EL26-67-000 · 2026-06-18 · FERC

PJM show cause order

195 FERC ¶ 61,211 
UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
 
Before Commissioners:  Laura V. Swett, Chairman; 
                                        David Rosner, Lindsay S. See, 
                                        Judy W. Chang, and David LaCerte. 
 
PJM Interconnection, L.L.C.  
AEP Appalachian Transmission Company, Inc. 
AEP Indiana Michigan Transmission Company, Inc. 
AEP Kentucky Transmission Company, Inc. 
AEP Ohio Transmission Company, Inc. 
AEP West Virginia Transmission Company, Inc. 
Allegheny Electric Cooperative, Inc. 
American Transmission Systems, Incorporated 
Appalachian Power Company 
Atlantic City Electric Company 
Baltimore Gas and Electric Company 
Commonwealth Edison Company 
Commonwealth Edison Company of Indiana, Inc. 
Dayton Power and Light Company 
Delmarva Power & Light Company 
Duke Energy Kentucky, Inc. 
Duke Energy Ohio, Inc. 
Duquesne Light Company 
Essential Power Rock Springs, LLC 
Hudson Transmission Partners, LLC 
Indiana Michigan Power Company 
Jersey Central Power & Light Company 
Kentucky Power Company 
Keystone Appalachian Transmission Company 
Kingsport Power Company 
Linden VFT, LLC 
Mid-Atlantic Interstate Transmission, LLC 
Monongahela Power Company 
Neptune Regional Transmission System, LLC 
NextEra Energy Transmission MidAtlantic Indiana, Inc. 
Ohio Power Company 
Ohio Valley Electric Corporation 
Old Dominion Electric Cooperative 
PECO Energy Company 
Docket No. EL26-67-000

Docket No. EL26-67-000 
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PPL Electric Utilities Corporation 
The Potomac Edison Company 
Potomac Electric Power Company 
Public Service Electric and Gas Company 
Rockland Electric Company 
Silver Run Electric, LLC 
Trans-Allegheny Interstate Line Company 
Transource West Virginia, LLC 
UGI Utilities, Inc. 
Virginia Electric and Power Company 
Wabash Valley Power Association, Inc. 
Wheeling Power Company 
 
ORDER INSTITUTING PROCEEDING  
 
UNDER SECTION 206 OF THE FEDERAL POWER ACT 
 
(Issued June 18, 2026) 
 
 
Paragraph Numbers 
I. Background ..................................................................................................................... 6. 
A. Growth of Large and Co-Located Loads and ANOPR ............................................. 6. 
B. Recent Proceedings Addressing Large and Co-Located Loads .............................. 11. 
1. PJM Co-Location Proceedings ............................................................................ 12. 
2. SPP High Impact Large Load Process and High Impact Large Load Generation 
Assessment Processes .............................................................................................. 15. 
3. SPP Conditional High Impact Large Load Service ............................................. 17. 
II. PJM’s Existing Processes ............................................................................................ 19. 
A. Existing Tariff Processes ......................................................................................... 19. 
B. Recent Stakeholder Proceedings in PJM ................................................................. 31. 
III. Discussion ................................................................................................................... 35. 
A. Transmission Service to Eligible Customers on Behalf of Large Loads ................ 41. 
1. Jurisdiction ........................................................................................................... 44. 
2. Tariff Provisions .................................................................................................. 50. 
B. Cost Shifting Risk Among Transmission Customers .............................................. 66. 
1. Jurisdiction ........................................................................................................... 68. 
2. Additional Cost Transparency ............................................................................. 71. 
3. Cost Recovery Agreements ................................................................................. 77. 
C. Extending New Transmission Services to Eligible Customers Taking Service on 
Behalf of Flexible Large Loads ................................................................................... 85.

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D. Interconnection Customers Serving Electrically Proximate Large Load and Co-
Located Load ................................................................................................................ 88. 
1. Jurisdiction ........................................................................................................... 92. 
2. Definitions ........................................................................................................... 94. 
3. Tariff Provisions .................................................................................................. 95. 
E. Informational Report ............................................................................................. 102. 
IV. Briefing Questions .................................................................................................... 105.

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Over the past year, the Commission has taken action in numerous dockets1 to 
address issues related to (a) unprecedented increases in requests for transmission service 
to serve large loads2 and (b) growing interest in the co-location of loads with generating 
facilities (co-location arrangements3).  Separately, the Secretary of Energy (Secretary) 
released an advance notice of proposed rulemaking (ANOPR) in October 2025.  The 
ANOPR, issued pursuant to section 403 of the Department of Energy Organization Act,4 
directed the Commission to consider taking additional actions to address the addition of 
large and co-located loads to the transmission system.5  The records in these proceedings 
illustrate a host of urgent challenges associated with providing the transmission service 
needed to serve the ongoing influx of large loads while maintaining reliability and 
affordability.  In particular, stakeholders have expressed concerns that large loads are not 
efficiently and appropriately integrated onto the transmission system; have identified a 
 
1 See, e.g., PJM Interconnection, L.L.C., 190 FERC ¶ 61,115 (2025) (PJM Show 
Cause Order); PJM Interconnection, L.L.C., 193 FERC ¶ 61,217 (2025) (PJM                       
Co-Location Order); Sw. Power Pool, Inc., 194 FERC ¶ 61,031 (2026) (SPP HILL 
Order); Sw. Power Pool, Inc., 195 FERC ¶ 61,196 (2026) (SPP CHILLS Order); see also, 
e.g., Duke Energy Carolinas, LLC, 193 FERC ¶ 61,237 (2025); Commonwealth Edison 
Co., 194 FERC ¶ 61,181 (2026). 
2 As explained below, it appears that it would be reasonable to define a large load 
as (1) a new commercial or industrial customer, (2) located at a single site behind one or 
more points of interconnection, (3) that has a peak load of 50 MW or greater, (4) 
interconnects to the transmission system at a voltage level of greater than 69 kV, and    
(5) is not part of a co-location arrangement.  See infra P 58. 
3 The PJM Co-Location Order defined co-located load as “configuration [that] 
refers to end-use customer load that is physically connected to the facilities of an existing 
or planned Customer Facility on the Interconnection Customer’s side of the Point of 
Interconnection to the PJM Transmission System.”  PJM Co-Location Order, 193 FERC 
¶ 61,217 at P 164 (alterations in original).  The PJM Co-Location Order used the term   
co-location arrangement when referring to both the co-located load and the associated 
generator.  Id. P 3. 
4 42 U.S.C. § 7173. 
5 See Interconnection of Large Loads to the Interstate Transmission System, 
Advance Notice of Proposed Rulemaking, Docket No. RM26-4-000 (Oct. 23, 2025) 
(ANOPR); see also Letter from Chris Wright, Sec’y, U.S. Dep’t of Energy, Docket     
No. RM26-4-000 (Oct. 23, 2025).  The ANOPR uses the term “hybrid facilities,” which it 
explains are large loads that “share a point of interconnection with new or existing 
generation facilities.”  ANOPR at P 12.  In this order, we use the term co-located load.

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number of unique challenges that large load integration poses for the reliable operation of 
that system; and have debated how best to ensure that the rates, terms, and conditions of 
transmission service remain just and reasonable as more and more large loads are 
onboarded onto that system.6  The records in these proceedings likewise present serious 
concerns about the lack of clarity and consistency in Regional Transmission Organization 
or Independent System Operator (RTO/ISO) tariffs—including with respect to the rates, 
terms, and conditions of service that apply to flexible large loads, co-location 
arrangements, load with behind the meter generation, and generating facilities with 
electrically proximate large load7 or co-located load. 
 
The findings in several recent Commission proceedings establish the foundations 
of a just and reasonable framework for addressing these concerns and ensuring the 
timely, efficient, and reliable integration of large and co-located loads onto the 
transmission system.  For example, Southwest Power Pool, Inc. (SPP) has recently taken 
a number of innovative and proactive steps to address the challenges of integrating large 
loads, co-located loads, and/or generation and electrically proximate large load onto the 
transmission system while ensuring that its tariff remains just and reasonable.8  PJM 
Interconnection, L.L.C. (PJM), through the Commission’s show cause proceedings, is 
also addressing the rates, terms, and conditions of service that apply to co-location 
arrangements and establishing new transmission services that reflect the ability of 
Eligible Customers9 taking transmission service on behalf of Eligible Load to limit their 
 
6 Throughout this order we rely on comments and answers filed in response to the 
ANOPR in Docket No. RM26-4-000 and all referenced comments in this order were filed 
in that docket, unless otherwise noted.  A full list of commenter names and abbreviations 
is attached to this order as an Appendix.  Additionally, we have relied on the discussions 
held in the Federal and State Current Issues Collaborative in Docket No. AD24-7-000 
(NARUC Collaborative).  All entities who wish to participate in this docket, regardless of 
participation in the ANOPR proceeding or NARUC Collaborative, should file to 
intervene in Docket No. EL26-67-000. 
7 As explained below, for purposes of this order, an “electrically proximate large 
load” is a large load, as defined in this order, 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 (e.g., large load that is located no more than 
two substations away from the generating facility).  See infra P 94. 
8 SPP HILL Order, 194 FERC ¶ 61,031; SPP CHILLS Order, 195 FERC ¶ 61,196. 
9 PJM’s Tariff defines an Eligible Customer as:

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withdrawals from the transmission system under certain conditions.10  PJM has also taken 
steps attempting to enhance resource adequacy in the region.11  Because the Commission 
is addressing its concerns related to co-located load in the separate and ongoing Federal 
Power Act (FPA) section 20612 proceeding involving PJM, this order is limited to 
addressing the integration of large loads that are not co-located with generation.  While 
we appreciate the steps PJM has already taken with respect to co-location arrangements, 
we note that PJM has not yet proposed tariff revisions to address the challenges 
associated with the integration of large loads. 
 
As discussed below, we find that PJM’s existing Open Access Transmission Tariff 
(Tariff) appears to be unjust, unreasonable, or unduly discriminatory or preferential.  We 
 
(i) Any electric utility (including any Transmission Owner 
and any power marketer), Federal power marketing agency, 
or any person generating electric energy for sale for resale . . .  
(ii) Any retail customer taking unbundled transmission 
service pursuant to a state requirement that the Transmission 
Provider or a Transmission Owner offer the transmission 
service, or pursuant to a voluntary offer of such service by a 
Transmission Owner, is an Eligible Customer under the 
Tariff.  As used in Tariff, Part VIII, Eligible Customer shall 
mean only those Eligible Customers that have submitted an 
Application and Study Agreement.   
PJM Interconnection, L.L.C., Intra-PJM Tariffs, OATT, pt. VIII, § 400 
(Definitions E) (2.0.0) (PJM Tariff). 
10 PJM Show Cause Order, 190 FERC ¶ 61,115; PJM Co-Location Order,         
193 FERC ¶ 61,217, order on reh’g, 195 FERC ¶ 61,209 (2026) (PJM Co-Location 
Rehearing Order).  In the PJM Co-Location Rehearing Order, the Commission used the 
term Eligible Load to refer to co-located load and/or load with Behind the Meter 
Generation.  PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 91.  
11 PJM Interconnection, L.L.C., 195 FERC ¶ 61,197 (2026) (PJM EIT Order); 
PJM Interconnection, L.L.C., 190 FERC ¶ 61,084, order on reh’g, 192 FERC ¶ 61,085 
(2025); see also PJM Interconnection, L.L.C., Informational Report, Docket                          
No. EL25-49-000, et al. (filed Jan. 20, 2026); PJM Interconnection, L.L.C., Supplemental 
Informational Report, Docket Nos. EL25-49-000, et al. (filed Feb. 23, 2026); PJM 
Interconnection, L.L.C., Second Supplemental Informational Report, Docket                 
No. EL25-49-000, et al. (filed Mar. 9, 2026). 
12 16 U.S.C. § 824e.

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thus institute a show cause proceeding pursuant to section 206 of the FPA, and we direct 
PJM and the Transmission Owners,13 within 60 days of the date of this order, to either:   
(1) show cause as to why the Tariff remains just and reasonable and not unduly 
discriminatory or preferential without provisions addressing:   
(a) the application process, study procedures, and ongoing operational 
requirements that apply to Eligible Customers seeking transmission service 
on behalf of large loads;  
(b) additional transparency concerning the Network Upgrade14 costs to 
provide transmission service to Eligible Customers on behalf of large loads, 
a pro forma cost recovery agreement between PJM, the relevant 
transmission owner, and Eligible Customer taking transmission service on 
behalf of the large load to mitigate the risk of cost shifting among 
transmission customers, and a mechanism to ensure such payments are 
appropriately credited toward transmission owners’ transmission revenue 
requirements consistent with the Commission’s cost-of-service regulations;   
(c) transmission services that reflect Eligible Customers taking transmission 
service on behalf of flexible large loads that are willing and able to limit 
their use of the transmission system under certain conditions;15 and 
 
13 Transmission Owners refers to the entities listed in the caption of this order.  We 
recognize that PJM’s transmission owners include entities that are not subject to the 
Commission’s jurisdiction because they are not public utilities pursuant to section 201(f) 
of the FPA.  See 16 U.S.C. § 824(f); Sw. Power Pool, Inc., 180 FERC ¶ 61,022,                      
at PP 44-45 (2022).  Accordingly, the Commission has not included AMP Transmission, 
LLC; City of Cleveland, Department of Public Utilities, Division of Cleveland Public 
Power; City of Hamilton, OH; East Kentucky Power Cooperative, Inc.; and Southern 
Maryland Electric Cooperative, Inc. here as Transmission Owners that must respond to 
this order to show cause.  Nonetheless, the Commission retains the authority to review 
each entity’s formula rates as a component of PJM’s Tariff in an order to show cause 
directed towards PJM, and PJM must respond to this order regarding the non-public 
utilities’ PJM Tariff provisions on file with the Commission.  See Sw. Power Pool, Inc., 
180 FERC ¶ 61,022 at P 40. 
14 Capitalized terms not otherwise defined herein have the meanings ascribed to 
them in the Tariff. 
15 As explained below, for purpose of this order, “flexible” large loads are a subset 
of large loads, as used in this order, that are not co-located with generation, but are

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(d) the rates, terms, and conditions of service applicable to interconnection 
customers serving electrically proximate large load or co-located load; or  
(2) explain what changes to the Tariff would remedy the identified concerns if the 
Commission were to determine that the Tariff has in fact become unjust and 
unreasonable or unduly discriminatory or preferential and, therefore, proceeds to 
establish a replacement Tariff.  
 
We are also concerned with PJM’s need to ensure adequate generation to serve 
new large loads.16  We therefore direct PJM to submit, within 30 days of the date of 
issuance of this order, an informational report on how PJM intends to ensure that 
adequate generation will be available to serve existing and new large loads, as detailed 
later in this order.   
 
We recognize that large loads, including data centers, are actively working with 
transmission owners and other relevant entities to interconnect to, and to take service 
from, the transmission system.  We appreciate that different large loads are currently at 
different stages of that process.  We also understand that large loads and Eligible 
Customers taking transmission service on behalf of large loads are negotiating, entering 
into, and/or have executed various agreements related to interconnecting to the 
transmission system and/or the provision of transmission service.  This proceeding is not 
intended to disrupt existing commercial arrangements, but rather to establish prospective 
reforms.  Accordingly, any Tariff revisions offered by PJM and/or the Transmission 
Owners in response to this proceeding should (a) propose a reasonable implementation 
period to ensure minimal disruption to such existing commercial arrangements, and (b) 
allow a reasonable amount of time to finalize ongoing agreements that are nearing 
completion as of the date such Tariff provisions are filed with the Commission.  Such 
proposed Tariff revisions should include a reasonable effective date that accommodates 
such considerations regarding these existing commercial arrangements. 
 
willing and able to limit their energy withdrawals from the transmission system under 
certain conditions.  See infra note 178. 
16 Cf. PJM Co-Location Order, 193 FERC ¶ 61,217 at PP 237-239 (highlighting 
PJM’s ongoing Critical Issue Fast Path stakeholder process to consider proposals to help 
integrate large load additions without causing resource inadequacy and directing an 
informational report on the status of those proposals).

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I. 
Background 
A. 
Growth of Large and Co-Located Loads and ANOPR 
 
As the Secretary explained in the ANOPR, electricity demand in the United States 
is expected to grow at an extraordinary pace in the near term, largely due to the rapid 
growth of large loads.17  The Secretary highlighted findings from the North American 
Electric Reliability Corporation (NERC) that show that demand growth is now higher 
than at any point in the past two decades, driven in part by increasing quantities of large 
commercial and industrial load, most notably data centers, connecting rapidly to the 
transmission system.18  The Secretary also highlighted NERC’s conclusion that the size 
and speed with which data centers can be connected to the grid present unique challenges 
for demand forecasting and system planning.  The ANOPR proposed that, in light of the 
unprecedented current and expected growth of large loads seeking to interconnect to the 
transmission system, the Commission should standardize interconnection procedures and 
agreements for large loads, including those that seek to share a point of interconnection 
with new or existing generation facilities.19 
 
On April 16, 2026, the Commission issued an order regarding its intent to act with 
respect to the ANOPR docket.20  In that order, the Commission explained that it agreed 
with the Secretary “that, ‘[i]n light of the unprecedented current and expected growth of 
large loads’ such as data centers, there is an urgent need for thoughtful reforms to ensure 
that large loads are ‘able to connect to the transmission system in a timely, orderly, and 
 
17 ANOPR at 2 (citing U.S. Dep’t of Energy, Resource Adequacy Report: 
Evaluating the Reliability & Security of the United States Electric Grid (July 2025), 
www.energy.gov/sites/default/files/2025-
07/DOE%20Final%20EO%20Report%20%28FINAL%20JULY%207%29.pdf). 
18 Id. (citing NERC, 2024 Long- Term Reliability Assessment 8 (Dec. 2024, 
updated July 2025), 
https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_Long%2
0Term%20Reliability%20Assessment_2024.pdf). 
19 Id. P 12.  For example, the ANOPR proposed that load and hybrid facilities 
should be studied together with generating facilities, observing that “siting a large load 
near or at the same point of interconnection as a new generating facility could reduce the 
network upgrades needed to interconnect only the load or only the generating facility.”  
ANOPR at P 20. 
20 Interconnection of Large Loads to the Interstate Transmission Sys., 195 FERC    
¶ 61,045 (2026) (Order Regarding Intent to Act).

