proposal.  
 
94 Id. at 16. 
95 Id. at 17.

23 
1. MISO’s LARS proposal is unduly discriminatory 
Under the FPA, a rate design must be non-discriminatory and non-preferential as well as 
being just and reasonable.96 As the D.C. Circuit has observed, the Act “bristles with concern for 
undue discrimination.”97 The Commission and courts have consistently found that 
“[d]iscrimination is undue when there is a difference in rates or services among similarly situated 
[entities] that is not justified by some legitimate factor.”98 Different treatment is only justified if 
the record “evidence show[s] factual differences to justify” it.99 
As Commissioner See has previously explained, when a “proposal’s goal is to get some 
interconnection requests through the study process faster than others, the Commission is by 
definition asked to greenlight discrimination.”100 Here, LARS sets up a generation and load study 
process that will offer an unlimited number of generation projects and loads preferential access 
to the transmission system. LARS generators also obtain the additional significant benefit of 
access to MISO’s Planning Resource Auction (“PRA”). LARS accomplishes this in a way that is 
unrelated to any technical or operational limitation or purported system need, and allows self-
interested vertically integrated utilities the ability to determine which projects can access the 
process without any mechanism for Commission, or even MISO, oversight. The result is a study 
process that violates the FPA’s prohibition against undue discrimination, and its longstanding 
 
96 See 16 U.S.C. § 824d(a)–(b); see also Ala. Elec. Co-op., Inc. v. FERC, 684 F.2d 20, 27 (D.C. 
Cir. 1982). 
97 Associated Gas Distribs. v. FERC, 824 F.2d 981, 998 (D.C. Cir. 1987). 
98 El Paso Natural Gas Co., 104 FERC ¶ 61,045, at P 115 (2003) (footnote omitted); State Corp. 
Comm’n v. FERC, 876 F.3d 332, 335 (D.C. Cir. 2017) (undue discrimination occurs only if the 
entities are “similarly situated”); see also Ark. Elec. Energy Consumers v. FERC, 290 F.3d 362, 
367 (D.C. Cir. 2002); Consol. Edison Co. of N.Y., Inc. v. FERC, 45 F.4th 265, 281 (D.C. Cir. 
2022). 
99 Elec. Consumers Res. Council v. FERC, 747 F.2d 1511, 1516 (D.C. Cir. 1984). 
100 Midcontinent Indep. Sys. Operator, Inc., 191 FERC ¶ 61,131 (2025) (See, Comm’r, 
concurring at P 2).

24 
open access principles. Specifically, the proposal runs afoul of the Commission’s prohibition on 
undue discrimination by: 1) allowing one class of similarly situated entities expedited access to 
the MISO Planning Resource Auction; 2) allowing one class of load (load over 200 MW) 
expedited access to the transmission system; and 3) allowing LSEs the ability to favor their own 
resources over competitors in pairing them with large loads. The Commission should reject the 
proposal for any of these three independent reasons. 
a. The LARS framework unduly discriminates among similarly 
situated resources seeking to participate in MISO’s Planning 
Resource Auction 
MISO’s proposal is unduly discriminatory because it grants generators associated with 
qualifying large loads an accelerated pathway to obtain access to MISO’s Planning Resource 
Auction market that is unavailable to similarly situated generators participating in the ordinary 
DPP process. As noted in the LARS Tariff filing, “A LARS Generating Facility will have the 
ability to participate in the Planning Reserve Auction (“PRA”) and support resource 
adequacy.”101 This benefit flows from MISO’s choice to allow LARS generators to receive NRIS 
service. However, MISO justifies LARS as a large load-serving interconnection pathway, not as 
a general market-entry pathway. By allowing LARS generators unfettered NRIS interconnection 
rights, as opposed to a more limited interconnection framework, LARS is not a narrowly tailored 
mechanism to accelerate the integration of large loads onto the bulk power system; instead, it 
also creates a secondary, unrelated, and unnecessary substantial benefit to those resources by 
providing them a pathway for those generating resources to participate in MISO’s broader 
capacity construct. MISO provides no justification for providing access to LARS generators to 
 
101 Drake Testimony at 13 (note Ms. Drake mistakenly identifies the auction as the “Planning 
Reserve Auction,” when the proper naming convention is the “Planning Resource Auction”).

25 
the PRA via its allocated NRIS service. Nor could it, because as described below this benefit is 
unrelated to the regulatory purpose of MISO’s proposal. 
Despite repeatedly describing LARS as a strictly limited interconnection construct tied to 
service for a specific large load, MISO specifically grants LARS resources NRIS rights with its 
full suite of benefits. Providing such rights is untethered to the alleged regulatory purpose of 
LARS, and therefore inappropriate. Specifically, MISO states that “[t]he purpose of LARS is to 
create a fast and efficient process for viable, shovel ready projects.”102 More generally, MISO 
makes clear that this proposal is responsive to the Department of Energy’s Speed to Power 
initiative, by “providing a process through which significant new large loads and generation 
intended to support that load can be studied on an accelerated and coordinated basis.”103 As such, 
it is clear that the LARS program’s regulatory purpose is not to bolster system reliability in 
general, and therefore, MISO cannot rely on that purpose for providing the outsized, 
mismatched, and substantial benefit of full NRIS service rights. 
Moreover, because of the way in which the LARS large loads are contractually tied to the 
generators, it is entirely inconsistent and irrational to allow those same generators full PRA 
participation rights. If a LARS generator receives expedited interconnection treatment because it 
is paired with and is intended to “serve”104 a particular large load in a specific LRZ, permitting 
that same generator to also compete in the regional capacity market gives it the opportunity to 
essentially double-dip. This is particularly true for the types of large loads that MISO anticipates 
connecting, which have disproportionately high load factors and therefore should not have the 
excess capacity to bid into the PRA. 
 