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non-discriminatory manner.’”21  After recognizing the Commission’s recent actions in 
proceedings involving issues associated with large loads,22 the Commission concluded 
that it was clear that additional “action is warranted to support further progress where it is 
needed.”23 
 
PJM’s load forecast predicts peak load growth of 32 gigawatts (GW) from 2024 to 
2030, 30 GW of which is projected to be from data centers.24  Many commenters in the 
ANOPR proceeding highlight the unprecedented load growth in PJM associated with 
large loads.  For example, AES Ohio currently forecasts over 6.3 GW of new load by 
2032, which will nearly triple AES Ohio’s current peak.25  Exelon states that, in 
ComEd’s service territory, data center demand has grown at an annual rate of 27% 
through                June 2025, and ComEd’s most recent large load adjustment request to 
PJM included a future expected demand increase of 11 GW by 2040, 6 GW higher than 
ComEd’s submission relative to the prior year.26  WATT and Advancing Modern 
Powerlines note that PJM is expected to host as much as 70% of future U.S. data center 
development and that this concentration of demand, especially in northern Virginia’s 
“data center alley,” is creating intense pressure for new greenfield transmission to support 
 
21 Id. P 2. 
22 Id. (citing PJM Co-Location Order, 193 FERC ¶ 61,217; SPP HILL Order,               
194 FERC ¶ 61,031; Commonwealth Edison Co., 194 FERC ¶ 61,181; Tri-State 
Generation & Transmission Ass’n, 193 FERC ¶ 61,070 (2025); Duke Energy Carolinas, 
LLC, 193 FERC ¶ 61,237). 
23 Id. PP 3-4. 
24 Letter from David E. Mills, PJM Board of Managers Chair, PJM, 
Interconnection, L.L.C. to PJM Stakeholders (Aug. 8, 2025), https://www.pjm.com/-
/media/DotCom/about-pjm/who-we-are/public-disclosures/2025/20250808-pjm-board-
letter-re-implementation-of-critical-issue-fast-path-process-for-large-load-additions.pdf 
(PJM Board Letter).  Since the issuance of the PJM Board Letter, PJM has published its 
2026 Long-Term Load Forecast Report, which anticipates lower peak demand in the near 
term due to forecasting improvements, revising the peak load forecast for 2030 
downward by 875 MW, but confirms significant growth in the next 20 years.  PJM, 
PJM’s Updated 20-Year Forecast Continues to See Significant Long-Term Load Growth 
(Jan. 14, 2026), https://insidelines.pjm.com/pjms-updated-20-year-forecast-continues-to-
see-significant-long-term-load-growth/. 
25 AES November 21 ANOPR Comments at 4. 
26 Exelon November 21 ANOPR Comments at 2.

Docket No. EL26-67-000 
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the interconnection of data centers.27  Buckeye states that load growth of approximately 
10 GW driven largely by data centers in the Dominion Zone of PJM resulted in 
approximately                     $12 billion in transmission investment across PJM.28   
 
A number of commenters in the ANOPR proceeding assert that large load 
additions have caused growing resource adequacy, reliability, and affordability problems 
in PJM.29  Commenters also argue that large load interconnection in PJM is experiencing 
significant delays.30  In addition, Buckeye and Southeast PIOs express concern that 
infrastructure costs driven by data center loads will be borne by all transmission 
customers in the corresponding PJM transmission zones and, where applicable, in the 
broader PJM region.31  They and other commenters argue that wholesale transmission 
customers are at risk of absorbing cost shifts and that retail large load tariffs do not 
protect wholesale transmission customers from cost shifting.32  Vistra also raises 
concerns that PJM and transmission owners’ processes for determining Network 
 
27 WATT and Advancing Modern Powerlines November 21 ANOPR Comments    
at 4. 
28 Buckeye November 21 ANOPR Comments at 6. 
29 See, e.g., ECA November 21 ANOPR Comments at 8; Geronimo November 21 
ANOPR Comments at 7; Illinois AG November 21 ANOPR Comments at 5-6; Joint 
Consumer Advocates November 21 ANOPR Comments at 2; OCC November 21 
ANOPR Comments at 6-7; PIOs November 21 ANOPR Comments at 3-5, 13-14; PJM 
IMM November 25 ANOPR Comments, Attach. A at 3-5.  
30 International Energy Credit Association November 21 ANOPR Comments at 6; 
Constellation November 21 ANOPR Comments at 2, 49-51. 
31 See, e.g., Buckeye November 21 ANOPR Comments at 8; Southeast PIOs 
November 21 ANOPR Comments at 10-11 (asserting that there is a significant overlap 
between multi-driver projects that may be driven by increased loads, including data 
centers, and those transmission projects selected in PJM’s recent RTEP solicitation). 
32 See, e.g., APPA November 21 ANOPR Comments at 6 (“Wholesale 
transmission customers in particular could be left shouldering massive costs if new large 
loads do not ultimately attain or maintain the level of electricity demand that is being 
forecasted.”); NRECA November 21 ANOPR Comments at 21 (noting the risk that other 
transmission customers could bear stranded upgrade costs caused by large loads that they 
cannot absorb); TAPS November 21 ANOPR Comments at 26 (“[A] number of state 
commissions are moving forward with retail large load tariffs, which provide for varying 
protections, but may not require the revenues and minimum demand levels to be included 
in wholesale transmission rates.”).

Docket No. EL26-67-000 
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Upgrades are not included in the Tariff and that existing transmission customers may be 
disproportionately shouldering the costs for interconnecting large loads.33  OCC requests 
that the Commission provide additional transparency regarding large load additions.34  
Commenters also support reforms to capture the efficiencies of generation paired with 
electrically proximate large load.35 
 
Moreover, many commenters in the ANOPR proceeding filed persuasive 
comments documenting, generally, the need for clear and consistent tariff provisions to 
ensure regulatory and process certainty, fairness and consistency, and efficiency as large 
loads are added to the transmission system in increasing numbers.36  There is also broad 
support for rules that help to ensure that other transmission customers are not unfairly 
burdened with additional costs or reliability impacts as large loads interconnect to the 
transmission system.37  In addition, many ANOPR commenters highlighted the need to 
 
33 Vistra November 21 ANOPR Comments at 22-23. 
34 OCC November 21 ANOPR Comments at 3-4. 
35 See, e.g., AEP December 5 ANOPR Comments at 10-12; Exelon November 21 
ANOPR Comments at 14; Illinois AG November 21 ANOPR Comments at 8. 
36 See, e.g., AI Supply Chain Alliance November 21 ANOPR Comments at 2; 
Calibrant November 21 ANOPR Comments at 1-3; CEBA November 21 ANOPR 
Comments at 9-11; Constellation November 21 ANOPR Comments at 6; DCC   
November 21 ANOPR Comments at 3-4; ECA November 21 ANOPR Comments                
at 7-11; EPSA November 21 ANOPR Comments at 4-6; Infrastructure Masons  
December 5 ANOPR Comments at 4-7; Microsoft November 21 ANOPR Comments          
at 9-10; National Grid November 21 ANOPR Comments at 7; ODEC December 5 
ANOPR Comments at 2-4; R Street November 21 ANOPR Comments at 3; Switch 
December 5 ANOPR Comments at 3; Tract November 21 ANOPR Comments at 5; 
Vantage November 21 ANOPR Comments at 5-6; Vistra December 5 ANOPR 
Comments at 1-2. 
37 See, e.g., APPA November 21 ANOPR Comments at 6; Buckeye November 21 
ANOPR Comments at 17; Exelon November 21 ANOPR Comments at 10; Kansas 
Commission November 21 ANOPR Comments at 12; NCSL November 21 ANOPR 
Comments at 1; NRECA November 21 ANOPR Comments at 8-9; NY UIU                 
November 21 ANOPR Comments at 3; OCC November 21 ANOPR Comments at 9; 
Oklo December 5 ANOPR Comments at 3; Southeast PIOs December 5 ANOPR 
Comments 11-15; State Entities November 21 ANOPR Comments at 7-8; Tri-State 
November 21 ANOPR Comments at 8; UCS November 21 ANOPR Comments at 9-11; 
U.S. Representatives November 21 ANOPR Comments at 1.

Docket No. EL26-67-000 
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efficiently integrate large loads, particularly data centers, to support national security 
priorities and economic development.38    
B. 
Recent Proceedings Addressing Large and Co-Located Loads 
 
Over the past year, the Commission has begun to address, both sua sponte and in 
response to complaints and FPA section 20539 filings, the growing use of co-location 
arrangements.40  The Commission’s orders in those proceedings have addressed the need 
for clear and consistent tariff provisions regarding the rates, terms, and conditions of 
service that apply to co-location arrangements and for transmission services that reflect 
Eligible Customers taking transmission service on behalf of co-located loads and load 
with behind the meter generation that are willing and able to limit their energy 
withdrawals from the transmission system under certain conditions.  Several other 
Commission proceedings have addressed the challenges of integrating large loads onto 
the transmission system, including the need for clear and consistent tariff provisions 
regarding the provision of transmission service to Eligible Customers on behalf of large 
loads and for interconnection customers serving electrically proximate large load.  As 
explained below, these proceedings provide examples that will help to ensure that 
jurisdictional transmission service is provided in a manner that is just and reasonable and 
maintains reliability as large loads are integrated onto the transmission system and                  
co-location arrangements become more common.  It is in this context, and in recognition 
of the steps PJM has taken with respect to co-location arrangements, that the Commission 
now considers whether PJM’s Tariff remains just and reasonable. 
1. 
PJM Co-Location Proceedings 
 
On February 20, 2025, the Commission initiated a show cause proceeding against 
PJM and the PJM Transmission Owners regarding the lack of tariff provisions addressing 
with sufficient clarity or consistency the rates, terms, and conditions of service that apply 
 
38 See, e.g., AI Supply Chain Alliance November 21 ANOPR Comments at 2; 
DCC November 21 ANOPR Comments at 3; ECA November 21 ANOPR Comments             
at 6; Geronimo November 21 ANOPR Comments at 1-2; Google November 21 ANOPR 
Comments at 2-3; Verrus December 5 ANOPR Comments at 2. 
39 16 U.S.C. § 824d. 
40 See PJM Show Cause Order, 190 FERC ¶ 61,115; PJM Co-Location Order,                  
193 FERC ¶ 61,217, order on reh’g, PJM Co-Location Rehearing Order, 195 FERC                 
¶ 61,209; SPP HILL Order, 194 FERC ¶ 61,031; SPP CHILLS Order, 195 FERC                      
¶ 61,196.

Docket No. EL26-67-000 
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to co-location arrangements.41  The Commission explained when initiating that 
proceeding that the absence of such provisions may leave entities unable to determine 
what steps they can or must take to effectuate co-location arrangements of various 
configurations and how to do so in a manner that is just and reasonable.42  On               
December 18, 2025, the Commission found that PJM’s Tariff was indeed unjust and 
unreasonable because it does not contain provisions addressing with sufficient clarity or 
consistency the rates, terms, and conditions of service that apply to interconnection 
customers serving co-located load and Eligible Customers taking transmission service on 
behalf of co-located load.43   
 
Specifically, the Commission found that the PJM Tariff was unjust and 
unreasonable because there is a lack of sufficient clarity or consistency as to the rates, 
terms, and conditions of service that apply to interconnection customers serving                      
co-located load.44  The Commission also found that PJM’s Tariff was unjust and 
unreasonable because it does not include transmission services that reflect Eligible 
Customers taking transmission service on behalf of co-located loads that are willing and 
able to limit their energy withdrawals from the transmission system under certain 
conditions.45  Additionally, the Commission found that PJM’s behind the meter 
generation rules were no longer just and reasonable.46  The Commission directed PJM to 
file a compliance filing to revise its Tariff:  (1) to set forth specific terms and conditions 
that an interconnection customer in PJM seeking to serve co-located load must follow in 
order to effectuate a co-location arrangement;47 (2) to require that the Eligible Customer 
taking transmission service on behalf of co-located load takes one of three transmission 
services:  (a) network integration transmission service (NITS) or a new interim, non-firm 
transmission service while Network Upgrades to provide full NITS service are 
 
41 See PJM Show Cause Order, 190 FERC ¶ 61,115. 
42 Id. P 74.  The PJM Show Cause Order defined co-located load as a 
“configuration [that] refers to end-use customer load that is physically connected to the 
facilities of an existing or planned Customer Facility on the Interconnection Customer’s 
side of the Point of Interconnection (‘POI’) to the PJM Transmission System.”  Id. P 3 
n.4.   
43 PJM Co-Location Order, 193 FERC ¶ 61,217. 
44 Id. P 176.  
45 Id. P 177. 
46 Id. P 179. 
47 Id. PP 187-192, 225-230.

Docket No. EL26-67-000 
- 15 - 
constructed (interim NITS); (b) a new firm contract demand transmission service; or (c) a 
new non-firm contract demand transmission service;48 (3) to revise the behind the meter 
generation rules and implement a transition process for existing behind the meter 
generation participants;49 and (4) to make several clarifications on how certain aspects of 
PJM’s generator interconnection process apply to interconnection customers seeking to 
serve co-located load.50 
 
On June 18, 2026, concurrently with the instant order, the Commission issued an 
order modifying the discussion in the PJM Co-Location Order and setting aside the order 
in part; accepting in part and rejecting in part PJM’s compliance filing, and directing a 
further compliance filing; and establishing as just and reasonable certain rates, terms, and 
conditions for the new transmission services (i.e., interim NITS, firm contract demand 
transmission service, and non-firm contract demand transmission service).51 
2. 
SPP High Impact Large Load Process and High Impact Large 
Load Generation Assessment Processes 
 
On January 14, 2026, the Commission accepted revisions to SPP’s tariff to add a 
high impact large load (HILL) study process and High Impact Large Load Generation 
Assessment (HILLGA) process.52  SPP’s tariff revisions established HILLs as a new 
category of load;53 imposed enhanced study requirements to enable SPP to assess the 
 
48 Id. PP 193-218.  The Commission also established a paper hearing to determine 
the just and reasonable rates, terms, and conditions for the new transmission services.  Id. 
PP 219-220. 
49 Id. PP 221-224.  
50 Id. PP 161, 231-236. 
51 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at PP 7-9.  PJM’s 
compliance filing proposing revisions in response to the Commission’s directives 
regarding clarification that certain aspects of PJM’s generator interconnection process 
apply to interconnection customers seeking to serve co-located load was accepted in part 
on April 16, 2026.  PJM Interconnection, L.L.C., 195 FERC ¶ 61,030 (2026). 
52 SPP HILL Order, 194 FERC ¶ 61,031 at PP 61, 64.   
53 SPP defines a HILL as:   
A new commercial or industrial load, or increase in 
commercial or industrial load, at a single site connected 
through one or more shared Points of Interconnection (POIs) 
or delivery points, where such load is either:  (1) 10 MW or

Docket No. EL26-67-000 
- 16 - 
HILL’s reliability impacts on the transmission system;54 and created additional, ongoing 
operational requirements for transmission customers serving HILLs to ensure continued 
reliability of the transmission system.55  The tariff revisions also established the HILLGA 
process, a new generator interconnection service and related interconnection process to 
facilitate the prompt interconnection of generating facilities that are specifically identified 
for, and limited to, serving a HILL and are located no more than two substations away 
from the HILL.56   
 
more if connected to the Transmission System at a voltage 
level less than or equal to 69 [kilovolts (kV)]; or (2) 50 MW 
or more if connected to the Transmission System at a voltage 
level greater than 69 kV.  An Electric Storage Resource is not 
considered a HILL.  
SPP, Open Access Transmission Tariff, Sixth Revised Vol. No. 1, pt. I, § 1                
(Definitions H) (1.0.0). 
54 SPP HILL Order, 194 FERC ¶ 61,031 at PP 13-17 (explaining that the HILL 
process requires up to three additional studies beyond those required of all transmission 
service requests for transmission customers requesting to add or modify a delivery point 
associated with a HILL, including a HILL delivery point study, HILL supplemental load 
connection study, and potential supplemental Electromagnetic Transient study). 
55 Id. P 18 (explaining that market participants registering a HILL must:                       
(1) follow all nonconforming load requirements (e.g., additional load forecast 
requirements); (2) provide load data via telemetry in real time; (3) have remote capability 
to disconnect the load from the transmission system made available to the transmission 
operator; (4) have an up/down ramp rate not exceeding 20 MW per minute unless 
otherwise directed; (5) include additional information with registration; and (6) not have 
withdrawals from the transmission system without appropriate transmission service); id. 
P 19 (explaining that the transmission owner, at the transmission customer’s expense, 
must install a phasor measurement unit or similar equipment); id. PP 20-21 (explaining 
that the transmission customer will be required to comply with ride-through requirement 
guidelines). 
56 Id. P 27 (explaining that, under the HILLGA process, SPP proposes to study 
HILLGA requests to determine whether any network upgrades are needed to 
accommodate the generating facility’s injection to the local area); id. P 32 (explaining 
that SPP will grant HILLGA customers a new type of interconnection service, load 
limited resource interconnection service, which grants limited interconnection service 
solely to serve the associated HILL).