102 Id. at 15. 
103 Transmittal Letter at 2. 
104 See id. at 9 (“The agreement must demonstrate that the output of the LARS Generating 
Facility will serve the LARS Associated Load.”).

26 
The LARS generator therefore receives the principal benefit sought by any generator 
(including those in the DPP queue): the ability to obtain deliverable interconnection rights and 
participate in MISO’s capacity construct. And it receives that substantial market benefit through 
an accelerated 120-day process unavailable to other generators. This preferential market access 
benefit, which is unrelated to the regulatory purpose of LARS, is further compounded by the fact 
that LARS generators will also have quicker access to additional revenue by virtue of their 
shorter interconnection timeline while also enjoying lower overall financing costs because such 
generators will need to maintain study deposits for shorter periods of time. 
MISO has not identified any reasonable justification for granting one class of resources 
expedited access to PRA participation. The sole differentiating factor is that LARS generators 
possess a contractual relationship with a qualifying large load, which generators in the ordinary 
queue do not possess. However, the existence of a commercial arrangement with a data center or 
other large customer does not alter the generator’s ability to contribute to regional resource 
adequacy, and if anything the likelihood of a LARS generator being able to provide that capacity 
is necessarily lower. Nor does it explain why such a resource should be allowed to receive the 
full benefits of NRIS service, including but not limited to access to the PRA, more quickly than 
competing generators intending to serve regional load generally. A generator paired with a data 
center through a private commercial arrangement is not materially different, from a resource 
adequacy perspective, from a generator developed by an independent power producer seeking to 
serve regional load generally. 
For example, MISO offers no reasonable justification for why “Generator A” may 
receive expedited NRIS and PRA eligibility through a 120-day LARS process because it signed a 
contract with a 200 MW data center, while “Generator B” seeking the identical interconnection

27 
product and identical PRA participation rights must proceed through the DPP because it does not 
have that same contractual relationship. Simply put, MISO offers no meaningful reliability 
distinction between the two generators sufficient to justify drastically different interconnection 
timelines and rights. Accordingly, MISO has failed to establish that generators seeking identical 
capacity-market participation rights are differently situated in a manner to justify the proposed 
discriminatory treatment. 
MISO has failed to demonstrate that this disparate treatment is supported by any 
corresponding reliability or operational distinction, rendering the proposal unduly discriminatory 
under section 205 of the Federal Power Act. 
b. The LARS framework unduly discriminates against load 
under 200 MW that is seeking to interconnect in MISO 
The LARS proposal is designed to provide “expedited review of the addition of 200 MW 
or greater loads together with new generation resources that are electrically proximate to those 
loads.”105 This framework is unduly preferential because “shovel ready” load that is under 200 
MW cannot take advantage of this expedited interconnection product. MISO provides no 
permissible justification for allowing only larger customers to skip the ordinary interconnection 
line. 
The FPA prohibits MISO from treating customers preferentially. MISO’s conduct here is 
textbook preferential treatment. There is nothing preventing a load under 200 MW from meeting 
each of the other eligibility requirements by: requesting interconnection service not greater than 
150 percent of its peak demand, being located in the same Local Resource Zone as its 
contracted-for generation, providing a $250,000 application fee, having a Point of 
Interconnection approved by the Transmission Owner, having full site control, meeting EMT 
 
105 Transmittal Letter at 1.

28 
modeling requirements, and specifying a commercial operation date not later than three years 
from its interconnection request.106 The only limiting criterion is the load size.107  
As noted above, the alleged “purpose of LARS is to create a fast and efficient process for 
viable, shovel ready projects.”108 MISO fails to identify any technical or operational limitation 
for loads under 200 MW—that otherwise meet the criteria above—that would prevent them from 
being just as “viable” and “shovel ready” as loads over 200 MW. 
MISO answers the question, “why is the LARS load size limited to at least 200 MW,” by 
stating that the threshold was chosen because loads of that size “would benefit from a 
coordinated study process and that data center loads in general come in 200 MW blocks.”109 
However, smaller loads (e.g., 100 MW loads or pooled loads of 200 MW and larger) could also 
benefit in the way MISO describes from a coordinated study process as well. MISO offers no 
operational or technical justification for the discriminatory 200 MW limit, nor can it. Other 
statements by MISO regarding the 200 MW threshold are circular and do not provide a 
reasonable justification: for example, MISO states that “limiting LARS load participants to at 
least 200 MW at one POW ensures that the load coming online is sufficiently large to warrant 
inclusion in LARS.”110 Absent a clear justification for this preferential treatment, it remains 
undue and therefore must be rejected. 
 
106 Drake Testimony at 21–22. 
107 Nor does MISO explain why smaller resources could not pool together to reach 200 MW, 
other than a conclusory statement that such pooling would slow down the study process. 
However, beyond this conclusory statement MISO does not support this restriction with any data 
or analysis. 
108 Drake Testimony at 15 (emphasis added). 
109 Id. at 24. 
110 Transmittal Letter at 11.