Docket No. EL26-67-000 
- 17 - 
 
The Commission stated that SPP demonstrated that the “unprecedented growth in 
large loads in the SPP region presents significant and unique operational and planning 
challenges.”57  The Commission found that SPP demonstrated that its proposed HILL 
process was a just and reasonable approach for integrating transmission customers’ new 
large loads onto SPP’s transmission system in a reliable manner.58  The Commission 
found that it was reasonable to impose additional study requirements and other proposed 
requirements given the unique operating characteristics of HILLs.  The Commission 
further found that the proposed study requirements would ensure the reliable integration 
of the transmission customer’s HILLs onto SPP’s transmission system and would provide 
SPP with information about their impact on SPP’s transmission system, including the 
transmission system’s ability to withstand and control disturbances by the HILL at the 
point of interconnection.59  In addition, the Commission found that the proposed study 
deposits would discourage speculative HILL study requests.60  Finally, the Commission 
concluded that the proposed ongoing reliability requirements would allow SPP to 
maintain reliable operation of its transmission system by increasing SPP’s visibility, 
providing necessary data, and imposing real-time operational safeguards for HILLs.61  In 
accepting HILLGA, the Commission found that “SPP’s HILLGA process reasonably 
provides a flexible, expedited, and separate serial interconnection process that will 
facilitate the prompt interconnection of generating facilities that are limited to serving a 
HILL in the same local area.”62   
3. 
SPP Conditional High Impact Large Load Service 
 
On June 5, 2026, the Commission accepted revisions to SPP’s tariff to add a new 
type of non-firm transmission service, conditional high impact large load service 
 
57 Id. P 60. 
58 Id. P 61. 
59 Id. P 62. 
60 For the HILL delivery point study, SPP required a $10,000 non-refundable 
application fee and a $100,000 study deposit, with an additional $200,000 study deposit if 
an Electromagnetic Transient study was also required.  Id. P 15.  For the HILL 
supplemental load connection study, SPP allows the host transmission owner to require a 
$25,000 study deposit.  Id. P 16. 
61 Id. P 63. 
62 Id. P 64.

Docket No. EL26-67-000 
- 18 - 
(CHILLS).63  CHILLS allows transmission customers serving HILLs to reliably receive 
transfers of energy until sufficient designated resources and/or network upgrades are in 
place to support long-term, firm transmission service.64  CHILLS is an as-available 
transmission service that will transfer energy to designated points of delivery to serve the 
portion of a HILL eligible to receive CHILLS, subject to curtailment and interruption.65  
CHILLS has a maximum term of seven years, which is intended to incentivize 
transmission customers seeking CHILLS to obtain the designated resources and/or 
complete the network upgrades needed to procure long-term firm transmission service 
through existing tariff processes.66   
 
The Commission found that SPP had shown that unprecedented growth in large 
loads presents significant and unique operational and planning challenges.67  The 
Commission also found that SPP’s ability to add HILLs to its transmission system in a 
timely manner may be limited due to delays in obtaining sufficient designated resources 
and completing network upgrades needed to provide long-term firm transmission service 
to such load.68  The Commission concluded that CHILLS is a just and reasonable and not 
unduly discriminatory or preferential approach to addressing the need to expeditiously 
interconnect and provide transmission service to new HILLs, while maintaining the 
reliable operation of SPP’s transmission system.69 
II. 
PJM’s Existing Processes 
A. 
Existing Tariff Processes 
 
PJM’s Tariff sets forth a process by which an Eligible Customer may request 
either NITS,70 including modifications to existing service agreements to add new 
 
63 SPP CHILLS Order, 195 FERC ¶ 61,196 at P 1. 
64 Id. P 7.  
65 Id. PP 9-10. 
66 Id. P 9. 
67 Id. P 84. 
68 Id. 
69 Id. 
70 NITS is a transmission service that allows Network Customers to use their 
Network Resources (as well as other non-designated generation resources) to serve their

Docket No. EL26-67-000 
- 19 - 
Network Loads, or Point-to-Point Transmission Service.71  In the PJM Co-Location 
Order, the Commission also directed PJM to create three new transmission services that 
an Eligible Customer taking transmission service on behalf of co-located load may take:  
(1) an interim, non-firm transmission service until all Network Upgrades necessary to 
provide the requested NITS are complete, (2) a new Firm Contract Demand transmission 
service, and (3) a new Non-Firm Contract Demand transmission service.72   
 
In PJM, new load additions are processed in one of two ways:  (1) an Eligible 
Customer requesting new transmission service submits a Transmission Service Request 
to PJM; or (2) for existing Network Customers adding new Network Loads, the Network 
Customer provides PJM with notice of the designation of new Network Load and must 
modify its existing service agreement accordingly.73  For NITS and Firm Point-to-Point 
Transmission Service Requests, PJM determines whether a Phase I System Impact 
Study74 is needed to assess whether the transmission system has sufficient available 
capability to provide the requested service and tenders an Application and Studies 
 
Network Load located in the PJM region and designated additional loads.  PJM Tariff,   
pt. III, § 28.1 (Scope of Service) (1.0.0).   
71 Point-to-Point Transmission Service provides for “the reservation and 
transmission of capacity and energy on either a firm or non-firm basis from the Point(s) 
of Receipt to the Point(s) of Delivery.”  Id. pt. I, § 1 (Definitions O-P-Q) (36.0.0) 
(definition of Point-to-Point Transmission Service). 
72 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 160. 
73 PJM Tariff, pt. III, § 31.2 (New Network Loads Connected With the 
Transmission Provider) (1.0.0).  To the extent that a Network Customer seeks to add a 
new Delivery Point or interconnection point between the PJM transmission system and a 
Network Load, the Network Customer must provide PJM with as much advance notice as 
reasonably practicable.  Id. pt. III, § 31.4 (New Interconnection Points) (0.0.0). 
74 PJM’s study process for New Service Requests consists of Phase I, II, and III 
System Impact Studies.

Docket No. EL26-67-000 
- 20 - 
Agreement75 to initiate a New Service Request pursuant to which the Eligible Customer 
agrees to reimburse PJM for the required Phase I System Impact Study.76   
 
PJM studies all New Service Requests including generator interconnection 
requests, merchant transmission interconnection requests, and long-term firm 
transmission service requests77 in a single queue (New Services Queue), which is 
governed by the transitional interconnection process in Part VII of the Tariff (for requests 
submitted between April 1, 2018 and September 30, 2021, where an Interconnection 
Customer does not have an Interconnection Service Agreement as of July 10, 2023), and 
the new cycle interconnection process in Part VIII of the Tariff (“new rules” for valid 
New Service Requests submitted on or after October 1, 2021).78  PJM’s New Services 
 
75 PJM’s Tariff defines an “Application and Studies Agreement” as the application 
that must be submitted by a Project Developer or Eligible Customer that seeks to initiate 
a New Service Request.  PJM Tariff, pt. VII, § 300 (Definitions A) (3.0.0); id. pt. VIII, 
§ 400 (Definitions A) (2.0.0). 
76 Id. pt. III, § 32.1 (Notice of Need for Phase I System Impact Study) (2.0.0); id. 
pt. II , § 19.1 (Notice of Need for Phase I System Impact Study) (4.0.0).  As the RTO, 
PJM administers the interconnection of generating facilities and Merchant Transmission 
Facilities, requests for transmission service, and upgrades to existing transmission owner 
facilities in the PJM transmission system through the New Service Requests process.  
PJM Manual 14H: New Service Requests Cycle Process, § 1.1 (Sep. 2025), 
https://www.pjm.com/-/media/DotCom/documents/manuals/m14h.ashx (PJM                  
Manual 14H). 
77 Id. pt. VII, subpt. C, § 306(A)(3) (Application Rules) (1.1.0) (includes specific 
additional application requirements for Long-Term Firm Transmission Service seeking to 
initiate a New Services Request); id. pt. VIII, subpt. B § 403(A)(3) (Application Rules) 
(0.1.0); id., pt. VII, § 300 (Definitions N) (2.0.0) (definition of New Service Request); id. 
pt. VIII, § 400 (Definitions N) (2.0.0) (definition of New Service Request); see also id. 
pt. VII, § 300 (Definitions C) (2.0.0) (definition of Completed Application); id. pt. VII, 
§ 300 (Definitions I) (2.0.0) (definition of Interconnection Request); id. pt. VIII, § 400 
(Definitions C) (2.0.0) (definition of Completed Application); id. pt. VIII, § 400 
(Definitions I) (2.0.0) (definition of Interconnection Request); id. pt. I, § 1                    
(Definitions A-B) (19.1.1) (definition of Application). 
78 See id. pt. VII, § 301 (Transition Introduction) (1.0.0) (“Part VII sets forth the 
procedures and other terms governing the Transmission Provider’s administration of the 
transition to the new Cycle-process, including procedures and other terms regarding 
studies and other processing of New Service Requests within the Transition Cycle”); id. 
pt. VIII, § 401 (Applications for Cycle Process Intro) (2.0.0); id. pt. VIII, § 401(A) (New 
Cycle Process) (2.0.0) (“Part VIII of the Tariff applies to valid New Service Requests

Docket No. EL26-67-000 
- 21 - 
Queue is a first-ready, first-served clustered cycle approach that consists of an application 
phase, a three-phase study process, where each phase includes a System Impact Study 
and decision point, and a final agreement negotiation phase.  For transmission service 
requests, once the New Service Request is processed, the transmission customer will 
enter into a transmission service agreement, a construction service agreement, and/or a 
Network Upgrade cost responsibility agreement.  PJM’s Tariff does not have any specific 
study provisions or requirements for Eligible Customers requesting transmission service 
on behalf of large load additions.   
 
The system impact study is an assessment by PJM of:  (1) the adequacy of the 
transmission system to accommodate a New Service Request; (2) whether any additional 
costs may be incurred in order to provide such transmission service or to accommodate a 
New Service Request; and (3) an estimated date that the New Service Requests can be 
interconnection with the transmission system and an estimate of the cost responsibility 
for the interconnection of the New Service Request.79  The System Impact Studies also 
provide “estimates of cost responsibility and construction lead time for new facilities 
required to interconnect the project and required system upgrades,”80 including Network 
Upgrades.  The Tariff describes the phases and studies that determine the cost allocation 
of Network Upgrades to New Service Requests, and PJM Manual 14H provides the 
implementation details used to govern the interconnection and transmission customers 
service request process for new generating facilities seeking to connect to or use the PJM 
transmission system through PJM’s cluster-based queue methodology.81  Specifically, the 
 
submitted on or after October 1, 2021, and sets forth the . . . procedures and other terms 
regarding studies and other processing of New Service Requests”); id. pt. VIII, § 401(B) 
(Applications for Cycle Process) (2.0.0) (“Part VIII of the Tariff applies to (a) Generation 
Interconnection Requests; (b) Transmission Interconnection Requests; and (c) Completed 
Applications”). 
79 Id. pt. VIII, § 400 (Definitions S) (3.0.0) (definition of System Impact Study).  
The System Impact Study includes facilities study analysis.  
80 Id. pt. VII, subpt. D, § 307 (Introduction) (1.0.0); id. pt. VII, subpt. D, 
§ 307(A)(2)(a)(ii) (Overview of System Impact Studies) (1.0.0); id. pt. VIII, subpt. C, 
§ 404 (Introduction) (1.0.0); id. pt. VIII, subpt. C, § 404(2)(a)(ii) (Introduction) (1.0.0). 
81 See id. pt. VII, subpt. D § 307 (Introduction) (1.0.0) (including a description of 
the phases and an overview of the System Impact Studies and cost allocation of Network 
Upgrades, noting that the cost allocation will be in accordance with PJM Manuals); id. pt. 
VII, subpt. D § 307(A)(5)(c) (Cost Allocation for Network Upgrades) (1.0.0); id. pt. VIII, 
subpt. C, § 404 (Introduction) (1.0.0), id. pt. VIII, subpt. C, § 404(A)(5)(c) (Cost 
Allocation for Network Upgrades) (1.0.0); see PJM Manual 14H: New Service Requests

Docket No. EL26-67-000 
- 22 - 
Tariff provides that each “Eligible Customer shall be obligated to pay for 100% of the 
costs of the minimum amount of Network Upgrades necessary to accommodate its New 
Service Request and that would not have been incurred under the Regional Transmission 
Expansion Plan [(RTEP)] but for such New Service Request, net of benefits resulting 
from the construction of the upgrades, such costs not to be less than zero.”82  The Tariff 
further specifies that “[a]ll New Service Requests that contribute to the need for a 
Network Upgrade will receive cost allocation for that upgrade pursuant to each New 
Service Request’s contribution to the reliability violation identified on the transmission 
system in accordance with PJM Manuals.”83 
 
As relevant on the generator interconnection side, pursuant to the Tariff, a Project 
Developer may request, and PJM may provide, Provisional Interconnection Service for 
limited interconnection service at the discretion of PJM based upon an evaluation that 
will consider the results of available studies.84  PJM determines, through available studies 
or additional studies as necessary, “whether stability, short circuit, thermal, and/or 
voltage issues would arise” if the Project Developer interconnects without modifications 
to the Generating Facility or the transmission system.85  Under the Tariff, a Project 
Developer may also request surplus interconnection service for an unneeded portion of 
interconnection service capacity at an existing point of interconnection.86  The surplus 
interconnection study consists of reactive power, short circuit/fault duty, stability analysis 
and any other appropriate analyses, and steady-state (thermal/voltage) analyses may be 
 
Cycle Process, § 4.2.6 (Sep. 2025), https://www.pjm.com/-
/media/DotCom/documents/manuals/m14h.ashx (PJM Manual 14H). 
82 PJM Tariff, pt. VII, subpt. D, § 307(A)(5)(a) (Cost Allocation for Network 
Upgrades) (1.0.0); id. pt. VIII, subpt. C, § 404 (A)(5)(a) (Cost Allocation for Network 
Upgrades) (1.0.0). 
83 Id. pt. VII, subpt. D, § 307(A)(5)(c) (Cost Allocation for Network Upgrades) 
(1.0.0); id. pt. VIII, subpt. C, § 404 (A)(5)(c) (Cost Allocation for Network Upgrades) 
(1.0.0). 
84 Id. pt. IX, subpt. B, app. 2, § 1.4A.2 (Provisional Interconnection Service) 
(0.0.0). 
85 Id. 
86 Id. pt. VIII, subpt. E, § 414(A) (Surplus Interconnection Service Request) 
(1.0.0).

Docket No. EL26-67-000 
- 23 - 
performed as necessary to ensure that all required reliability conditions are studied under 
off-peak conditions.87 
 
In PJM, electric distribution companies and transmission owners administer load 
interconnection processes for existing Network Customers, and transmission owners 
perform local transmission planning to accommodate load additions.88  PJM, as 
transmission provider, conducts additional studies and transmission planning activities to 
support load additions.  Requests to physically interconnect loads are submitted to 
transmission owners, who have their own study processes and requirements.  Some 
transmission owners have established specific large load interconnection procedures and 
requirements.89  New loads taking bundled retail service from a transmission owner or 
that are served subject to state-required retail access programs (Native Load) are studied 
through transmission owners’ local transmission planning processes.  Transmission 
owners must designate resources and loads to serve Native Load in the same manner as 
any Eligible Customer.90   
 
Network Upgrades identified in transmission owners’ local transmission planning 
process as needed to accommodate load additions are designated as Supplemental 
Projects under Attachment M-3 of PJM’s Tariff.91  Under Attachment M-3, transmission 
owners plan for the local transmission needs of their own transmission systems.  
Attachment M-3 provides procedures for stakeholder review and comment on 
Supplemental Projects in the Transmission Expansion Advisory Committee (230 kV or 
above) and Subregional RTEP Committee (below 230 kV) and as part of a transmission 
 
87 Id. pt. VIII, subpt. E, § 414(B)(1) (Surplus Interconnection Study) (1.0.0). 
88 See PJM November 21 ANOPR Comments at 6. 
89 See, e.g., EEI March 12 ANOPR Comments at 13 (“In December 2025, Exelon 
subsidiary Delmarva Power submitted proposed changes in line with the Commission’s 
November 2025 order: a new service class ‘GS-LD’ applicable to large demand 
customers with a monthly maximum of 25 MW or greater.  The company also proposed 
implementing an application process and specific requirements for potential customers 
with a projected load of at least 50 MW.”); id. (“Exelon subsidiary Commonwealth 
Edison Company (ComEd) has proposed revisions to Rider DE that clarify requirements 
and procedures for large load customers' new service requests.”).   
90 PJM Tariff, pt. III, § 28.2 (Transmission Provider Responsibilities) (1.0.0). 
91 See id. attach. M-3 (Additional Procedures for Planning Supplemental Projects 
and Asset Management Projects) (1.0.0).

Docket No. EL26-67-000 
- 24 - 
owner’s Local Plan, before the Local Plan is submitted for integration into the RTEP.92  
These transmission projects do not qualify for region-wide cost allocation, and PJM 
conducts only a “do no harm” test to ensure that local transmission facilities do not 
adversely impact the reliability of the broader transmission system before the 
Supplemental Projects are added into the RTEP base case.93  Supplemental Project costs 
are allocated to the local transmission owner’s zone pursuant to individual transmission 
owner cost allocation frameworks.94    
 
Attachment H of the PJM Tariff includes the formula rate for each transmission 
owner.  The formula rate calculates the annual transmission revenue requirement, and 
resulting NITS rate, in the relevant PJM transmission zones.  The demand charges for 
NITS, which are charged to the relevant Network Customer (i.e., the Eligible Customer), 
are determined by multiplying the rate for NITS (based on the NITS rate in Attachment H 
of the relevant transmission zone) by the customer’s coincident peak demand.95   
 
In some instances, an aggregation of large loads, coupled with other drivers, could 
trigger regional (as opposed to local) transmission system needs, which would be 
identified and addressed by a regional transmission project in the RTEP, which is subject 
to PJM’s regional cost allocation method.  For example, a transmission owner may 
identify a local transmission need that may be more efficiently or cost-effectively 
addressed by a regional transmission project identified in the RTEP.96   
 
The Tariff includes a hybrid cost allocation method that was accepted as part of 
PJM’s compliance with Order No. 1000 for Regional Facilities and Necessary Lower 
Voltage Facilities that address a reliability need.97  Under this method, PJM allocates 
 
92 See id. § (c) (Procedures for Review of Attachment M-3 Projects). 
93 See PJM Interconnection, L.L.C., Answer, Docket No. EL25-49-000, at 6-7 
(filed Mar. 24, 2025); PJM Manual 14B: PJM Regional Transmission Planning Process,    
§ 1.1 (Apr. 2026), https://www.pjm.com/-
/media/DotCom/documents/manuals/m14b.pdf#page=14. 
94 PJM Interconnection, L.L.C., Answer, Docket No. EL25-49-000, at 7 (filed 
Mar. 24, 2025).    
95 PJM Tariff, pt. III, § 34.1 (Monthly Demand Charge) (1.0.0). 
96 See, e.g., Potomac Edison Co., 190 FERC ¶ 61,074, at PP 5, 22 (2025) 
(allowing for recovery of abandoned plant costs where a local transmission project was 
superseded by regional transmission development in PJM’s RTEP process). 
97 PJM identifies reliability transmission needs and economic constraints that 
result from the incorporation of public policy requirements into its sensitivity analyses

Docket No. EL26-67-000 
- 25 - 
50% of the costs of Regional Facilities or Necessary Lower Voltage Facilities on a              
load-ratio share basis and the other 50% based on the solution-based distribution factor 
(DFAX) method.  PJM allocates all of the costs of Lower Voltage Facilities using the 
solution-based DFAX method.  Cost responsibility assignments pursuant to the Order   
No. 1000-compliant cost allocation method are included in Schedule 12-Appendix A of 
the Tariff.     
 
Schedule 12 of the Tariff provides that cost responsibility for the portion of costs 
allocated on a load-ratio share basis will be updated annually using the applicable zonal 
loads at the time of each zone’s annual peak load from the 12-month period ending 
October 31 of the calendar year preceding the calendar year for which the annual cost 
responsibility assignment is determined, consistent with section 34.1 of the Tariff.98  
 
Schedule 12 of the Tariff also provides that, for the portion of cost responsibility 
assignments allocated pursuant to the solution-based DFAX method, PJM shall make a 
preliminary cost responsibility assignment for each Required Transmission Enhancement 
at the time such transmission facility is selected in the RTEP for purposes of cost 
allocation.  Further, beginning with the calendar year in which a transmission facility is 
scheduled to enter service, and thereafter annually at the beginning of each calendar year, 
PJM shall update the preliminary cost responsibility assignment for each transmission 
facility using the values and inputs used in the base case of the most recent RTEP 
approved by the PJM Board prior to the date of the update.99  
B. 
Recent Stakeholder Proceedings in PJM 
 
PJM has begun considering reforms to address large load additions, including the 
development of solutions to ensure large load additions can continue to be integrated 
 
and allocates the costs of the solutions to such transmission needs in accordance with the 
type of benefits they provide.  PJM Interconnection, L.L.C., 142 FERC ¶ 61,214, at P 441 
(2013); see PJM Tariff, Schedule 12 (15.0.0), § (b)(v) (assigning cost responsibility for 
Economic Projects that are either accelerations or modifications of Reliability Projects, or 
new enhancements or expansions that relieve one or more economic constraints); PJM, 
Intra-PJM Tariffs, Operating Agreement, Schedule 6, § 1.5 (Procedure for Development 
of the Regional Transmission Expansion Plan) (29.1.0), 1.5.7(c)(iii).  
98 PJM Tariff, Schedule 12, § (b)(i)(A)(1) (Designation of Customers Subject to 
Transmission Enhancement Charges) (15.0.0). 
99 Id. § (b)(iii)(H)(2) (Designation of Customers Subject to Transmission 
Enhancement Charges) (15.0.0).  The annual update includes any projects that were 
included to address any individual transmission owner Form No. 715 local planning 
criteria.

Docket No. EL26-67-000 
- 26 - 
rapidly and reliably without causing resource inadequacy.  On January 16, 2026, the PJM 
Board issued a decisional letter on the Critical Issues Fast Path (CIFP) detailing the 
initiatives that PJM will move forward to implement, which include:  (1) a definition for 
large load additions; (2) load forecasting improvements; (3) voluntary “Bring Your Own 
New Generation” commensurate with large load additions; (4) an expedited generator 
interconnection track to offset large loads; (5) requiring, in specific circumstances, some 
new large loads to be subject to curtailment prior to the deployment of pre-emergency 
demand response pursuant to a “connect and manage” framework; (6) immediate 
initiation of reliability backstop procurement; (7) holistic review of investment incentives 
in PJM’s energy, reserve, and capacity markets; and (8) feedback on whether to extend 
the price collar for the 2028/2029 and 2029/2030 capacity auctions.100   
 
Additionally, on January 16, 2026, governors from each of the 13 states in PJM 
met with the White House National Energy Dominance Council and issued a statement of 
principles calling on PJM to:  (1) provide 15-year price certainty for new capacity 
resources by holding a reliability backstop auction to procure new capacity resources 
commencing no later than September 2026; (2) allocate the costs of capacity procured 
through the reliability backstop auction to load serving entities with new data centers that 
have not self-procured new capacity or agreed to be curtailable; (3) extend the existing 
price collar to the next two Base Residual Auctions; (4) refine load forecasting 
methodologies by improving large load modeling assumptions; (5) accelerate ongoing 
generator interconnection studies; and (6) embark on a stakeholder process to reform the 
capacity market to ensure long-term viability.101   
 
In response, PJM has initiated stakeholder processes on several items.  The PJM 
Board initiated a new CIFP stakeholder process to engage stakeholders in the 
 
100 PJM, Board Decisional Letter on Critical Issue Fast Path - Large Load 
Additions (Jan. 16, 2026), https://www.pjm.com/-/media/DotCom/about-pjm/who-we-
are/public-disclosures/2026/20260116-pjm-board-letter-re-results-of-the-cifp-process-
large-load-additions.pdf.  PJM has since submitted its proposal to extend the price collar 
for the 2028/2029 and 2029/2030 delivery years, which the Commission accepted on 
April 28, 2026.  PJM Interconnection, L.L.C., 195 FERC ¶ 61,076 (2026).  PJM has also 
since submitted its proposal for a temporary, expedited generator interconnection process 
(Expedited Interconnection Track), which the Commission accepted on June 9, 2026.  
PJM EIT Order, 195 FERC ¶ 61,197.  
101 U.S. Department of Energy, Statement of Principles Regarding PJM (Jan. 16, 
2026), https://www.energy.gov/documents/statement-principles-regarding-pjm.

Docket No. EL26-67-000 
- 27 - 
development of a reliability backstop procurement mechanism.102  PJM also developed a 
Connect and Manage Senior Task Force to consider the “connect and manage” 
framework to manage the reliability challenges during the transition period in which new 
load additions are outpacing the additions of new capacity in the PJM 
system.103  Following initial stakeholder workshops, the PJM Board decided to expand 
the scope of the CIFP regarding the reliability backstop procurement mechanism to 
include the “connect and manage” framework, given the substantive overlap between the 
two proposals.104  PJM expects to develop a comprehensive proposal by the end of June, 
which it expects to file with the Commission shortly thereafter, with the goal of procuring 
any shortfall resulting from the upcoming Base Residual Auction through a centralized 
procurement in September 2026.105  PJM has additionally issued a report examining 
market design and investment incentives in light of rising demand, which is driven in part 
by the expansion of large loads, and constrained supply.106  PJM has scheduled a series of 
workshops through August 2026 to develop recommendations based on the choices 
presented in the report.107 
 
While we are encouraged by PJM’s stakeholder efforts, and by its initial attention 
to the pressing concerns associated with large and co-located loads,108 and to the 
 
102 PJM, Critical Issue Fast Path – Reliability Backstop Procurement, 
https://www.pjm.com/committees-and-groups/cifp-rbp.   
103 PJM, Connect and Manage Senior Task Force, 
https://www.pjm.com/committees-and-groups/task-forces/camstf.  
104 PJM, Third Supplemental Informational Report, Docket No. EL25-49-000,      
et al. (filed May 20, 2026); see also PJM, Critical Issue Fast Path - Reliability Backstop 
Procurement / Connect & Manage, https://www.pjm.com/committees-and-groups/cifp-
rbp. 
105 PJM, Third Supplemental Informational Report, Docket No. EL25-49-000,      
et al. (filed May 20, 2026). 
106 PJM, Powering Reliability Through Market Design: Addressing Rising 
Demand and Constrained Supply, and Stimulating Investment to Support Durable 
Reliability (May 6, 2026), https://www.pjm.com/-/media/DotCom/library/reports-
notices/special-reports/2026/20260506-powering-reliability-through-market-design.pdf. 
107 PJM, Powering Reliability Through Market Design Workshops, 
https://www.pjm.com/committees-and-groups/workshops/prtmdw. 
108 PJM November 21 ANOPR Comments at 12; see also PJM, Large Load 
Additions Workshop, at 1 (May 9, 2025), https://www.pjm.com/-
/media/DotCom/committees-groups/workshops/llaw/2025/20250509/20250509-item-02--

Docket No. EL26-67-000 
- 28 - 
Secretary’s interest in these issues,109 we are initiating this FPA section 206 proceeding 
in order to ensure that PJM’s ongoing processes generate reforms that are sufficiently 
timely and comprehensive to address the concerns we today identify.  As such, and as the 
Commission explained in the April Order Regarding Intent to Act, we find that the 
Commission must now take further action to ensure that PJM promptly proposes 
revisions to ensure that its Tariff remains just and reasonable. 
III. 
Discussion 
 
Based on the discussion below, pursuant section 206 of the FPA, we direct PJM 
and the Transmission Owners, within 60 days of the date of this order, to either:   
(1) show cause as to why the Tariff remains just and reasonable and not unduly 
discriminatory or preferential without provisions addressing:   
(a) the application process, study procedures, and ongoing operational 
requirements that apply to Eligible Customers seeking transmission service 
on behalf of large loads;  
(b) additional transparency concerning the Network Upgrade costs to 
provide transmission service to Eligible Customers on behalf of large loads, 
a pro forma cost recovery agreement between PJM, the relevant 
transmission owner and Eligible Customer taking transmission service on 
behalf of the large load to mitigate the risk of cost shifting among 
transmission customers, and a mechanism to ensure such payments are 
appropriately credited towards transmission owners’ transmission revenue 
requirements consistent with the Commission’s cost-of-service regulations;  
(c) transmission services that reflect Eligible Customers taking transmission 
service on behalf of flexible large loads that are willing and able to limit 
their use of the transmission system under certain conditions; and  
(d) the rates, terms, and conditions of service applicable to interconnection 
customers serving electrically proximate large load or co-located load; or  
 
-large-load-additions-workshop---presentation.pdf (discussing challenges with reliability 
of connecting large loads); PJM IMM, Planning for Large Load Additions (Jan. 7, 2025), 
https://www.monitoringanalytics.com/reports/Presentations/2025/IMM_PC_Large_Load
_Additions_20250107.pdf. 
109 See supra PP 6-7.

Docket No. EL26-67-000 
- 29 - 
(2) explain what changes to the Tariff would remedy the identified concerns if the 
Commission were to determine that the Tariff has in fact become unjust and 
unreasonable or unduly discriminatory or preferential and, therefore, proceeds to 
establish a replacement Tariff.   
 
We also direct PJM to submit, within 30 days of the date of issuance of this order, 
an informational report on how PJM intends to ensure that adequate generation will be 
available to serve existing and new large loads.   
 
Interested entities may respond within 30 days of PJM’s and the Transmission 
Owners’ filings, addressing either or both of: (1) whether the existing Tariff remains just 
and reasonable and not unduly discriminatory or preferential; and (2) if not, what changes 
to the Tariff should be implemented as replacement rates.   
 
We recognize that PJM and/or the Transmission Owners (to the extent the matters 
addressed herein implicate aspects of the Tariff over which they have the filing rights) 
may elect to address some or all of the issues discussed in this order by proposing 
revisions to the Tariff pursuant to their applicable FPA section 205 filing rights.  We 
strongly encourage this.  Although both the Secretary’s ANOPR and our own Order 
Regarding Intent to Act expressly recognized (and indeed encouraged) that possibility,110 
no such filings were received from PJM by the Commission prior to the issuance of this 
order.  Should PJM and/or the Transmission Owners elect to make such filings in 
response to this order, those filings should state explicitly that the proposals are being 
submitted under FPA section 205.  Should PJM and/or the Transmission Owners submit a 
filing under FPA section 205, they should also explain which of the Commission’s above 
directives their filing addresses and how it resolves them.  Additionally, any such filing 
should provide a reasoned explanation for how the proposal will avoid disrupting existing 
commercial arrangements and clearly identify a reasonable effective date that 
accommodates such existing commercial arrangements. 
 
The Commission will consider requests from PJM and/or the Transmission 
Owners to hold, for up to 90 days, all or certain aspects of this FPA section 206 
proceeding in abeyance, including the deadline to respond to this order.  Any such 
abeyance, which will begin as of the deadline to respond to this order, would be 
considered to provide PJM and the Transmission Owners time while they work through 
the stakeholder processes to develop FPA section 205 filings to revise the Tariff to 
address the issues raised in this order.  Requests for a full or partial abeyance111 should be 
 
110 See ANOPR at P 32; Order Regarding Intent to Act, 195 FERC ¶ 61,045 at P 5. 
111 A partial abeyance may be appropriate to the extent PJM is developing FPA 
section 205 filings in response to only a subset of the directives in this order.  For any

Docket No. EL26-67-000 
- 30 - 
submitted prior to the deadline to respond to this order, specifically within 45 days of 
issuance of this order, to allow time for the Commission to act on the abeyance request.  
We emphasize that we will not grant such abeyances reflexively, that any abeyance will 
be limited to 90 days, and that we will look with great disfavor toward requests to extend 
the abeyance period.  We anticipate that successful abeyance requests, if any, will include 
both (1) a robust description of the content of a potential future filing under FPA              
section 205 and (2) a reasoned and specific explanation of when such a filing is expected 
to be made.   
 
In cases where, as here, the Commission institutes a section 206 investigation on 
its own motion, section 206(b) of the FPA requires that the Commission establish a 
refund effective date that is no earlier than the date of the publication by the Commission 
of notice of its intention to initiate such proceeding nor later than five months after the 
publication date.  In such cases, in order to give maximum protection to customers, and 
consistent with our precedent, we have historically tended to establish the section 206 
refund effective date at the earliest date allowed by section 206, and we do so here as 
well.112  That date is the date of publication of notice of initiation of this proceeding in 
the Federal Register. 
A. 
Transmission Service to Eligible Customers on Behalf of Large Loads 
 
We today make a preliminary finding that PJM’s Tariff appears to be unjust and 
unreasonable because it lacks provisions that address, with sufficient clarity and 
consistency, how PJM and/or the Transmission Owners will timely study (i.e., within             
60-90 days of receiving the request) the provision of transmission service to Eligible 
Customers on behalf of large loads.113   
 
Throughout this order, we use the phrase “the provision of transmission service to 
Eligible Customers on behalf of large loads” to encompass the provision of new, 
modified, or additional jurisdictional transmission service to Eligible Customers on 
behalf of large loads.  We note that this phrase is not limited to instances where an 
Eligible Customer submits an application to request new transmission service.  It also 
includes instances where an Eligible Customer requests a new or modified point of 
 
remaining directives, we expect a response to this order within the 60-day deadline set 
forth herein.  
112 See, e.g., Idaho Power Co., 145 FERC ¶ 61,122 (2013); Canal Elec. Co.,                 
46 FERC ¶ 61,153, order on reh’g, 47 FERC ¶ 61,275 (1989). 
113 As discussed below, our findings here also apply to the study process for 
unbundled retail transmission service requests by end-use large load customers, as 
allowed by state law or voluntary utility rules.

Docket No. EL26-67-000 
- 31 - 
delivery to serve a large load, where a large load seeks a new or modified delivery point 
as an unbundled retail transmission service customer, or where large loads are otherwise 
included in an Eligible Customer’s reported load growth and that Eligible Customer is 
taking NITS.    
 
We direct PJM and the Transmission Owners to the extent the matters addressed 
herein implicate aspects of the Tariff over which they have the filing rights, to explain 
whether the Tariff remains just and reasonable without an application process, study 
procedures, and ongoing operational requirements that address the unique characteristics 
and challenges of providing transmission service to Eligible Customers on behalf of large 
loads, or to propose appropriate Tariff revisions.   
1. 
Jurisdiction 
 
At the outset, we clarify the principles relating to the Commission’s jurisdiction 
over the matters relevant to the integration of large loads onto the transmission system 
and the impacts of large loads on the transmission system.  We recognize that rates, 
terms, and conditions associated with the addition of and service to large loads implicate 
both federal and state interests.  We also recognize that resolution of issues related to 
large load additions will require the involvement of both federal and state actors, 
including the Commission, state public utility commissions, and other state and local 
entities.  We are encouraged by efforts made at the state level to address issues related to 
large load additions that fall within state jurisdiction.114   
 
As discussed below, however, certain aspects of the process for integrating large 
loads onto the transmission system fall squarely within the Commission’s exclusive 
jurisdiction.  Specifically, we find that it is within the Commission’s exclusive authority 
to ensure that transmission provider and/or transmission owner tariffs include sufficiently 
clear and consistent provisions governing how transmission service to Eligible Customers 
on behalf of large loads interconnecting to the transmission system will be studied, 
including whether new or upgraded transmission facilities are necessary to provide the 
requested transmission service.  The Commission has jurisdiction over the study process 
for transmission service to both Eligible Customers on behalf of large loads and 
unbundled retail transmission service to end-use large load customers where, pursuant to 
state law or a public utility’s voluntary offer of such service, the large load is an Eligible 
Customer under the transmission provider and/or transmission owner tariffs.115 
 
114 See generally NARUC April 14 ANOPR Comments (highlighting action taken 
by state public utility commissions related to large loads). 
115 Under the pro forma OATT, Eligible Customers include end-use customers 
seeking unbundled retail transmission service, pursuant to state law or public utility’s

Docket No. EL26-67-000 
- 32 - 
 
The Commission is a creature of statute and has jurisdiction over only those 
matters that Congress has given it the authority to regulate.116  That authority includes 
jurisdiction over the wholesale sale and transmission of electricity in interstate 
commerce, including all facilities used for such sale and transmission.117  As relevant 
here, the Commission must ensure that the rates, charges, and classifications for such 
transmission of electricity—as well as the practices directly affecting such transmission 
of electricity—are just and reasonable and not unduly discriminatory or preferential.118  
The Supreme Court has held that the Commission’s authority over interstate transmission 
is not limited to wholesale transmission service and that the Commission has authority 
over unbundled retail transmission service.119  As part of its transmission authority, the 
Commission has exercised jurisdiction over the terms of certain interconnections to the 
transmission system as an element of transmission service,120 including the 
interconnection of wholesale load to the transmission system.121  
 
As applied to large load additions to the transmission system, these principles 
mean that the Commission has exclusive jurisdiction over the rates, terms, and conditions 
of interstate transmission service to Eligible Customers on behalf of large loads 
connecting to the transmission system, and the practices directly affecting the provision 
of such interstate transmission of electricity.  An essential component of providing such 
transmission service is the process by which the transmission provider and/or 
 
voluntary offer of such service.  Pro forma OATT, § 1.12 (Definitions – Eligible 
Customer); see also PJM Tariff pt. VIII, § 400 (Definitions E) (2.0.0). 
116 Atl. City Elec. Co. v. FERC, 295 F.3d 1, 8 (D.C. Cir. 2002). 
117 16 U.S.C. § 824(b)(1). 
118 Id. §§ 824d, 824e; see FERC v. Elec. Power Supply Ass’n, 577 U.S. 260, 278 
(2016) (EPSA) (approving “a common-sense construction of the FPA’s language, 
limiting FERC’s ‘affecting’ jurisdiction to rules or practices that ‘directly affect the 
wholesale rate’” (cleaned up)).    
119 New York v. FERC, 535 U.S. 1, 17, 19-20 (2002) (upholding the Commission’s 
exercise of jurisdiction over unbundled retail transmission service). 
120 Tenn. Power Co., 90 FERC ¶ 61,238, at 61,761 (2000) (Tennessee Power), 
order denying reh’g, 91 FERC ¶ 61,271 (2000); Standardization of Generator 
Interconnection Agreements & Procs., Order No. 2003, 104 FERC ¶ 61,103, at P 9 
(2003); see also Laguna Irrigation Dist., 91 FERC ¶ 61,340, at 62,152 (2000). 
121 Pac. Gas & Elec. Co., 109 FERC ¶ 61,392, at P 37 (2004); Pac. Gas & Elec. 
Co., 115 FERC ¶ 61,193, at PP 36-38 (2006).