29 
c. The LARS framework provides LSEs the unchecked ability to 
favor their own generation and discriminate against 
competitors 
To protect against undue discrimination, the Commission set a number of open access 
requirements, which ensure that generation owned by transmission owners is not given 
preferential access to the transmission system. For nearly a quarter of a century, FERC has 
rigorously implemented this statutory prohibition by requiring open access in generator 
interconnection processes.111 As the D.C. Circuit has acknowledged, “[o]ne of the Commission’s 
chief goals in promulgating standard interconnection rules was to minimize opportunities for 
undue discrimination by transmission operators, and it does that in part by protecting relatively 
unencumbered entry into the market.”112 
FERC has therefore been wary of proposals that open the door to undue discrimination by 
expediting certain generators’ interconnections. When FERC recently accepted expedited 
generator interconnection procedures to meet a demonstrated reliability need in the PJM 
Interconnection (“PJM”) region, it did so only after concluding that: (1) the processes were 
narrowly tailored to ensure comparable access to interconnection service for resources seeking to 
show they are capable of meeting the identified reliability need; and (2) the proposal minimized 
harm to other interconnection customers that could not participate in the expedited process.113 In 
other words, to the extent FERC countenances discrimination through expedited interconnection 
queues, that discrimination must be closely scrutinized to ensure it is due.114 
 
111 Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, 
104 FERC ¶ 61,103, at PP 8–12 (2003); Improvements to Generator Interconnection Procedures 
and Agreements, Order No. 2023, 184 FERC ¶ 61,054, at P 37 (2023). 
112 Xcel Energy Servs. v. FERC, 41 F.4th 548, 559 (D.C. Cir. 2022) (cleaned up). 
113 PJM Interconnection, L.L.C., 190 FERC ¶ 61,084, at PP 123, 245 (2025). 
114 See id. (Rosner & Phillips, Comm’rs, concurring at P 2).

30 
Here, LARS allows vertically integrated utilities, entities with an incentive to 
discriminate against competitors, to serve as the lead “coordinator,” providing them with the 
authority to discriminate against competitors who also seek to participate in the LARS process. 
Additionally, the LARS proposal is not narrowly tailored in any of the ways the Commission has 
previously required in its limited approval of departures from open access principles. Given these 
deficiencies, the Commission should reject the LARS proposal. 
i. The Transmission Customer, often the LSE, is the only 
party that may submit a LARS application to MISO 
and is therefore subject to perverse incentives to 
discriminate against competitors 
MISO proposes to require that a transmission customer, which “often” is an LSE, 
sponsors and “submit[s]” the LARS application.115 In other words, the LSE is the gatekeeper for 
participation in LARS, because without it “initiat[ing] the LARS application” the process cannot 
proceed.116 The Commission instituted open access to prevent transmission-owning entities, such 
as many LSEs, from gatekeeping which generators can and cannot interconnect to the grid.117 
This is because, as the Commission has noted, utilities have a distinct incentive to stymie 
interconnection to the queue from independent generators and otherwise prefer their own 
generation.118 
 
115 Transmittal Letter at 6, 8. 
116 Id. at 6. 
117 See, e.g., Alliant Energy Corp. v. FERC, 253 F.3d 748, 753 (D.C. Cir. 2001) (“Order [No.] 
888 was expressly designed to remedy undue discrimination in access to the monopoly owned 
transmission wires that control whether and to whom electricity can be transported in interstate 
commerce.”) (internal quotations omitted). 
118 Order No. 888’s preamble states: “The legal and policy cornerstone of these rules is to 
remedy undue discrimination in access to the monopoly owned transmission wires that control 
whether and to whom electricity can be transported in interstate commerce. A second critical 
aspect of the rules is to address recovery of the transition costs of moving from a monopoly-
regulated regime to one in which all sellers can compete on a fair basis and in which electricity is 
more competitively priced.” Promoting Wholesale Competition Through Open Access Non-

31 
MISO explains that it has allowed the transmission customer this pivotal role “[b]ecause 
only the Transmission Customer can procure Transmission Service under established Tariff 
processes.”119 But MISO’s response does not reasonably explain why the setup MISO 
proposed—which, as described below, is rife with opportunities for discrimination—is needed.  
For example, many LSEs have their own generation that they would prefer to use to serve 
load, and in particular lucrative large loads like data centers. Therefore, the structure of LARS, 
which gives them final gatekeeping authority, will allow them to either block, undercut, or 
otherwise disadvantage competitors, principally independent resource developers, from being 
able to fairly participate in LARS. For example, if a large load is given competitive offers from 
an LSE and an independent power producer, the large load will have an incentive to choose the 
LSE even if the independent power producer’s offer is more competitive considering the ultimate 
leverage the LSE holds over the process.  
Moreover, LARS does not give any entity—from MISO, to the Commission itself—clear 
visibility to determine if a Transmission Customer is discriminating by preferring only its own 
generation projects for LARS. An agency, like the Commission, may not subdelegate its 
decision-making and oversight authority “to outside entities—private or sovereign—absent 
affirmative evidence of authority to do so.”120 Additionally, it is unclear whether, under the 
structure of the LARS proposal, the Commission could even utilize FPA section 206 to conduct 
an after-the-fact investigation into whether a Transmission Customer discriminated against a 
LARS applicant if that same Transmission Customer is not subject to Commission jurisdiction 
 
Discriminatory Transmission Services by Public Utilities, Order No. 888, 61 Fed. Reg. 21,540, 
21,541 (May 10, 1996), FERC Stats. & Regs. ¶ 31,036, at 31,634–35 (1996). 
119 Transmittal Letter at 6. 
120 See U.S. Telecom Ass’n v. FCC, 359 F.3d 554, 566 (D.C. Cir. 2004); see also Entergy Servs., 
Inc., 120 FERC ¶ 61,020, at P 28 (2007) (“[R]atemaking obligations … cannot be delegated to a 
state commission.”).