Docket No. EL26-67-000 
- 33 - 
transmission owner evaluates (1) whether it can provide the requested transmission 
service and (2) the impact that providing such transmission service will have on the 
jurisdictional transmission system, including determining whether any new or upgraded 
transmission facilities are needed to provide transmission service while maintaining 
reliable operation of the transmission system.  This transmission service study process 
determines what Network Upgrades are needed to provide transmission service to 
Eligible Customers on behalf of large loads, the costs of which are included in 
transmission rates.  As such, this study process directly affects Commission-jurisdictional 
transmission rates.122  The Commission has exclusive authority to ensure that the process 
to study the provision of transmission service to Eligible Customers is just and reasonable 
and not unduly discriminatory or preferential.  We therefore find that we have authority 
to ensure that tariffs include provisions that clearly and consistently address the study 
process for the provision of transmission service to Eligible Customers on behalf of large 
loads, including the unique impacts that providing transmission service to Eligible 
Customers on behalf of large loads may have on the transmission system. 
 
At the same time, we continue to recognize that the FPA expressly reserves to 
states the authority over any other sale of electric energy, including retail sales and 
wholesale sales not in interstate commerce (such as wholesale sales within the Electric 
Reliability Council of Texas region), as well as facilities used for the generation and 
distribution of electricity.123  As such, we recognize that states will continue to regulate:  
(1) the specific terms of retail sales to large load;124 (2) which entities may make retail 
sales within their borders, including which entities are legally permitted to provide 
electricity to retail large load customers;125 and (3) any siting decisions and construction 
 
122 Cf. Transmission Plan. & Cost Allocation by Transmission Owning & 
Operating Pub. Utils., Order No. 1000, 136 FERC ¶ 61,051, at P 112 (2011) (“It is 
through the transmission planning process that public utility transmission providers 
determine which transmission facilities will more efficiently or cost-effectively meet the 
needs of the region, the development of which directly impacts the rates, terms and 
conditions of jurisdictional service.”). 
123 16 U.S.C. § 824(b)(1); see Dayton Power & Light Co. v. FERC, 126 F.4th 
1107, 1129 (6th Cir. 2025). 
124 See EPSA, 577 U.S. at 279-80 (recognizing state authority over retail electricity 
sales); New York v. FERC, 535 U.S. at 28 (same). 
125 PJM Show Cause Order, 190 FERC ¶ 61,115 at PP 68-69.

Docket No. EL26-67-000 
- 34 - 
associated with the large load project.126  Nothing in this order is intended to intrude upon 
state authority over retail service to large loads.   
 
In sum, we today exercise our authority to ensure that the process by which 
jurisdictional transmission providers and/or transmission owners will study the provision 
of jurisdictional transmission service to Eligible Customers on behalf of large loads 
interconnecting to the transmission system, including where, as allowed by state law or a 
public utility’s voluntary offer of such service, an end-use large load seeks unbundled 
retail transmission service, is just and reasonable and not unduly discriminatory or 
preferential.  Pursuant to that authority, we find that PJM’s Tariff appears to be unjust 
and unreasonable or unduly discriminatory or preferential because it lacks sufficiently 
clear and consistent provisions regarding the study process related to the provision of 
transmission service to Eligible Customers on behalf of large loads.  We need not 
comprehensively address the Commission’s jurisdiction over other aspects of the addition 
of large loads to the transmission system at this time.  
2. 
Tariff Provisions 
 
In the following section, we begin by considering PJM’s Tariff as it relates to how 
PJM and/or the Transmission Owners will study the provision of transmission service to 
Eligible Customers on behalf of large loads and explain our concerns that the lack of 
sufficiently clear and consistent provisions regarding the study process for the provision 
of transmission service to Eligible Customers on behalf of large loads is unjust and 
unreasonable or unduly discriminatory or preferential.  We then consider whether the 
Tariff is unjust and unreasonable without certain elements.  First, we consider whether 
the Tariff lacks sufficiently clear and consistent Tariff provisions establishing an 
appropriate definition of large load, as a separate category of load.  Second, we consider 
whether the Tariff lacks sufficiently clear and consistent Tariff provisions establishing an 
application process and requirements for Eligible Customers requesting transmission 
service on behalf of large loads and a study process that considers the unique operational 
challenges of providing transmission service to Eligible Customers on behalf of large 
loads.  Third, we consider whether the Tariff lacks sufficiently clear and consistent Tariff 
provisions establishing ongoing operational requirements necessary to ensure that PJM 
can reliably provide transmission service given the unique operational impacts on the 
transmission system of providing transmission service to Eligible Customers on behalf of 
large loads.  Finally, we consider whether the Tariff requires such ongoing operational 
 
126 See, e.g., Citizens Action Coal. of Ind., Inc. v. FERC, 125 F.4th 229, 238 (D.C. 
Cir. 2025) (citing 16 U.S.C. § 824(b)(1)) (recognizing state authority over generation 
resource mix, including through their siting authority); Order No. 1000, 136 FERC                 
¶ 61,051 at P 107 (acknowledging state authority over siting, permitting, and construction 
of transmission facilities).

Docket No. EL26-67-000 
- 35 - 
requirements for Eligible Customers taking transmission service on behalf of large loads 
to be memorialized in service agreements. 
 
We preliminarily find that PJM’s Tariff appears to be unjust and unreasonable or 
unduly discriminatory or preferential because it does not contain provisions addressing 
with sufficient clarity and consistency how PJM and/or the Transmission Owners will 
study the provision of transmission service to Eligible Customers on behalf of large 
loads.  We recognize that PJM and/or the Transmission Owners may have existing load 
integration processes, including studies that are performed in evaluating the provision of 
transmission service to Eligible Customers on behalf of large loads.127  However, we are 
concerned that those processes and any required studies with regard to the provision of 
transmission service are not described in the Tariff with the degree of clarity and 
specificity necessary to ensure that the transmission provider can mitigate operational 
risks of providing transmission service to Eligible Customers on behalf of large loads, 
given their impact on the transmission system, avoid disputes regarding how studies are 
conducted, deter speculative or duplicative requests for transmission service by Eligible 
Customers on behalf of large loads, and help avoid excessive and unnecessary Network 
Upgrades.  Moreover, we are concerned that the existing Tariff does not contain other 
elements akin to those described below, which we preliminarily find may be necessary to 
ensure that the rates, terms, and conditions of jurisdictional transmission service are just 
and reasonable.   
 
At the outset, we recognize that the Transmission Owners may be primarily 
responsible for conducting the studies that (1) evaluate whether a large load may be 
interconnected to the transmission system and served by the Eligible Customer, and                
(2) determine whether Network Upgrades are necessary to provide transmission service.  
We appreciate that this role may stem from how PJM and the Transmission Owners 
allocated rights and responsibilities in the governing documents establishing PJM.  We 
do not seek to alter that allocation of rights and responsibilities. 
 
We are nonetheless concerned that PJM’s Tariff lacks a study process that 
addresses the unique operational and reliability challenges that providing transmission 
service to Eligible Customers on behalf of large loads presents to the transmission 
system.  Large loads can be more energy intensive and geographically concentrated than 
traditional load, and exhibit different load profiles and operational characteristics.128  
 
127 See supra PP 20-24. 
128 See, e.g., SPP HILL Order, 194 FERC ¶ 61,031 at PP 7-8; NERC, 
Characteristics and Risks of Emerging Large Loads (July 2025), 
https://www.nerc.com/globalassets/who-we-are/standing-committees/rstc/whitepaper-

Docket No. EL26-67-000 
- 36 - 
PJM itself has recognized that enhanced large load saturation can have a disproportionate 
impact on system reliability, including voltage and frequency fluctuations due to their 
size and unique characteristics, if mitigating operational steps and other protection 
schemas are not developed and implemented.129  The PJM Board has also recognized that 
the scale, pace, and characteristics of large load growth present significant operational 
and planning challenges.130  As a result, providing transmission service to Eligible 
Customers on behalf of large loads may be more complex and could raise greater 
reliability concerns for the transmission system, relative to a situation where Eligible 
Customers seek transmission service on behalf of traditional load. 
 
Without a clear and consistent process to study the provision of transmission 
service to Eligible Customers on behalf of large loads, PJM and/or the Transmission 
Owners may not fully capture the transmission system impacts of providing such 
transmission service, which could result in significant operational risks for the 
transmission system.  Furthermore, we are concerned that, without sufficiently clear and 
consistent Tariff provisions, PJM will not have the ongoing visibility and operational 
control necessary to provide reliable transmission service. 
 
We are also concerned that the absence of sufficiently clear and consistent Tariff 
provisions for how PJM and/or the Transmission Owners will study the provision of 
transmission service to Eligible Customers on behalf of large loads will lead to disputes 
over a variety of issues—e.g., study timelines and delays,131 how the transmission service 
needed on behalf of the large load is studied,132 what types of Network Upgrades are 
 
characteristics-and-risks-of-emerging-large-loads.pdf (NERC Characteristics and Risks 
of Large Loads). 
129 PJM November 21 ANOPR Comments at 12. 
130 See PJM Board Letter.  PJM TOs further note that many data centers’ initial 
loads are significantly lower when they first enter commercial operation, but following 
expansion and full potential of operation capacity, their demand increases to much higher 
levels.  PJM TOs November 21 ANOPR Comments at 9. 
131 See, e.g., Institute for Progress November 21 ANOPR Comments at 7-8; 
Microsoft November 21 ANOPR Comments at 9; ODEC December 5 ANOPR 
Comments at 4; Vistra November 21 ANOPR Comments at 21 (discussing lack of 
defined load interconnection process in PJM and lack of detail in PJM Tariff and manuals 
regarding load integration study). 
132 Commenters raised concern that large loads are not studied with consideration 
of their known operating characteristics, including their willingness to be flexible or 
curtailable.  See, e.g., ClearPath November 21 ANOPR Comments at 5-6; Constellation 
November 21 ANOPR Comments at 23-24; Critical Loop November 21 ANOPR

Docket No. EL26-67-000 
- 37 - 
considered, and how required Network Upgrades to provide the requested transmission 
service are determined.133  Such disputes may arise from the lack of transparency in how 
studies are performed and how decisions will be made.134  We are thus concerned that the 
lack of clear and consistent provisions in PJM’s Tariff related to the study process for the 
provision of transmission service to Eligible Customers on behalf of large loads appears 
to be unjust and unreasonable or unduly discriminatory or preferential.   
 
Lastly, we are concerned that PJM’s existing Tariff fails to deter speculative or 
duplicative requests for transmission service by Eligible Customers on behalf of large 
loads.  Many ANOPR comments assert that clear and consistent provisions establishing 
study timelines and costs, readiness requirements, and/or penalties will deter speculative 
or duplicative requests related to large load additions.135  Commenters explain that 
 
Comments at 3; GridCare December 5 ANOPR Comments at 1-2; L. Lynne Kiesling 
November 21 ANOPR Comments at 10. 
133 Specifically, commenters raised concern that transmission providers/owners 
may only consider traditional transmission infrastructure or that there is a lack of 
consideration of alternative transmission solutions.  See, e.g., ACORE November 21 
ANOPR Comments at 3-4, 6-7; American Terawatt November 21 ANOPR Comments            
at 4-5; Calibrant November 21 ANOPR Comments at 1-2, 3; CEBA November 21 
ANOPR Comments at 9-10; Chamber of Commerce November 21 ANOPR Comments  
at 3; CTC Global Corporation November 21 ANOPR Comments at 1-3; DCC            
November 21 ANOPR Comments at 10-11; GridCARE December 5 ANOPR Comments 
at 4; Industrial Customers November 21 ANOPR Comments at 27-28; Infrastructure 
Masons December 5 ANOPR Comments at 18; Iron Mountain Data Centers, LLC 
November 21 ANOPR Comments at 3-4; Land Trust Alliance November 21 ANOPR 
Comments at 5-6; PIOs November 21 ANOPR Comments at 22; Southeast PIOs 
November 21 ANOPR Comments at 44-45; WATT and Advancing Modern Powerlines 
November 21 ANOPR Comments at 5-8. 
134 See, e.g., CEBA November 21 ANOPR Comments at 12; ECA December 5 
ANOPR Comments at 1-2; Eolian November 21 ANOPR Comments at 17-18; EPSA 
November 21 ANOPR Comments at 6; Infrastructure Masons December 5 ANOPR 
Comments at 4, 6-7; Southeast PIOs November 21 ANOPR Comments at 39-40; Switch 
December 5 ANOPR Comments at 3; Tract November 21 ANOPR Comments at 5; 
Vantage November 21 ANOPR Comments at 5-6; Verrus November 21 ANOPR 
Comments at 6, 12; Vistra December 5 ANOPR Comments at 27. 
135 See, e.g., ACORE November 21 ANOPR Comments at 6; AEU November 21 
ANOPR Comments at 17-18; Amazon November 21 ANOPR Comments at 6; Crusoe 
December 5 ANOPR Comments at 5-6; EDF Power November 21 ANOPR Comments  
at 12-13; EEI November 21 ANOPR Comments at 20; Fervo November 21 ANOPR

Docket No. EL26-67-000 
- 38 - 
speculative requests may bog down and delay the study process, wasting time and 
resources for transmission providers;136 result in inaccurate study results or delays for 
other Eligible Customers seeking transmission service on behalf of load;137 create a 
substantial risk of cost shifts if the large load additions do not materialize as planned;138 
and distort load forecasts.139  Clear and consistent study procedures that include readiness 
requirements (i.e., meaningful milestones and/or financial commitments) can help ensure 
that Eligible Customers’ requests for transmission service on behalf of large loads are 
more viable and more likely to materialize as planned, given that they must meet specific 
milestones and/or pay costs to proceed.  
 
More specifically, we preliminarily find that PJM’s Tariff appears to be unjust and 
unreasonable because it lacks sufficiently clear and consistent Tariff provisions that 
 
Comments at 3; GridCare December 5 ANOPR Comments at 5; Invenergy November 21 
ANOPR Comments at 6; Microsoft November 21 ANOPR Comments at 9; Ohio FEA 
November 21 ANOPR Comments at 4. 
136 See, e.g., Eolian November 21 ANOPR Comments at 17-18; GridCare 
December 5 ANOPR Comments at 5; Illinois AG November 21 ANOPR Comments               
at 9-10; Institute for Progress November 21 ANOPR Comments at 9; OCC November 21 
ANOPR Comments at 7-8; Ohio FEA November 21 ANOPR Comments at 4; Vistra 
November 21 ANOPR Comments at 23. 
137 See, e.g., Amazon November 21 ANOPR Comments at 6; CEBA November 21 
ANOPR Comments at 8; ClearPath November 21 ANOPR Comments at 4; Geronimo 
November 21 ANOPR Comments at 12; TAPS November 21 ANOPR Comments                    
at 14-15. 
138 See, e.g., AES November 21 ANOPR Comments at 10-11; Buckeye             
November 21 ANOPR Comments at 1-2; Exelon November 21 ANOPR Comments at 3; 
NRECA November 21 ANOPR Comments at 9; OCC November 21 ANOPR Comments 
at 9; Southeast PIOs November 21 ANOPR Comments at 20; State Entities November 21 
ANOPR Comments at 7-8; TAPS November 21 ANOPR Comments at 15, 22-24;                
Tri-State November 21 ANOPR Comments at 6, 8; Vistra November 21 ANOPR 
Comments at 23. 
139 See, e.g., CEBA November 21 ANOPR Comments at 8; EEI November 21 
ANOPR Comments at 20; ELCON November 21 ANOPR Comments at 7; Invenergy 
November 21 ANOPR Comments at 6; GridCare December 5 ANOPR Comments at 5; 
OCC November 21 ANOPR Comments at 9; PIOs November 21 ANOPR Comments            
at 5; Southeast PIOs November 21 ANOPR Comments at 41; Talen November 21 
ANOPR Comments at 9.

Docket No. EL26-67-000 
- 39 - 
address certain aspects of the process to provide transmission service to Eligible 
Customers on behalf of large loads, including:    
(1) a definition of large load sufficient to capture loads that present the unique 
challenges described herein;  
(2) the application process for requesting transmission service to Eligible 
Customers on behalf of large loads and the study procedures, including readiness 
requirements, for studying the provision of transmission service to Eligible 
Customers on behalf of large loads;  
(3) ongoing operational requirements for transmission customers140 serving large 
loads necessary to ensure reliable operation of the transmission system; and  
(4) pro forma provisions in transmission service agreements to memorialize these 
terms. 
 