32 
pursuant to Federal Power Act section 201(f). The end result therefore is likely both unknowable 
and unreviewable. 
Indeed, this is a similar problem to one that is currently being litigated with regard to 
MISO’s ERAS proposal, which is currently pending before the U.S. Court of Appeals for the 
D.C. Circuit.121 To the extent the petitioners in that case prevail on their structural challenge to 
ERAS, it will fundamentally undermine the entire framework underpinning this proposal. 
ii. The LARS framework is not sufficiently narrowly 
tailored 
FERC has allowed some limited departures from open access requirements if such 
deviations are narrowly tailored to meet an important need, and principally, this has been when 
there is an imminent reliability need.122 But even in these situations, the Commission has 
required that the intervention be narrowly tailored to meet that need. As discussed above, LARS 
does not claim to be serving a specific reliability need, and, as a result, it is inherently impossible 
to narrowly tailor for that need.  
But LARS also does not have any of the other indicia of a narrowly tailored program that 
the Commission has previously required. For example, LARS is not time-limited, as MISO’s 
most recent queue-jumping proposal ERAS was. Additionally, while LARS includes a yearly 
threshold of three cycles of a maximum of ten projects per cycle, it does not limit the total 
number of projects or include a cap on the total MW of load proposed to be interconnected. 
MISO does not even attempt to identify the outer limits of when or how this queue-jumping 
framework will no longer be necessary, or otherwise explain why it could not undertake such an 
analysis. The D.C. Circuit has already admonished such an open-ended approach and held that it 
 
121 See Clean Wisconsin v. FERC, No. 25-1264 (D.C. Cir.) (pending). 
122 See, e.g., PJM Interconnection, L.L.C., 190 FERC ¶ 61,084 (2025); Midcontinent Indep. Sys. 
Operator, Inc., 192 FERC ¶ 61,064 (2025).

33 
“cannot overlook such unexplained inconsistency” when the Commission approves a policy that 
extends beyond the “limited period of time” of identified need.123 
MISO’s proposal also is expressly not limited to physically connected and electrically 
proximate pairs of load and generation. Instead, LARS generators and load are merely required 
to be in the same general Local Resource Zone.124 Indeed, MISO recognizes that this choice does 
not reflect a narrowly tailored approach where it notes that “there [were] other ways it could 
have limited the pairing such as requiring the generation and LARS Associated Load to be 
located in the same Local Balancing Authority area or through requiring that the location of the 
Generating Facilities be within a specific number of substations of the LARS Associated 
Load.”125 Without such protections to more narrowly tailor the scope and effect of the proposal, 
LARS strays far afield from even the limited exceptions to open access principles which the 
Commission has previously blessed. 
C. LARS is an unjustified departure from the Commission’s pro forma 
interconnection procedures and does not accomplish the purposes of Order 
No. 2023 
Interconnection is a “critical component of open access transmission service.”126 The 
Commission standardizes interconnection through pro forma interconnection procedures and 
agreements that every public utility transmission provider must adopt.127 An RTO or ISO may 
depart from the pro forma documents under the “independent entity variation” standard, but only 
 
123 Ky. Mun. Energy Agency v. FERC, 45 F.4th 162, 186 (D.C. Cir. 2022). 
124 Transmittal Letter at 10. 
125 Id. 
126 Order No. 2023, 184 FERC ¶ 61,054, at P 11& n.11 (quoting Order No. 2003, 104 FERC ¶ 
61,103 at P 9 (2003)). 
127 Order No. 2003, 104 FERC ¶ 61,103, order on reh’g, Order No. 2003-A, 106 FERC ¶ 61,220 
(2004), order on reh’g, Order No. 2003-B, 109 FERC ¶ 61,287 (2004), order on reh’g, Order 
No. 2003-C, 111 FERC ¶ 61,401 (2005), aff’d sub nom. Nat’l Ass’n of Regulatory Util. Comm’rs 
v. FERC, 475 F.3d 1277 (D.C. Cir. 2007); Order No. 2023, 184 FERC ¶ 61,054, order on reh’g, 
Order No. 2023-A, 186 FERC ¶ 61,199 (2024).

34 
where it “demonstrates that the proposed variation: (1) is just and reasonable and not unduly 
discriminatory or preferential; and (2) accomplishes the purposes of the order.”128 While this 
standard is more flexible than a “consistent with or superior to” standard, the Commission has 
stated that “[i]t is not a sufficient justification to state that a variation conforms to current 
RTO/ISO practices or to the RTO’s/ISO’s tariff definitions and terminology.”129 The 
Commission has applied the standard to recent expedited interconnection proposals, including 
MISO’s ERAS.130 Here, LARS is a deviation from Order No. 2023, which the D.C. Circuit 
upheld this summer.131 
MISO has not shown that it meets the independent entity variation standard with respect 
to Order No. 2023. MISO asserts that LARS is “just and reasonable” and “not unduly 
discriminatory,” but it never identifies LARS as a variation from the pro forma procedures and 
never explains how a permanent, serial, first-come, first-served interconnection process 
accomplishes the purposes of a rule that abolished serial, first-come, first-served interconnection 
processes. MISO’s only mention of Order No. 2023 is in a footnote acknowledging that MISO 
built the LLGIA from a version of its pro forma GIA that predates its own Order No. 2023 
compliance filing (pending at the Commission) and promising “to reconcile these versions as 
appropriate once they are accepted.”132 The Commission cannot determine whether a variation 
 
128 PJM Interconnection, L.L.C., 195 FERC ¶ 61,031, at P 10 (Apr. 16, 2026) (quoting ISO New 
England Inc., 164 FERC ¶ 61,222, at P 9 (2018)); Order No. 2023, 184 FERC ¶ 61,054 at P 1764 
(citing Order No. 2003, 104 FERC ¶ 61,103, at P 826 (2003); and Reform of Generator 
Interconnection Procedures and Agreements, Order No. 845, 163 FERC ¶ 61,043, at P 556 
(2018)). 
129 Cal. Indep. Sys. Operator Corp., 170 FERC ¶ 61,112, at P 11 (2020). 
130 Midcontinent Indep. Sys. Operator, Inc., 191 FERC ¶ 61,131 (2025) (rejecting MISO’s initial 
ERAS proposal). 
131 Advanced Energy United v. FERC, No. 23-1282 (D.C. Cir. July 31, 2026) (per curiam) 
(denying all petitions for review of Order No. 2023). 
132 Transmittal Letter at 24 n.95.