First, we preliminarily find that PJM’s Tariff appears to be unjust and 
unreasonable because it lacks a definition of large load, as a new category of load.  As 
PJM acknowledges, integrating large loads poses specific challenges to transmission 
system operation given their size, operational behavior, and unique potential to impact 
the transmission system.141  An appropriate definition, including a load size and 
interconnection voltage threshold, should be based on the characteristics of PJM’s 
transmission system.  That said, based on the record in the ANOPR proceeding,142 it 
appears that it would be reasonable to define a large load as a new, commercial or 
 
140 We note that such ongoing operational requirements should apply to 
transmission customers, rather than Eligible Customers, as these requirements apply after 
the Eligible Customer has an executed (or a filed unexecuted) service agreement for 
transmission service and have become transmission customers under the Tariff.  
141 PJM November 21 ANOPR Comments at 12. 
142 See, e.g., Constellation November 21 ANOPR Comments at 13 (supporting a 
voltage threshold); DTE November 21 ANOPR Comments at 3, 17-19 (recommending a 
threshold of an amount between 50 MW to 100 MW); Eolian November 21 ANOPR 
Comments at 8-9 (recommending a voltage threshold greater than or equal to an amount 
between 60 kV to 100 kV); Illinois AG November 21 ANOPR Comments at 7 
(supporting a 20 MW or 50 MW threshold and consideration of other factors, such as 
voltage level); ITC November 21 ANOPR Comments at 3 (recommending a threshold of 
between 50 MW to 100 MW); Nebraska Board November 21 ANOPR Comments at 4 
(proposing a 50 MW threshold); New Mexico Commission November 21 ANOPR 
Comments at 5 (proposing a 50 MW threshold).

Docket No. EL26-67-000 
- 40 - 
industrial customer, located at a single site behind one or more points of interconnection, 
and that has a peak load of 50 MW or greater, interconnects to the transmission system at 
a voltage level of greater than 69 kV, and is not part of a co-location arrangement.  In its 
response to this order, PJM should explain whether the Tariff remains just and reasonable 
without such a definition, or propose Tariff revisions establishing its own definition of 
large load. 
 
Second, we preliminarily find that PJM’s Tariff appears to be unjust and 
unreasonable because it lacks sufficiently clear and consistent Tariff provisions 
establishing the application process and study procedures that will be used when PJM 
and/or the Transmission Owners evaluate the provision of transmission service to 
Eligible Customers on behalf of large loads.  PJM should explain whether the Tariff 
remains just and reasonable, for example, without:  (1) an application process that accepts 
Eligible Customers’ applications for transmission service on behalf of large loads on a 
rolling basis; (2) a non-refundable application fee and sufficient readiness requirements 
that escalate at distinct phases of the study process to deter duplicative or speculative 
requests for transmission service (e.g., meaningful milestones and/or financial 
commitments); and (3) information and data requirements that Eligible Customers must 
submit to PJM and/or the Transmission Owners regarding the characteristics of the large 
load on behalf of which the Eligible Customer is taking transmission service, including 
disclosure to PJM of any substantially similar pending transmission service requests on 
behalf of the same large load customer.143  PJM may also elect to propose Tariff revisions 
establishing such an application process, fee, and requirements.   
 
Further, PJM’s Tariff appears to lack sufficiently clear and consistent provisions 
establishing a study process for evaluating the provision of transmission service to 
Eligible Customers on behalf of large loads that considers the unique characteristics and 
impacts of large loads on the transmission system.  For example, we are concerned that 
PJM’s Tariff may not clearly and consistently require PJM or the Transmission Owners 
to conduct studies that evaluate the transmission system’s ability to withstand risks 
observed from analyzed large load behavior created by the large load at the point of 
interconnection, or any other necessary supplemental studies to evaluate the impact of 
providing transmission service to Eligible Customers on behalf of large loads.144  
 
143 The Electric Reliability Council of Texas (ERCOT) has proposed a similar 
disclosure requirement in its Batch Zero process for large load interconnections.  ERCOT 
Planning Guide, § 9.7.1(1)(b) (proposed Mar. 4, 2026). 
144 See generally NERC, Industry Recommendation:  Large Load Interconnection, 
Study, Commissioning, and Operations (Sep. 2025), 
https://www.nerc.com/globalassets/programs/bpsa/alerts/2025/nerc-alert-level-2--large-

Docket No. EL26-67-000 
- 41 - 
Additionally, we preliminarily find that PJM’s Tariff appears unjust and unreasonable 
because it lacks appropriate provisions recognizing within the transmission service 
request study process the unique operational characteristics of large loads that are willing 
and able to limit their energy withdrawals under certain conditions, which may thereby 
lessen or potentially avoid the need for certain Network Upgrades.  While flexible large 
loads can reduce the demand on the transmission system, and therefore potentially reduce 
the need for additional transmission capacity, additional informational and study 
requirements may be necessary to account for the dynamic nature of these types of loads 
while maintaining reliability.145  Additionally, we note that accurate models using 
Electromagnetic Transient studies may help to ensure that transmission service needed on 
behalf of large loads can be provided without compromising reliability.146 
 
Additionally, we preliminarily find that PJM’s Tariff appears to be unjust and 
unreasonable because it lacks clear and consistent provisions requiring the evaluation of 
alternative transmission technologies147 as potential solutions to accommodate an 
Eligible Customer’s request for transmission service on behalf of a large load.  
Alternative transmission technologies can add more capacity on existing transmission 
 
loads.pdf (finding that unique operational characteristics of large loads necessitate 
enhancements to studies). 
145 See, e.g., AEMA November 21 ANOPR Comments at 6; Thermal Battery 
Alliance November 21 ANOPR Comments at 7; Verrus November 21 ANOPR 
Comments at 10. 
146 See, e.g., NERC, Draft Reliability Guideline:  Risk Mitigation for Emerging 
Large Loads 6-7 (May 2026), https://www.nerc.com/globalassets/who-we-are/standing-
committees/rstc/reliabilityguideline_riskmitigationforemerginglargeloads.pdf; NERC, 
Assessment of Gaps in Existing Practices, Requirements, and Reliability Standards for 
Emerging Large Loads 31 (Mar. 2026), https://www.nerc.com/globalassets/our-
work/guidelines/reliability/white-paper---assessment-of-gaps.pdf; see also SPP HILL 
Order, 194 FERC ¶ 61,031 at P 62. 
147 For purposes of this order, alternative transmission technologies include static 
synchronous compensators, static VAR compensators, advanced power flow control 
devices, transmission switching, synchronous condensers, voltage source converters, 
advanced conductors, tower lifting, and dynamic line ratings.  We note that the 
Commission has also referred to these types of technologies as Grid Enhancing 
Technologies (GETs).

Docket No. EL26-67-000 
- 42 - 
lines quickly, often within one to three years.148  Unlike with traditional load growth,149 
large load customers often have development timelines requiring interconnection to the 
transmission system faster than traditional Network Upgrades can be built, necessitating a 
sufficient evaluation of alternative transmission technologies that can more quickly 
accommodate transmission service requests from Eligible Customers on behalf of large 
loads.150  The Commission has previously recognized that alternative transmission 
technologies have the potential to mitigate or defer the need for traditional Network 
Upgrades and often can be deployed both more quickly and at lower cost than traditional 
Network Upgrades, and therefore failing to consider whether alternative transmission 
technologies can meet transmission needs more efficiently or cost-effectively than 
traditional Network Upgrades has the potential to render Commission-jurisdictional rates 
 
148 WATT and Advancing Modern Powerlines November 21 ANOPR Comments 
at 5-6. 
149 See, e.g., SPP HILL Order, 194 FERC ¶ 61,031 at P 7 (explaining that the 
HILL proposal was needed in part due to large load customers frequently requesting 
transmission service within months rather than years of their intended commercial 
operation, straining legacy regulatory frameworks and planning processes originally 
designed for slow, incremental, and predictable load growth); see also Commission Staff, 
2025 State of the Market Report 8 (Mar. 2026) (“[D]ata centers have characteristics 
unlike more traditional loads [including] size, strong desire for faster interconnection, and 
potential flexibility.”). 
150 Exec. Off. of the President, Winning the Race: America’s AI Action Plan 1-2, 
15 (July 2025), https://www.whitehouse.gov/wp-content/uploads/2025/07/Americas-AI-
Action-Plan.pdf (explaining that accelerated deployment of AI data centers is a critical 
matter of national security and international economic competitiveness, and 
recommending federal policy action to optimize the existing grid through advanced grid 
technologies); WATT and Advancing Modern Powerlines November 21 ANOPR 
Comments at 5-8 (“[Alternative transmission technologies’] deployment timelines are 
more aligned with the interconnection needs of new large loads, which may only take 1-2 
years to construct.”); Industrial Customers November 21 ANOPR Comments at 28 
(“Achieving speed-to-power in the near-term, while also protecting customers, will 
require the use of GETs, advanced reconductoring, and unlocking all available system 
capacity.”); Energy Systems Integration Group, Historical and Modern Large Loads: 
Characteristics, Context, and Industry Action to Meet Grid and Customer Needs 4           
(Mar. 2026), https://www.esig.energy/wp-content/uploads/2026/03/ESIG-Historical-vs-
Modern-Large-Loads-white-paper-2026.pdf (describing the timing mismatch between 
how long it takes to build a new data center and how long it takes to plan, permit, and 
build transmission).

Docket No. EL26-67-000 
- 43 - 
unjust and unreasonable.151  Further, to the extent Network Upgrade costs to 
accommodate an Eligible Customer’s request for transmission service on behalf of a large 
load are rolled into a transmission owner’s transmission revenue requirement, 
transmission customers other than the Eligible Customer may bear a portion of those 
Network Upgrade costs, highlighting the need for clear and consistent provisions 
requiring the evaluation of least-cost options like alternative transmission technologies to 
mitigate the rate impact on all transmission customers.    
 
PJM should explain whether the Tariff remains just and reasonable without 
provisions that:  (1) require the evaluation of alternative transmission technologies in 
transmission service request studies, using models that are capable of evaluating the 
transmission system to accurately account for advanced transmission technologies, in all 
instances, without the need for a request from the Eligible Customer seeking transmission 
service on behalf of a large load; and (2) if traditional Network Upgrades are selected 
instead of alternative transmission technologies, inclusion in the study report to the 
Eligible Customer seeking transmission service on behalf of a large load of a sufficiently 
clear demonstration of why alternative transmission technologies are not feasible (i.e., 
would not resolve reliability violations identified or meet the relevant planning criteria) 
or would not result in lower costs or a faster timeline for accommodating the transmission 
service request; or propose Tariff revisions establishing such provisions.  This 
transparency and informational requirement is warranted for the regulatory scheme we 
are establishing for transmission service requests by Eligible Customers on behalf of 
large loads given demand from and the expedited development timelines for large load 
customers.  We underscore that we are not mandating the use of alternative transmission 
technologies.  To the extent stakeholders believe that specific characteristics of providing 
transmission service to Eligible Customers on behalf of large loads warrant requirements 
beyond those contemplated here, we seek further briefing. 
 
Finally, based on the record, it appears reasonable that such study processes, 
culminating in a report to the Eligible Customer with the results of the studies, including 
any Direct Assignment Facilities and Network Upgrades necessary to accommodate the 
transmission service request as well as a non-binding good-faith estimate of the cost and 
the time to construct such facilities, should take no more than 60-90 days calendar days to 
 
151 Improvements to Generator Interconnection Procs. & Agreements, Order              
No. 2023, 184 FERC ¶ 61,054 at P 1583, order on reh’g, 185 FERC ¶ 61,063 (2023), 
order on reh’g, Order No. 2023-A, 186 FERC ¶ 61,199, errata notice, 188 FERC                    
¶ 61,134 (2024); see also Bldg. for the Future Through Elec. Reg’l Transmission Plan. & 
Cost Allocation, Order No. 1920, 187 FERC ¶ 61,068 at P 1201, order on reh’g, Order 
No. 1920-A, 189 FERC ¶ 61,126 (2024), order on reh’g, Order No. 1920-B, 191 FERC       
¶ 61,026 (2025).

Docket No. EL26-67-000 
- 44 - 
complete.152  To the extent PJM or the Transmission Owners already have such 
procedures and conduct such studies, but those processes are not included in the Tariff, 
PJM and the Transmission Owners should explain their existing processes and consider 
whether amendments are necessary to the Tariff to memorialize those processes and also 
address the concerns expressed herein.  Otherwise, PJM should explain whether the 
Tariff remains just and reasonable without:  (1) sufficiently clear and consistent 
provisions to evaluate the impact of providing the requested transmission service to 
Eligible Customers on behalf of large loads, including identifying the Direct Assignment 
Facilities and Network Upgrades necessary to provide such service reliably;                          
(2) provisions to appropriately recognize within the transmission service study process 
the unique operational characteristics of large loads; (3) a study deadline of no more than 
60-90 calendar days; or propose Tariff revisions establishing them. 
 
Third, we preliminarily find that PJM’s Tariff appears to be unjust and 
unreasonable because it lacks provisions addressing ongoing operational requirements for 
transmission customers taking transmission service on behalf of large loads.  We are 
concerned that without such requirements the rates, terms, and conditions of transmission 
service may be unjust and unreasonable.  The unique nature of these large loads creates 
challenges for operation of the transmission system and necessitates greater visibility and 
operational control when providing transmission service to transmission customers on 
behalf of large loads, without which the reliability of the transmission system could be at 
risk.153  For example, we are concerned that PJM’s Tariff does not require transmission 
customers to provide PJM hourly forecasts, telemetry data, and other data to ensure 
sufficient visibility or specify requirements for maintaining communication channels 
between PJM and the transmission customer on behalf of the large load.  Additionally, 
we are concerned that the Tariff does not require transmission owners to install, and 
transmission customers to pay for, equipment to enable PJM to monitor large loads for 
impacts of, for example, fast-ramping load that may impact the transmission system too 
quickly to be captured by conventional data acquisition systems (e.g., the need for phasor 
 
152 Several commenters support a 60-day timeline.  See, e.g., Constellation 
November 21 ANOPR Comments at 26; Critical Loop December 5 ANOPR Comments 
at 8; EDF Power November 21 ANOPR Comments at 16; Tract November 21 ANOPR 
Comments at 9.  Other commenters note that SPP’s HILL process has a 90-day timeline, 
or otherwise support a 90-day timeline.  See, e.g., AEMA November 21 ANOPR 
Comments at 3; Eolian December 5 ANOPR Comments at 27; Industrial Customers 
November 21 ANOPR Comments at 20; PJM November 21 ANOPR Comments at 7; 
SPP November 21 ANOPR Comments at 16-17.  
153 E.g., ATC November 21 ANOPR Comments at 14; CAISO November 21 
ANOPR Comments at 10 (citing NERC Characteristics and Risks of Large Loads); Herb 
Schrayshuen November 21 ANOPR Comments at 2-5.

Docket No. EL26-67-000 
- 45 - 
measurement units or similar equipment).  We are also concerned that the Tariff does not 
require the transmission customer to enable PJM to remotely disconnect large loads when 
necessary to maintain reliability of the transmission system, with the costs of such 
equipment directly assigned to the transmission customer, as well as the terms and 
conditions under which PJM may remotely disconnect the large load (e.g., emergency 
conditions, so that transmission equipment is not harmed).  Further, we are concerned 
that the Tariff does not specify ramp rate or ride-through requirements with which the 
transmission customer taking transmission service on behalf of the large load must 
comply.  Lastly, we are concerned that the Tariff does not specify requirements for 
necessary control technologies and/or protection systems that may be necessary to limit a 
transmission customer’s withdrawals from the transmission system as appropriate.154  
PJM should explain whether the Tariff remains just and reasonable without these or other 
ongoing operational requirements as part of the rates, terms, and conditions of 
transmission service or propose Tariff revisions establishing necessary ongoing 
operational requirements. 
 
Fourth, we preliminarily find that PJM’s Tariff appears to be unjust and 
unreasonable because it lacks pro forma provisions in a transmission service agreement 
between PJM and the transmission customer taking transmission service on behalf of a 
large load to memorialize the above terms (e.g., equipment requirements, data 
requirements, remote disconnect capability).  We are concerned that, without such                 
pro forma provisions in a transmission service agreement between PJM and the 
transmission customer, PJM may be unable to enforce ongoing operational requirements 
for transmission customers taking transmission service on behalf of large loads.  PJM 
should explain whether the Tariff remains just and reasonable without such pro forma 
provisions in a transmission service agreement, or propose revisions to include pro forma 
provisions memorializing the ongoing operational requirements in a transmission service 
agreement between PJM and the transmission customer. 
B. 
Cost Shifting Risk Among Transmission Customers 
 
We next preliminarily find that PJM’s Tariff appears to be unjust and 
unreasonable because it lacks adequate mechanisms to mitigate the risk of cost shifting 
among transmission customers, which may result in unjust and unreasonable rates for 
transmission service.  In particular, we are concerned about the apparent lack of:           
(1) transparency regarding the assignment of Network Upgrades, and their associated 
costs, that are needed to provide transmission service to Eligible Customers on behalf of 
large loads; and (2) a pro forma cost recovery agreement between PJM, the relevant 
 
154 Specifically, as discussed below, the Commission has found that such 
necessary control technologies and/or protection schemes may be appropriate where 
Eligible Customers are taking one of the new transmission services.  See infra P 87.

Docket No. EL26-67-000 
- 46 - 
transmission owner, and the Eligible Customer taking transmission service on behalf of 
large loads that help ensure that Eligible Customers bear the risk and are ultimately 
responsible for costs incurred to provide transmission service, including the cost of 
Network Upgrades.  
 