35 
accomplishes the purposes of Order No. 2023 when the baseline from which it varies has not 
itself been conformed to Order No. 2023. MISO’s failure to address the governing standard is 
itself sufficient reason to reject the filing. 
Were the Commission to reach the merits of LARS’s status as a valid independent entity 
variation, the Commission would find that it does not. Order No. 2023’s central reform was to 
replace serial, first-come, first-served studies with first-ready, first-served cluster studies, 
because the Commission found that serial processing was a primary cause of the unjust and 
unreasonable backlogs for generator interconnection.133 MISO already operates a cluster study 
process, and it describes the DPP’s “three-phase, grouped study process” as the mechanism that 
“identif[ies] and remove[s] speculative or non-feasible projects as more information becomes 
available.”134 LARS, on the other hand, moves in the opposite direction, to a first-come, first-
served process. Each request under LARS is studied “individually and in a serial fashion based 
on their submission date.”135 MISO argues that this serial process “avoids the dependence on the 
overall cluster of generating facilities moving forward.”136 
Unlike other expedited interconnection processes approved by the Commission, LARS is 
permanent. For example, the Commission accepted PJM’s Reliability Resource Initiative as a 
one-time departure, and Commissioners Rosner and Phillips wrote that they would not have 
found it just and reasonable otherwise.137 While the Commission accepted MISO’s revised 
ERAS proposal, ERAS includes a sunset date and puts a cap on the number of participants. 
 
133 Order No. 2023, 184 FERC ¶ 61,054 at PP 44–55, 165 (2023). 
134 Drake Testimony at 9. 
135 Transmittal Letter at 12. 
136 Drake Testimony at 15. 
137 PJM Interconnection, L.L.C., 190 FERC ¶ 61,084 (2025); id. (Rosner & Phillips, Comm’rs, 
concurring).

36 
MISO asks the Commission to allow a permanent serial side-queue it has allowed only as a 
temporary and bounded exception in recent decisions. 
LARS is also counter to the need for certainty that the Commission insisted on in Order 
No. 2023.138 LARS reduces certainty for DPP participants in at least two ways. First, as shown 
above, LARS generators are studied without the DPP queue and DPP customers are studied 
without LARS generators, so that the upgrade assignments in both processes rest on models 
MISO concedes are separate and distinct.139 Second, LARS has no restudy process and MISO 
will tender LLGIAs before affected system results are available, which it concedes is “necessary 
to maintain the accelerated speed of the LARS process.”140 MISO seeks to trade certainty for 
speed for a privileged few data centers and their paired generation. 
Order Nos. 2003 and 2023 were also designed to accomplish an open access purpose of 
ensuring non-discriminatory access to the transmission system. Here too, MISO’s LARS 
proposal does not accomplish the purposes of the Commission’s interconnection orders. As 
discussed supra, LARS does not meet the goals of enabling open access to the transmission 
system because it places access to the LARS interconnection process under the gatekeeping 
control of self-interested vertically integrated utilities. It grants preferential treatment to 
generators interconnecting through LARS compared to generators seeking to interconnect 
through the DPP process.  
Additionally, the Commission’s interconnection orders were designed to streamline 
interconnection processes and create a standard, unified interconnection process. By creating a 
 
138 Order No. 2023, 184 FERC ¶ 61,054, at PP 37–45 (2023). 
139 Drake Testimony at 32–33. 
140 Transmittal Letter at 16, 25–26.

37 
new, parallel interconnection process in LARS, MISO’s proposal works crosswise to this 
simplifying goal.  
Finally, Order No. 2023 was designed to increase the speed of interconnection for new 
generation interconnection requests. While LARS might fast track a limited set of privileged 
interconnection requests, the creation of a new interconnection queue will put competing 
pressures on MISO’s staff and compute time to process standard DPP requests. And while MISO 
stated that LARS deposits will fund “additional tools, staffing, and process enhancements” rather 
than drawing on DPP resources,141 MISO still undermines the purpose of Order No. 2023 to the 
extent DPP is not receiving these marginal additional resources to speed DPP timelines.142 
D. MISO’s LARS proposal is not responsive to Commission direction regarding 
“electrically proximate” generation and load from the Show Cause Order 
In the Show Cause Order, the Commission found that MISO’s Tariff “appears to be 
unjust and unreasonable” because it did not contain provisions allowing an interconnection 
customer to serve “an electrically proximate large load.”143 Rather than directly responding to the 
Commission’s Order, MISO invents a new expansive definition of “proximate” in an attempt to 
demonstrate that its proposal is responsive to the Commission’s Order. It is not. 
The Commission defined electrically proximate load as a large load “that is sufficiently 
electrically close to the interconnection customer’s requested point of interconnection, such that 
the impact on the transmission system of the combination of the generating facility and the load, 
with the exception of the transmission facilities between the two, will be effectively the same as 
if they were located at the same substation.”144 MISO chose not to conform to this definition and 
 
141 Drake Testimony at 32. 
142 See Drake Testimony at 12 (noting that “the MISO DPP interconnection queue does not move 
this fast and is designed for a 365-day timeline”). 
143 Show Cause Order at P 113. 
144 Id. at P 112.

38 
instead “anchor[ed] the proximate requirement with the [Local Resource Zone],”145 not the two-
substation distance the Commission suggests as an example of electrically proximate load and 
generation.  
MISO argues that this new definition is appropriate because the Commission stated that it 
would “consider proposed revisions to this definition to ‘ensure it is appropriately tailored to 
MISO’s transmission system.’”146 However, as MISO itself concedes, its definition of proximate 
is not grounded in the unique structure of its transmission system, and instead MISO simply “did 
not want to limit the pairing of generation with associated load to a specific number of 
substations because that is likely too geographically narrow and could limit how MISO may 
optimize common transmission solutions.”147 As such, even MISO’s novel definition of 
proximate is inconsistent with the flexibility afforded by the Commission on this issue. 
Additionally, MISO justifies this choice by arguing that tying LARS Associated Load to 
Local Resource Zones “avoids price separation between the paired generation and LARS 
Associated Load.”148 However, Local Resource Zones do not always align with transmission 
pricing zones and cost allocation zones.149 Only zones 2, 8, 11, and 12 have only one 
transmission pricing zone within the LRZ. Other LRZs with multiple transmission pricing zones 
will not easily be able to ensure that transmission costs associated with large load additions are 
assigned to that load. Local Resource Zones are intended to reflect capacity and reliability needs, 
not transmission cost recovery. MISO intentionally separates these constructs because they 
 
145 Transmittal Letter at 21. 
146 Id. (quoting Show Cause Order at P 112) (emphasis added). 
147 Id. 
148 Id. (quoting Drake Testimony at 40–41). 
149 See generally Use of “Zones” and “Regions” at MISO, OMS CapCOM (Jan. 11, 2021), 
available at 
https://www.misostates.org/images/stories/meetings/Cost_Allocation_Principles_Committee/202
1/MISO_Zones_and_Regions.pdf.

39 
address different reliability and economic objectives, and MISO’s proposed blending of Local 
Resource Zones with economic objectives is therefore arbitrary. Indeed, the only plausible 
reason to tie the proximate definition to Local Resource Zones is that those zones are relevant to 
participation in MISO’s capacity construct, which, as described above, is also inappropriate and 
arbitrary. 
E. LARS threatens reliability and efficient planning 
LARS would be at least the fifth separate path onto the MISO transmission system, 
alongside the DPP, ERAS, the pending Zero-Injection Generator Interconnection Agreement 
(“ZGIA”) process, and EPR for load. A sixth, the Large Load Project Review (“LLPR”) is 
currently under development.150 MISO’s addition of another parallel interconnection process 
takes the region further away from efficient transmission planning. MISO’s statement that any 
constraints that are not addressed in the LARS study due to overallocation would be reconciled 
in the MTEP process does not promise that these solutions would be minimal upgrades.151 It 
promises only that they would be reconciled through the MTEP process. There is a risk under 
MISO’s current proposal that unresolved reliability contingencies identified in a subsequent 
MTEP process could require mitigation through backbone upgrades or other high-cost solutions 
resulting from the cumulative impacts of LARS and other interconnection requests, the costs of 
which non-LARS transmission customers would ultimately have to pay. Due to the permanent 
nature of MISO’s LARS proposal, there is a risk that non-LARS transmission customers could 
be permanently disadvantaged by the process and bear the costs of transmission investments 
needed to resolve issues caused, at least in part, by a LARS request, or series of interconnection 
requests. Each new path to interconnection takes MISO further from efficient planning. 
 
150 Drake Testimony at 38, 44; Transmittal Letter at 19–20. 
151 Transmittal Letter at 13.

40 
1. Parallel independent studies produce unreliable results and reliability risks 
Interconnection studies assign network upgrades on the basis of cumulative impacts. By 
putting some generators in one model and other generators in another, MISO cannot capture 
those impacts. The North American Electric Reliability Corporation’s (“NERC”) model 
validation guidance states that future-year planning cases “should contain the same component 
representations as the most recently validated model, unless there is a specific reason for the data 
to be different,” and should represent “the cumulative planned changes to the system” through 
the period studied.152 By excluding the DPP, LARS does the opposite of NERC’s procedures. 
Neither set of studies sees the other until MTEP, which is after LLGIAs have been executed and 
DPP customers have been assigned their upgrades. 
The consequences of this mutual blindness of the models are not limited to the cost shifts 
described above. A constraint that appears only when the two sets of projects are combined 
might be a contingency for which no mitigation was identified and no upgrade was built, leaving 
real-time operators without the reconfiguration options the planning process assumed. In the 
worst case, cascading blackouts could result. A more moderate negative outcome might be load 
shed as the only tool available to manage unstudied conditions. MISO does not appear to 
describe the dispatch and case assumptions for the LARS load study. MTEP-based load studies 
and DPP interconnection studies in MISO are built on different cases and different dispatch 
assumptions. Without an explanation of which assumptions LARS will use, the Commission has 
no basis to find that a load study built upon MISO’s existing EPR process will identify the 
constraints that a DPP study of the same generator would identify. 
 
152 NERC, Procedures for Validation of Powerflow and Dynamics Cases § 1, at 1, available at 
https://www.nerc.com/globalassets/our-
work/assessments/nerc_model_validation_procedures_v3.pdf.

41 
Siloing also creates questions around generator retirement. If a LARS generator retires 
within the fifteen-year pairing period, the Tariff says the load may go through MTEP, but it does 
not say whether the Attachment Y retirement study and the MTEP restudy of the load occur in 
sequence or in parallel, or who bears the upgrades needed to keep serving a load whose MTEP 
approval rested on a generator that no longer exists.153 Once future MTEP cycles combine 
generators from the serial and cluster processes into a single model, a withdrawal or retirement in 
either process can require restudy in the others. MISO has not addressed these interactions. 
2. Siloed, expedited processes are already driving MISO’s largest 
transmission investments outside regional planning 
MISO acknowledges that “large loads have overtaken the EPR process.”154 In MTEP26, 
roughly 54 percent of the $14.7 billion of approved transmission investments originated in EPR, 
as did eight of the ten largest Appendix A projects, representing approximately $6 billion.155 
Transmission additions to the MISO grid of this magnitude will have a dramatic impact on 
power flows throughout MISO’s system, and continuing the analysis of large load needs in an 
isolated process like that outlined in LARS risks harmful impacts to other transmission 
customers. By MISO’s admission in its LARS filing, the EPR process has become increasingly 
challenging due to the volume and type of facilities proposed through this process. Take, for 
instance, the proposed 500 kV Smalling–El Dorado and 500 kV West Fork–St. Landry lines and 
the 230/500 kV West Fork substation facility evaluated through MISO’s EPR process. These two 
transmission lines span over 200 miles across Louisiana and Arkansas, and the 230/500 kV 
 