We direct PJM and the Transmission Owners, to the extent the matters addressed 
herein implicate aspects of the Tariff over which they have the filing rights, to explain 
whether the Tariff remains just and reasonable without (1) robust, accurate, and 
systematic provision of data on PJM’s website in a single location, and in an easily 
accessible format that is searchable and allows users to filter the data, regarding the cost 
for Network Upgrades needed to provide transmission service to Eligible Customers on 
behalf of large loads; and (2) a pro forma cost recovery agreement between PJM, the 
relevant transmission owner, and the Eligible Customer taking transmission service on 
behalf of a large load, or to propose Tariff revisions to provide additional transparency 
and establish such a pro forma cost recovery agreement.  We encourage state regulators 
responsible for setting retail rates to provide input to PJM regarding their transparency 
needs. 
1. 
Jurisdiction 
 
The Commission has a duty to address the risk of cost shifting among transmission 
customers that may result in unjust and unreasonable transmission rates.  As explained 
above, the Commission is obligated to ensure that the rates charged for jurisdictional 
transmission service—as well as any practice directly affecting such rates—are just and 
reasonable and not unduly discriminatory or preferential.  With respect to the addition of 
large loads to the transmission system, the Commission has exclusive authority to ensure 
that transmission rates are just and reasonable.  The costs of those upgrades to the 
transmission system (i.e., Network Upgrades) necessary to provide transmission service 
to Eligible Customers on behalf of large loads are inputs to jurisdictional transmission 
rates, and thus directly affect the Commission-jurisdictional rates paid by transmission 
customers.  To fulfill its responsibility to ensure that transmission rates are just and 
reasonable, the Commission must act to address the risk of cost shifting among 
transmission customers due to (1) the process transmission providers and/or transmission 
owners use to evaluate the facilities needed, and the associated costs, for the provision of 
transmission service to Eligible Customers on behalf of large loads and (2) speculative 
transmission service requests by Eligible Customers on behalf of large loads that could 
result in unjust and unreasonable transmission rates. 
 
In response to the ANOPR, many commenters raise concerns about the impact that 
large load additions can have on retail ratepayers, particularly the concern that other retail 
ratepayers may be forced to subsidize Network Upgrades needed to add large loads to the

Docket No. EL26-67-000 
- 47 - 
transmission system.155  While we appreciate and are similarly concerned about this 
issue, the Commission is limited to addressing jurisdictional transmission rates and as 
such, we do so herein.  As the Commission has explained, states determine how 
Commission-approved rates are collected among the relevant retail consumers along with 
the rates for state-jurisdictional matters.156  Specifically, states have authority over how 
the wholesale costs of providing electricity, including transmission of such electricity, to 
those retail customers are recovered through retail rates.157  We are encouraged by efforts 
taken by states to reform retail tariffs to address the potential for retail cost shifting as 
large loads come online,158 as well as voluntary efforts by transmission owners to protect 
retail ratepayers through cost recovery agreements with large loads.159  We are also 
encouraged by the execution of the President’s Ratepayer Protection Pledge, through 
which data center developers have committed to shield retail ratepayers from increased 
electricity prices.160 
 
We expect that the additional cost transparency measures proposed in the 
following section will give state public utility commissions and other state regulators the 
information necessary to allow them to understand which transmission costs are caused 
by which transmission customers, so that they can sub-allocate these costs to the 
appropriate retail customers.  Indeed, the Commission’s objective in this proceeding is to 
respect the cooperative federalism approach established under the FPA.  Specifically, one 
of the benefits of providing transparency on the costs of Network Upgrades necessary to 
provide transmission service to Eligible Customers on behalf of large loads is so that state 
regulators can use that information to protect residential and small commercial customers 
 
155 See, e.g., Illinois AG November 21 ANOPR Comments at 11-12; Missouri 
Commission November 21 ANOPR Comments at 11; OMS November 21 ANOPR 
Comments at 4. 
156 PJM Show Cause Order, 190 FERC ¶ 61,115 at P 167. 
157 Id. P 68. 
158 See, e.g., Pennsylvania Commission November 21 ANOPR Comments at 7-8; 
Maryland Commission November 21 ANOPR Comments at 2; Virginia Commission 
November 21 ANOPR Comments at 4-5 
159 See, e.g., Commonwealth Edison Co. 194 FERC ¶ 61,106; Commonwealth 
Edison Co., 194 FERC ¶ 61,109; Commonwealth Edison Co., 194 FERC ¶ 61,110; 
Commonwealth Edison Co., 194 FERC ¶ 61,113 (2026); PECO Energy Co., 193 FERC    
¶ 61,148; Dayton Power & Light Co., 192 FERC ¶ 61,103; Dayton Power & Light Co., 
189 FERC ¶ 61,220 (2024). 
160 Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026).

Docket No. EL26-67-000 
- 48 - 
by incorporating those costs into the retail rates as they see fit given their authority to set 
rates for different classes of retail customers.  We encourage state public utility 
commissions, state regulators, and state consumer advocates to submit comments 
explaining whether this information is sufficient and granular enough or to submit 
comments explaining precisely which additional information on transmission cost 
allocation may be needed to inform proper state-jurisdictional cost allocation.  
2. 
Additional Cost Transparency 
 
We preliminarily find that PJM’s Tariff appears to be unjust and unreasonable or 
unduly discriminatory or preferential because it does not contain provisions requiring the 
provision of data on PJM’s website in a single location, and in an easily accessible format 
that is searchable and allows users to filter the data, on transmission service requested by 
Eligible Customers on behalf of large loads, for Network Upgrades evaluated in the local 
transmission planning process that are needed to provide transmission service to Eligible 
Customers on behalf of those large loads, and the costs for those Network Upgrades.  We 
preliminarily find that cost transparency measures are needed to provide stakeholders 
with sufficient information and visibility regarding the Network Upgrades, and their 
associated costs, needed to provide transmission service to Eligible Customers on behalf 
of large loads.   
 
As discussed above, Network Upgrades needed to accommodate a new 
transmission service request or designation of new network load may be designated as 
local transmission facilities (i.e., Supplemental Projects) or contribute to regional 
transmission system needs and be addressed by a Required Transmission Enhancement in 
the RTEP.  PJM’s Tariff Schedule 12 Appendix and Appendix A include the cost 
responsibility assignments for regional transmission projects selected through the RTEP 
process.  In addition, Attachment M-3 of PJM’s Tariff provides procedures for 
stakeholder review and comment on Supplemental Projects identified through 
transmission owners’ local transmission planning process in the Transmission Expansion 
Advisory Committee (230 kV or above) and Subregional RTEP Committee (below                 
230 kV) and as part of a transmission owner’s Local Plan, before the Local Plan is 
submitted for integration into the RTEP.161  PJM’s website also includes a list of 
Required Transmission Enhancements and Supplemental Projects with their project 
status, cost, and cost allocation.162   
 
161 See PJM Tariff, attach. M-3, § (c) (Procedures for Review of Attachment M-3 
Projects) (1.0.0). 
162 PJM, Project Status & Cost Allocation, 
https://www.pjm.com/planning/m/project-construction.

Docket No. EL26-67-000 
- 49 - 
 
However, PJM’s Tariff does not appear to require that information identifying the 
Network Upgrades needed to provide transmission service to Eligible Customers on 
behalf of large loads and the costs of those Network Upgrades determined through local 
transmission planning processes be readily available on PJM’s website in a single 
location, and in an easily accessible format that is searchable and allows users to filter the 
data.  We acknowledge that PJM’s website provides information concerning certain 
transmission projects, including Supplemental Projects, such as project status, cost, cost 
allocation, and the type of equipment and upgrade, and includes the primary driver for 
each transmission project (i.e., load growth), but these postings do not appear to be 
specific to transmission projects needed to provide transmission service to Eligible 
Customers on behalf of large loads.  The speed and scale with which Eligible Customers 
are seeking transmission service on behalf of large loads makes it difficult for interested 
parties, including transmission customers and state regulators, to accurately assess which 
transmission costs are driven by requests for transmission service by Eligible Customers 
to serve large loads.  Further, as PJM acknowledges, it forecasts significant peak load 
growth, but there is a large cone of uncertainty around the trajectory and amplitude of 
future demand growth.163  We are concerned that the potentially speculative nature of 
requests for transmission service by Eligible Customers on behalf of large loads,164 the 
speed and scale with which large loads are seeking to be added to the transmission 
system, the projected need for significant Network Upgrades to provide transmission 
service to Eligible Customers on behalf of large loads, and the lack of centralized 
information on the associated transmission costs in PJM hamper the ability of the 
Commission and stakeholders (including transmission customers and state regulators165) 
to understand and accurately assess the relationship between the addition of large loads to 
the transmission system and wholesale transmission costs.   
 
163 See PJM Board Letter at 1. 
164 See supra P 56. 
165 See Transcript, NARUC Collaborative, Docket No. AD24-7-000, at 16-17 
(Feb. 11, 2026) (Chair Bagot, Virginia) (asserting that additional transparency at the RTO 
level would help the states get the information they need to “identify . . . that bucket of 
costs” related to large load-driven transmission costs), 19 (Commissioner Chattopadhyay, 
New Hampshire) (noting the need for “all parties to be able to see things transparently” 
with respect to wholesale transmission costs), 35-37 (Chair Martz, Iowa) (raising concern 
that currently RTOs/ISOs do not have to clearly explain when a “bucket of costs is 
specifically for this large load” and noting that “if we, at the state level, can’t see the 
driver [of transmission costs], we can’t assign the cost to the causer[,] [a]nd so we need 
that clarity”), 69-70 (Chair Myers, Arizona) (“[B]eing able to allocate the large load costs 
to the correct bucket when it gets to the states is kind of a top priority.”).

Docket No. EL26-67-000 
- 50 - 
 
We are concerned that without sufficient transparency regarding the Network 
Upgrades, and their associated costs, needed to provide transmission service to Eligible 
Customers on behalf of large loads, stakeholders may lack information and visibility 
regarding the costs driven by large load additions.  We preliminarily find that, for 
Network Upgrades evaluated in the local transmission planning process166 that are 
needed to provide transmission service to Eligible Customers on behalf of large loads, 
PJM must provide clear, timely, and detailed information regarding the extent to which 
requests for transmission service by Eligible Customers on behalf of large loads 
necessitate Network Upgrades to accommodate the transmission service to Eligible 
Customers on behalf of large loads, as well as the costs of those Network Upgrades. 
 
We note that centralized information regarding Network Upgrades needed to 
accommodate requests for transmission service by Eligible Customers on behalf of large 
loads would also help inform stakeholders at the state and local level to address 
affordability and other challenges posed by the integration of large loads.  Indeed, 
commenters state that the opaque nature of requests for transmission service by Eligible 
Customers on behalf of large loads, and the associated Network Upgrades required to 
provide that transmission service, prevent wholesale and retail customers, states, and 
other stakeholders from understanding such costs.167        
 
166 Our concern with transparency regarding Network Upgrades needed to provide 
transmission service to Eligible Customers on behalf of large loads, as well as the costs of 
such upgrades, is limited to Network Upgrades planned through the local transmission 
planning process.  While we acknowledge that in Order No. 890, the Commission 
adopted requirements for RTOs/ISOs, as well as for transmission owners to the extent 
that they perform transmission planning within an RTO/ISO, to have open and 
transparent transmission planning processes, there are additional requirements that apply 
to regional transmission planning processes (that do not apply to local transmission 
facilities) and thus is relevant to the distinction here.  Specifically, under Order No. 1000, 
public utility transmission providers, including RTOs/ISOs, must evaluate as part of their 
regional transmission planning process whether there are transmission facilities that more 
efficiently or cost-effectively meet the transmission planning region’s identified 
transmission needs.  See Order No. 1000, 136 FERC ¶ 61,051 at P 11. 
167 See OCC November 21 ANOPR Comments at 3 (“Consumers, state advocates 
and state regulatory commissions have a right to know which entities are seeking            
large-load interconnections, the nature of the requested service, and how related costs 
could flow through to transmission and distribution rates.”); U.S. House of 
Representatives Committee on Energy and Commerce Ranking Members November 21 
ANOPR Comments at 2 (urging the Commission to “require sufficient transparency from 
grid operators so it can determine which specific large load facilities are responsible for 
grid upgrade needs”); see also CPUC November 21 ANOPR Comments at 16-17

Docket No. EL26-67-000 
- 51 - 
 
Accordingly, we preliminarily find that PJM’s Tariff appears to be unjust and 
unreasonable because it does not require the provision of data on PJM’s website in a 
single location, and in an easily accessible format that is searchable and allows users to 
filter the data, that identifies the Network Upgrades that are needed to accommodate 
requests for transmission service by Eligible Customers on behalf of large loads, and the 
costs of those Network Upgrades.  PJM should explain whether the Tariff remains just 
and reasonable without provisions that would require PJM and the Transmission Owners 
to publicly post and regularly update data that details:  (1) the aggregate amounts of 
proposed large load additions in PJM’s footprint, including the aggregate amounts in 
each transmission pricing zone; (2) the planned Network Upgrades needed to provide 
transmission service to Eligible Customers on behalf of large loads, identified by type of 
equipment and Network Upgrade (e.g., new substation, reconductoring, a new                    
high-voltage transmission line) for each transmission service request; and (3) cost 
estimates for those Network Upgrades; or propose such Tariff revisions.  PJM and the 
Transmission Owners should also consider what other data related to transmission costs 
resulting from the provision of transmission service to Eligible Customers on behalf of 
large loads would be useful to include on PJM’s website.  To the extent there are 
concerns about data confidentiality, PJM and the Transmission Owners should consider 
whether there are ways to mitigate those concerns while still providing the necessary 
transparency. 
3. 
Cost Recovery Agreements 
 
We next preliminarily find that PJM’s Tariff appears to be unjust and 
unreasonable because it lacks adequate mechanisms to mitigate the risk of cost shifting 
among transmission customers, which may result in unjust and unreasonable rates for 
transmission service.  In particular, we are concerned about the apparent lack of a              
pro forma cost recovery agreement between PJM, the relevant transmission owner, and 
the Eligible Customer taking transmission service on behalf of large loads that help 
ensure that Eligible Customers bear the risk and are ultimately responsible for costs 
incurred to provide transmission service, including the cost of Network Upgrades.  
 
Several commenters discuss the risk of cost shifting among transmission 
customers that could result from transmission service requests by Eligible Customers on 
behalf of large loads.168  Commenters also argue that retail-level large load tariffs do not 
 
(asserting that the public posting of large load cost responsibility determinations would 
improve transparency, to the benefit of businesses and ratepayers).  
168 See, e.g., Buckeye November 21 ANOPR Comments at 8-13; APPA    
November 21 ANOPR Comments at 6 (“Wholesale transmission customers in particular 
could be left shouldering massive costs if new large loads do not ultimately attain or 
maintain the level of electricity demand that is being forecasted.”); NRECA

Docket No. EL26-67-000 
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protect wholesale transmission customers from cost shifting.169  Specifically, commenters 
in the record contend that, while a retail-level large load tariff protects the load serving 
entity taking wholesale transmission service and its retail customers, it fails “to provide 
any mechanism to protect other wholesale transmission customers” from stranded 
transmission costs.170  The Kansas Commission states that while its Large Load Power 
Services rate plan that requires large loads to make minimum payments toward 
transmission costs protects retail ratepayers from large-load driven transmission costs, it 
cannot protect against cost shifting associated with regional transmission buildout where 
“the large loads that formed the basis for the [regional] transmission plans do not 
materialize, leaving only existing customers to pay for generational expansions of the 
transmission grid.”171  TAPS contends, moreover, that it is not sufficient for the 
Commission to rely on transmission owners to voluntarily file cost recovery agreements 
to protect transmission customers from cost shifting for Network Upgrades.172   
 
We are likewise concerned that there may be speculative transmission service 
requests by Eligible Customers on behalf of large loads that could result in cost shifting 
among transmission customers, which may lead to unjust and unreasonable increases in 
jurisdictional transmission rates.  When a transmission owner constructs Network 
Upgrades to accommodate an Eligible Customer’s request for transmission service on 
behalf of a large load, those transmission costs will be included in the transmission 
owner’s transmission revenue requirement.  If, however, the Eligible Customer takes less 
transmission service than anticipated because the large load operates at a lower demand 
 
November 21 ANOPR Comments at 21 (noting the risk that other transmission customers 
could bear stranded upgrade costs caused by large loads that they cannot absorb); TAPS 
November 21 ANOPR Comments at 22-24; California DWR November 21 ANOPR 
Comments at 8. 
169 TAPS November 21 ANOPR Comments at 26 (“[A] number of state 
commissions are moving forward with retail large load tariffs, which provide for varying 
protections, but may not require the revenues and minimum demand levels to be included 
in wholesale transmission rates.”); Buckeye November 21 ANOPR Comments at 14-16; 
Kansas Commission November 21 ANOPR Comments at 15-16. 
170 Buckeye November 21 ANOPR Comments at 14-15; see TAPS November 21 
ANOPR Comments at 26-27 & nn.50-51.  
171 Kansas Commission November 21 ANOPR Comments at 11-12.  
172 TAPS November 21 ANOPR Comments at 25-26 (noting that AES Ohio 
“committed to reflecting the payments it received from the data center in its   
Commission-jurisdictional transmission revenue requirement so that other customers are 
protected,” in a Construction Service Agreement with Amazon).

Docket No. EL26-67-000 
- 53 - 
than anticipated or fails to materialize at all, other transmission customers may see an 
increase in transmission rates.  In such a situation, those other transmission customers 
may have to pay for potentially unnecessary Network Upgrades that they neither caused 
the need for nor benefit commensurately from.  In other words, this introduces the risk 
that costs may be unfairly shifted to other transmission customers, which may result in 
those costs then being passed through to residential customers, among others. 
 
PJM’s Tariff does not require cost recovery agreements between PJM, the relevant 
transmission owner, and the Eligible Customer taking transmission service on behalf of a 
large load.  Such agreements would help ensure that the Eligible Customer makes a 
minimum contribution to the transmission owner’s transmission revenue requirement 
commensurate with the costs incurred to provide the requested transmission service, 
including the costs of any needed Network Upgrades.  Absent such cost recovery 
agreements, we are concerned that 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.   
 