153 Proposed GIP § 3.12.7.4; Proposed Attachment FF § I.D.1.b.ii(g). 
154 Drake Testimony at 26. 
155 MISO, MTEP26 Report Review, Planning Advisory Committee, at 4, 8–9 (Oct. 7, 2026), 
available at 
https://cdn.misoenergy.org/20261007%20PAC%20Item%2006%20MTEP26%20Report%20Rev
iew785938.pdf.

42 
substation is a very large facility comprising $1.1 billion in investment.156 Backbone facilities of 
this size manage larger flows of energy that by their nature have more regional impacts, 
complicating MISO’s transmission planning process. To the extent LARS will include projects 
of this scope, considering them through siloed, expedited processes could disadvantage other 
transmission customers by separating these projects from a regional process where system 
impacts could be considered in an integrated manner. In addition, expedited processes like LARS 
leave little time for MISO to evaluate alternatives that may be most efficient and cost effective, 
as required under Order No. 1000.157 
Given the size of recent proposed EPR transmission investments and ERAS generator 
interconnection requests in MISO that can be linked to load interconnections of several 
gigawatts, there could be dramatic topology changes in the system that could significantly alter 
transmission flows on MISO’s system if not studied in an integrated manner. A high 
concentration of load in one area of the grid could create constraints that limit import capability 
to other load zones on the system, creating a situation where either greater investment in 
generation or transmission is required to maintain system reliability. Highly constrained areas 
like these exist today along the industrial corridor of the Gulf Coast, and MISO is currently in the 
process of assessing system needs related to these load pockets in the wake of load shed events 
on May 25, 2025158 and during Winter Storm Uri in 2021.159 Continuing a process where 
 
156 Id. 
157 Order No. 1000, 136 FERC ¶ 61,051, at P 6 (2011). 
158 MISO, May 25 Transmission Load Shed Event, Reliability Subcommittee (July 17, 2025), 
available at 
https://cdn.misoenergy.org/20250717%20RSC%20Item%2007%20May%2025%20Load%20She
d%20Event707855.pdf. 
159 MISO, The February Arctic Event (Feb. 14–18, 2021), available at 
https://cdn.misoenergy.org/2021%20Arctic%20Event%20Report554429.pdf.

43 
transmission needs for gigawatts of load are considered in a siloed process risks the creation or 
exacerbation of load pockets across MISO’s system. 
3. Integrated planning processes are available and MISO should adopt them 
There are viable alternatives to siloed transmission planning, which is inefficient and 
costly. In March, the Commission accepted SPP’s Consolidated Planning Process (“CPP”), 
which, in Commissioner Rosner’s description, “eliminat[es] the silos between the transmission 
planning process and the generator interconnection process” by “synthesizing and streamlining 
them into one recurring three-year planning cycle” that “recognizes that generation and load 
share one transmission system, and plans for both of their needs holistically.”160 Commissioner 
Rosner “strongly encourage[d] other transmission providers to take note of the innovative 
approach the CPP promises, and to consider developing similar integrated solutions tailored to 
meet the pressing needs within their own footprints.”161 Commissioner Rosner noted that SPP 
expected to deliver interconnection agreements within nine to ten months of the close of its 
application window, to cut study costs by millions of dollars, and to avoid more than $100 
million in duplicative transmission costs each planning cycle.162 PJM, responding to its own 
show cause order, has proposed to “[c]onsolidate generation and merchant transmission 
interconnection along with long-term firm and large load transmission service studies into a 
singular 12-month process.”163 Transmission planning becomes more efficient the more future 
transmission needs can be considered together in the planning process. This is one of the reasons 
 
160 Sw. Power Pool, Inc., 194 FERC ¶ 61,192, at 62,054, at P 2 (Mar. 13, 2026) (Rosner, 
Comm’r, concurring). 
161 Id. at P 8. 
162 Id. at P 2. 
163 PJM Interconnection, L.L.C., Show Cause for Large Loads Framework, Co-Located Load 
Order Workshop, at 6 (Sept. 30, 2026), available at https://www.pjm.com/-
/media/DotCom/committees-groups/workshops/cllsco/2026/20260930/20260930-item-02---
show-cause-for-large-loads-approach---presentation.pdf.

44 
FERC has required more comprehensive consideration of transmission needs in both 
transmission and interconnection planning under Order Nos. 1000, 2023, and 1920.164 MISO 
ignores that direction in proposing LARS. 
After MISO first presented its concept for aligning load and generation studies at the July 
16, 2026 LLWG meeting, stakeholders presented a consolidated planning process at MISO.165 
Among other things, the process would assign the costs of Network Upgrades would be allocated 
by contribution under the DPP’s existing cost-causation rules, rather than to load. The proposal 
drew support across sectors, including from the Environmental Sector.166 
167 
 
164 See Order No. 1000, 136 FERC ¶ 61,051 (2011); Order No. 1920, 187 FERC ¶ 61,068 
(2024); Order No. 2023, 184 FERC ¶ 61,054 (2023). 
165 Energy Futures Group, Generator and Load Interconnection Process (GALIP) at 7–12 (Aug. 
27, 2026), available at 
https://cdn.misoenergy.org/20260827%20LLWG%20Item%2013%20Generator%20Load%20Int
erconnection%20Process%20(GALIP)%20Proposal_Energy%20Futures%20Group777224.pdf. 
Energy Futures Group sought to present GALIP at the August 12, 2026 LLWG meeting, but 
MISO and the LLWG chair did not make time on that agenda; GALIP was heard in the final half 
hour of the six-hour August 27, 2026 LLWG meeting. 
166 Environmental Sector Feedback on LLWG-2026-6, MISO Stakeholder Feedback (Aug. 27, 
2026), available at https://www.misoenergy.org/engage/stakeholder-feedback/2026/llwg-large-
load-addition-resource-study-llwg-2026-6-20260827. 
167 Energy Futures Group, Generation and Load Interconnection Process (GALIP): A Smarter 
Approach to Interconnection (Sept. 15, 2026), available at

45 
MISO’s disagreement with the GALIP proposal reveals its interconnection ethos: “MISO 
offers different interconnection products to meet different needs.”168 This is problematic for three 
reasons. First, meeting every new need with a new, siloed interconnection process (as MISO has 
done with ERAS, the ZGIA, now LARS, and soon the LLPR) significantly increases network 
upgrade costs and the risk of MISO missing the combined system impacts of all of these parallel 
processes. Second, multiple interconnection paths increase the risk of bias and subjective 
assignment of preferential treatment, as discussed above. Third, interconnection studies are 
performed in sequential order where each stage builds on the models, assumptions, and data of 
the previous one. Parallel interconnection paths, particularly ones like LARS where the impact is 
not constrained to a single point of interconnection, are inherently flawed. Since the physics of 
load and generation interconnection are inextricably tied, MISO’s approach of parallel studies 
will fail to provide a complete view of transmission needs and system demands for LARS 
resources.  
IV. 
Conclusion 
For the foregoing reasons, the Commission should reject all portions of MISO’s LARS 
proposal and direct MISO to engage with stakeholders to advance a different proposal.  
Alternatively, Clean Energy Advocates and Community Organizations request that the 
Commission issue a deficiency letter directing MISO to address the issues in this protest. Either 
course of action should focus on an integration of planning processes that does not undermine 
the DPP queue or shift costs to DPP customers. 
Dated: October 23, 2026 
 
https://energyfuturesgroup.com/2026/09/15/generation-and-load-interconnection-process-galip-
a-smarter-approach-to-interconnection/.  
168 Drake Testimony at 44.

46 
Respectfully submitted, 
SIERRA CLUB 
 
/s/ Justin Vickers 
Justin Vickers 
Senior Attorney, Sierra Club 
2101 Webster St., 13th Floor 
Oakland, CA 94612 
(224) 420-0614 
justin.vickers@sierraclub.org 
 
/s/ Aaron Stemplewicz 
Aaron Stemplewicz 
Sameer Doshi 
Senior Attorney 
Earthjustice 
1617 John F. Kennedy Blvd., Ste. 2020 
Philadelphia, PA 19103 
(917) 628-7411 
astemplewicz@earthjustice.org 
sdoshi@earthjustice.org  
 
Counsel for Sierra Club 
 
NATURAL RESOURCES DEFENSE COUNCIL 
 
/s/ Anna Markowski 
Anna Markowski 
Director, Midwest 
Climate and Clean Energy 
Natural Resources Defense Council  
20 North Wacker Drive, Suite 1600  
Chicago, IL 60606  
312-651-7927 
Amarkowski@nrdc.org

47 
SUSTAINABLE FERC PROJECT 
 
/s/ Natalie McIntire 
Natalie McIntire 
Senior Advocate 
Sustainable FERC Project 
Natural Resources Defense Council 
20 North Wacher Drive, Suite 1600 
Chicago, IL 60606 
312-995-5907 
nmcintire@nrdc.org 
 
CLEAN GRID ALLIANCE 
 
/s/ Beth Soholt 
Beth Soholt 
Executive Director 
Clean Grid Alliance 
3433 Broadway St NE, Suite 240 
Minneapolis, MN 55413 
651.644.3400 
bsoholt@cleangridalliance.org 
 
CLEAN WISCONSIN 
 
/s/ Ciaran Gallagher 
Ciaran Gallagher, Ph.D. 
Energy & Air Manger 
Clean Wisconsin 
634 W Main St #300 
 
Madison, WI 53703 
cgallagher@cleanwisconsin.org 
 
COMMUNITY COLLABORATION ON CLIMATE CHANGE 
 
/s/ Kareem Scales 
Co-Chair 
Community Collaboration On Climate Change 
Grand Rapids, MI 
kareem@c4gr.org

48 
FRESH ENERGY 
 
/s/ Mike Schowalter 
Mike Schowalter 
Managing Director, Transmission Policy 
Fresh Energy 
81 Seventh St. E., Suite 200 
Saint Paul, MN 55101 
(612) 433-3648 
schowalter@fresh-energy.org 
 
MICHIGAN ENVIRONMENTAL JUSTICE COALITION 
 
/s/ Wesley Watson 
Wesley Watson 
Policy Associate 
Michigan Environmental Justice Coalition 
1401 W. Fort St., P.O. Box 44080 
Detroit, MI 48233 
wesley@michiganej.org

49 
CERTIFICATE OF SERVICE 
 
I hereby certify that the foregoing has been served in accordance with 18 C.F.R. § 
385.2010 upon each party designated on the official service list in this proceeding, by email. 
 
            Dated: October 23, 2026. 
 
/s/ Justin Vickers 
Justin Vickers 
Senior Attorney, Sierra Club 
2101 Webster St., 13th Floor 
Oakland, CA 94612 
(224) 420-0614 
justin.vickers@sierraclub.org 
 
Counsel for Sierra Club