Accordingly, we preliminarily find that, in order to prevent unjust and 
unreasonable cost shifting among transmission customers, it appears necessary for PJM, 
the relevant transmission owner, and the Eligible Customer taking transmission service 
on behalf of a large load to enter into a cost recovery agreement that requires the Eligible 
Customer to make a minimum contribution toward the transmission owner’s transmission 
revenue requirement, if the Eligible Customer ultimately takes less transmission service 
than anticipated because the large load does not materialize as planned or is not 
developed at all.  We preliminarily find that such cost recovery agreements are necessary 
to help ensure that the Eligible Customer is responsible for timely paying the costs of 
large load-driven transmission (i.e., the costs incurred to provide them with the requested 
transmission service, including the costs of any needed Network Upgrades), rather than 
having those costs paid by other transmission customers that neither caused the need for 
nor benefit commensurately from those Network Upgrades.173  Our preliminary finding is 
not intended to alter or call into question existing regional cost allocation methods for 
Network Upgrades, but instead is focused on helping to prevent cost shifting among 
transmission customers.   
 
We note that several transmission owners and large load customers have filed cost 
recovery agreements (Transmission Security Agreements or Construction Service 
Agreements) with the Commission that guarantee minimum contributions from a large 
 
173 See, e.g., Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1368 
(D.C. Cir. 2004); Ill. Com. Comm’n v. FERC, 576 F.3d 470, 476 (7th Cir. 2009).

Docket No. EL26-67-000 
- 54 - 
load customer (rather than from the Eligible Customer taking transmission service on 
behalf of the large load customer) to the transmission owner’s transmission revenue 
requirement.174  Although we decline to preliminarily find that cost recovery agreements 
between the transmission owner and the large load customer (rather than the Eligible 
Customer) are necessary to ensure just and reasonable transmission rates, we continue to 
find that such agreements directly affect Commission-jurisdictional transmission rates.  
Therefore, to the extent a transmission owner and a large load customer enter into a cost 
recovery agreement (whether voluntarily or pursuant to state law) through which the 
large load customer guarantees contributions to the transmission owner’s               
Commission-jurisdictional transmission revenue requirement, we find that such an 
agreement should be filed with the Commission.175  To reduce duplicative credit 
requirements and transaction costs, we direct further briefing on whether it would be 
appropriate for such an agreement to substitute for the requirement on the Eligible 
Customer to enter into a cost recovery agreement with the transmission owner, if the 
agreement with the large load customer provided comparable or greater protection 
against cost shifting among transmission customers than an agreement between the 
transmission owner and the Eligible Customer would.   
 
In addition to our preliminary finding that PJM’s Tariff is unjust and unreasonable 
because it lacks a pro forma cost recovery agreement of this type, we also preliminarily 
find that the minimum contribution required pursuant to such an agreement should be 
based on the level of jurisdictional transmission service (in MW) requested by the 
Eligible Customer on behalf of the large load.  That figure is in turn tied to how PJM 
and/or Transmission Owners will study the requested transmission service and determine 
any necessary Network Upgrades that must be developed to provide the requested 
transmission service.  We note, however, that there may be other just and reasonable 
methods for determining this minimum contribution, including methods that account for 
potential timing differences between when costs are incurred to develop needed Network 
Upgrades and the pace at which the large load ramps toward energizing at its full level of 
requested service.  We further preliminarily find that the cost recovery agreement should 
include a credit support (or other financial security) requirement sufficient to secure the 
obligations of the Eligible Customer taking transmission service on behalf of a large load 
to pay the amounts owed pursuant to the cost recovery agreement.  We find that a cost 
recovery agreement with a specified minimum financial contribution and financial 
security sufficient to secure such contribution is necessary to mitigate cost shifting if the 
 
174 See supra note 159. 
175 We emphasize that this finding 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.

Docket No. EL26-67-000 
- 55 - 
Eligible Customer ultimately takes less transmission service than anticipated because the 
large load does not materialize as planned or is not developed at all.  We preliminarily 
find that an Eligible Customer may include a credit support or other financial security 
posted by a large load as part of a retail agreement to avoid creating duplicative credit 
support requirements.  PJM should explain why such a pro forma cost recovery 
agreement is not necessary to ensure just and reasonable rates, or propose such a                   
pro forma cost recovery agreement.  To the extent that stakeholders believe that other 
mechanisms could address our cost shifting concerns, we seek further briefing as 
discussed below.176 
 
Lastly, we expect that any payments made by an Eligible Customer to a 
transmission owner pursuant to such a cost recovery agreement (or by a large load to a 
transmission owner pursuant to other voluntary agreement) will be appropriately credited 
toward transmission owners’ transmission revenue requirements consistent with the 
Commission’s cost-of-service regulations.177  We preliminarily find that it appears 
reasonable for filers of formula rates to provide a separate workpaper in the annual 
informational filing describing how any payments made pursuant to a cost recovery 
agreement are reflected in the transmission owner’s transmission formula rate. 
C. 
Extending New Transmission Services to Eligible Customers Taking 
Service on Behalf of Flexible Large Loads 
 
In response to the ANOPR, a number of commenters argue that certain large loads 
are able to limit their withdrawals from the transmission system under certain conditions.  
Namely, commenters observe that flexible large loads178 can quickly and verifiably adjust 
their consumption in response to system conditions or price signals.179  Commenters in 
the ANOPR also observe that, where load studies and system planning consider the 
flexible nature of large loads, flexible large loads can potentially defer or reduce the need 
 
176 See infra P 107.  
177 See 18 C.F.R. pt. 101 (2025). 
178 For purposes of this order, “flexible” large loads are a subset of large loads, as 
used in this order, that are not co-located with generation, but are willing and able to limit 
their energy withdrawals from the transmission system under certain conditions. 
179 See, e.g., AEMA November 21 ANOPR Comments at 1-2; Land Trust Alliance 
November 21 ANOPR Comments at 10; California DWR November 21 ANOPR 
Comments at 5; CEBA November 21 ANOPR Comments at 14-15; ClearPath            
November 21 ANOPR Comments at 2-4; Digital Energy Council November 21 ANOPR 
Comments at 1; EDF Power November 21 ANOPR Comments at 4; Emerald             
November 21 ANOPR Comments at 2; Verrus November 21 ANOPR Comments at 4.

Docket No. EL26-67-000 
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for Network Upgrades, among other potential benefits.180  In recognition of this 
flexibility, many commenters support new transmission services that reflect the 
operational capabilities of flexible large loads, including interim NITS while Network 
Upgrades are constructed, and non-firm transmission service.181   
 
We preliminarily find that PJM’s Tariff appears to be unjust and unreasonable 
because it does not include transmission services that reflect Eligible Customers taking 
transmission service on behalf of flexible large loads that are willing and able to limit 
their use of the transmission system under certain conditions.  The transmission services 
available to Eligible Customers, including on behalf of flexible large loads, in PJM are 
NITS and firm and non-firm Point-to-Point Transmission Service.182  While these remain 
just and reasonable options for an Eligible Customer to take on behalf of a flexible large 
load, based on the record before us, we preliminarily find that new transmission services 
should be available to reflect the operational reality that large loads may use the 
transmission system to differing extents and certain large loads are willing and able to 
limit their use of the transmission system under certain conditions.183  The Commission 
found that Eligible Customers taking transmission service on behalf of Eligible Load 
should be allowed to choose a transmission service that aligns with their use of the 
transmission system and therefore aligns the charges for service with the benefits 
received.184  As the record suggests, Eligible Customers taking transmission service on 
behalf of flexible large load also may be willing and able to limit their use of the 
transmission system under certain conditions.  As recognized in the ANOPR record, load 
 
180 See, e.g., AEMA November 21 ANOPR Comments at 5; ELCON               
November 21 ANOPR Comments at 9; Emerald November 21 ANOPR Comments             
at 6-7; Institute for Progress November 21 ANOPR Comments at 11; Land Trust Alliance 
November 21 ANOPR Comments at 10; LS Power November 21 ANOPR Comments        
at 5; Microsoft November 21 ANOPR Comments at 10-11; National Grid November 21 
ANOPR Comments at 19-20; OMS November 21 ANOPR Comments at 13-14; 
Southeast PIOs November 21 ANOPR Comments at 50. 
181 See, e.g., Constellation November 21 ANOPR Comments at 24-25; Calibrant 
November 21 ANOPR Comments at 2-4; Critical Loop November 21 ANOPR 
Comments at 2; Digital Power Network November 21 ANOPR Comments at 3; PIOs 
November 21 ANOPR Comments at 27-28; Splight November 21 ANOPR Comments          
at 3-4. 
182 See supra P 19 (describing existing transmission services in PJM). 
183 See supra P 85.  
184 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 199; PJM Co-Location 
Rehearing Order, 195 FERC ¶ 61,209 at P 103.

Docket No. EL26-67-000 
- 57 - 
flexibility can avoid inefficient and costly transmission system build-out.185  In addition, 
transmission services that reflect that flexible large loads are willing and able to limit 
their withdrawals from the transmission system under certain conditions could help 
timely interconnect flexible large loads.186  Entities in the PJM footprint acknowledge the 
importance of facilitating load flexibility.187 
 
Therefore, we are concerned that PJM’s Tariff does not include transmission 
services that reflect the use of the transmission system by Eligible Customers on behalf of 
flexible large load, on both an interim and permanent basis.  PJM should explain whether 
the Tariff remains just and reasonable without the transmission services described by the 
Commission in the PJM Co-Location Order being available to Eligible Customers taking 
transmission service on behalf of flexible large loads, or propose appropriate Tariff 
revisions.  Specifically, PJM should explain whether the Tariff remains just and 
reasonable without (1) an interim non-firm network transmission service while Network 
Upgrades are being constructed (i.e., interim NITS) and (2) permanent firm and non-firm 
contract demand transmission services (transmission service up to a specified MW 
quantity, i.e., the contract level, on a firm or non-firm basis).188  Finally, we note that the 
Commission has found it just and reasonable that, in order for an Eligible Customer to 
 
185 See supra P 85; see also PJM Co-Location Order, 193 FERC ¶ 61,217                 
at PP 160, 177, 199 (finding that new transmission service options reflect a co-located 
load’s ability to limit withdrawals from the transmission system and potentially avoid 
costly and inefficient transmission system buildout that may not be necessary). 
186 See supra P 85; see also PJM Co-Location Order, 193 FERC ¶ 61,217                          
at PP 201 (finding that the interim, non-firm transmission service will facilitate the 
“timely” provision of transmission service and that “[t]his willingness to curtail would 
potentially allow them to obtain service more quickly”), 205 (recognizing that parties 
argue that co-located loads may be able to receive transmission service faster with use of 
a new, limited transmission service product than they would if they selected NITS, to the 
extent that providing NITS would require Network Upgrades that the limited 
transmission service would not). 
187 See, e.g., Constellation November 21 ANOPR Comments at 23-24; Load 
Flexibility Parties November 21 ANOPR Comments at 2-5; State Entities November 21 
ANOPR Comments at 4. 
188 In an order also issued today, the Commission established as just and 
reasonable certain rates, terms, and conditions for the new transmission services directed 
in the PJM Co-Location Order, which include portions of PJM’s and the Transmission 
Owners’ proposals submitted in the briefs, and directed further compliance filings.  See 
generally PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209.

Docket No. EL26-67-000 
- 58 - 
take interim NITS, firm contract demand transmission service, and non-firm contract 
demand transmission service, an Eligible Customer must have necessary control 
technologies and/or protection systems, which may include a special protection scheme, 
to limit its energy withdrawals to its approved level.189 
D. 
Interconnection Customers Serving Electrically Proximate Large Load 
and Co-Located Load 
 
In response to the ANOPR, a number of commenters agree that the ability to study 
new load and new generation together, when physically or electrically proximate, 
presents system benefits and can help address the challenges posed by large load 
additions.190  Commenters argue that studies that consider large load and generation 
together present a more complete picture of the grid and can enable the identification of 
more accurate, efficient, and cost-effective transmission solutions by minimizing system 
impacts.191  As a result, this can speed up the interconnection process for both large loads 
and generation, and shorten energization timelines,192 which commenters contend 
reduces uncertainty for both parties193 and “is necessary to match the pace of AI 
innovation in the United States.”194  CEBA also highlights that cost and timeline factors 
drive developers to submit multiple requests for price and timing discovery, which 
 
189 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. 
190 See e.g., DCC November 21 ANOPR Comments at 5-6; DTE November 21 
ANOPR Comments at 11; Google November 21 ANOPR Comments at 7; International 
Energy Credit Association November 21 ANOPR Comments at 10; Terraflux                
November 21 ANOPR Comments at 1. 
191 AEU November 21 ANOPR Comments at 13; ClearPath November 21 
ANOPR Comments at 4; DCC November 21 ANOPR Comments at 5; DTE               
November 21 ANOPR Comments at 8-11; ENGIE November 21 ANOPR Comments             
at 6; Entergy November 21 ANOPR Comments at 5; Geronimo November 21 ANOPR 
Comments at 17-18; Information Technology Industry Council November 21 ANOPR 
Comments at 2. 
192 DCC November 21 ANOPR Comments at 5; DTE November 21 ANOPR 
Comments at 8-11; Information Technology Industry Council November 21 ANOPR 
Comments at 2; Microsoft November 21 ANOPR Comments at 8-9; Verrus December 5 
ANOPR Comments at 9. 
193 ClearPath November 21 ANOPR Comments at 4; CEBA November 21 
ANOPR Comments at 8. 
194 Microsoft November 21 ANOPR Comments at 8-9.

Docket No. EL26-67-000 
- 59 - 
inflates queue volumes, distorts demand and supply forecasts, and causes significant 
delays when projects withdraw late after finding costs or energization timelines 
uneconomic.195  Other benefits to a joint study identified by commenters include 
improving load forecasting and siting decisions196 and reducing the need for critical 
supply chain components.197   
 
Commenters contend that current generator interconnection study processes may 
not adequately capture generation and load, including by failing to model known 
electrically proximate large load in base case assumptions, which may result in inaccurate 
studies and inefficient system build-out.198  For example, Eolian states that in its 
experience developing a project in PJM, the failure of the generator interconnection study 
process to reflect reasonably expected load conditions on the grid models triggered overly 
costly Network Upgrades and caused the cancellation of generation project that could 
have reliably served adjacent load growth.199   
 
Commenters in the ANOPR proceeding argue that the current state of the 
generator interconnection queue is not meeting the expeditious time frame needed to 
match the pace of large load additions and ensure the safe and reliable interconnection of 
these loads.200  For example, Oracle states that one of the most significant and 
widespread delays it encounters when siting data centers in the U.S. is access to sufficient 
energy.201  Similarly, Helion contends that more than half of U.S. developers now 
identify interconnection delays as the single biggest barrier to adding new generation 
 
195 CEBA November 21 ANOPR Comments at 8. 
196 ELCON November 21 ANOPR Comments at 5; Maryland Commission 
November 21 ANOPR Comments at 6-7.  
197 AEU November 21 ANOPR Comments at 13. 
198 Base Power November 21 ANOPR Comments at 7; Eolian November 21 
ANOPR Comments at 18-19; Eolian May 19 ANOPR Comments at 2; Longroad 
November 21 ANOPR Comments at 8. 
199 Eolian May 19 ANOPR Comments at 10. 
200 See, e.g., AEP December 5 ANOPR Comments at 1; DCC November 21 
ANOPR Comments at 8; esVolta November 21 ANOPR Comments at 11-12; Oracle 
May 1 ANOPR Comments at 4.  
201 Oracle November 21 ANOPR Comments at 1.

Docket No. EL26-67-000 
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capacity.202  Commenters contend that if large load interconnection proceeds more 
quickly than new generation can come online, the result could be price increases for 
consumers.203   
 
A number of commenters support expedited interconnection studies for new 
generation paired with load.204  Some commenters argue that one solution to generator 
interconnection delays may be the creation of time-limited or conditional interconnection 
service for generators serving large loads, which could require less time for initial 
generator interconnection studies and improve speed to power.205  For example, several 
commenters express support for SPP’s HILLGA proposal as a model and urge the 
Commission to establish nationwide rules similar to that approach.206  Other commenters 
suggest reforms to expedite studies for new generation paired with large loads at existing 
points of interconnection that have already been studied, arguing it is unjust and 
unreasonable not to fully utilize existing infrastructure and proven reliability paths while 
new load waits for service.207   
1. 
Jurisdiction 
 
The Commission’s statutory authority includes jurisdiction over the wholesale sale 
and transmission of electricity in interstate commerce, including the facilities used for 
 
202 Helion November 21 ANOPR Comments at 1 (citing Third Way, Picking Up 
the PACE:  A Comprehensive Analysis of Available Pathways to Accelerating Clean 
Energy (PACE) (Nov. 2025)). 
203 AEP December 5 ANOPR Comments at 1-2; OPSI November 21 ANOPR 
Comments at 6-7, 11.  
204 See, e.g., DTE November 21 ANOPR Comments at 8; ENGIE November 21 
ANOPR Comments at 4; International Energy Credit Association November 21 ANOPR 
Comments at 8; Meta November 21 ANOPR Comments at 5-6; Ohio FEA November 21 
ANOPR Comments at 5.  
205 AEP December 5 ANOPR Comments at 12; AEU November 21 ANOPR 
Comments at 13; Google December 5 ANOPR Comments at 15; see also Duke 
November 21 ANOPR Comments at 21-22.  
206 AEP December 5 ANOPR Comments at 4; Crusoe December 5 ANOPR 
Comments at 7; Enchanted Rock November 21 ANOPR Comments at 4; Google 
November 21 ANOPR Comments at 7; GridStor November 21 ANOPR Comments at 5; 
Verrus November 21 ANOPR Comments at 9. 
207 Constellation June 5 ANOPR Comments at 8-9.

Docket No. EL26-67-000 
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such sale and transmission.208  The Commission also has exclusive jurisdiction to 
regulate the procedures and agreements applicable to generating facilities seeking to 
interconnect to a Commission-jurisdictional distribution facility or transmission 
facility.209  In the PJM Co-Location Order, the Commission observed that a generator’s 
interconnection to the interstate transmission system “does not fall outside of the 
Commission’s jurisdiction merely because there is [c]o-[l]ocated [l]oad behind the 
generator’s point of interconnection.”210  By the same token, the Commission retains 
jurisdiction over a generator’s interconnection even where the generator plans to serve an 
electrically proximate large load.   
 
We recognize that states have exclusive authority over resource planning and the 
generation mix within their boundaries.211  Nothing about our preliminary finding here, 
however, intrudes or is intended to intrude on that exclusive authority.  Rather, we 
preliminarily find that it is necessary and appropriate to exercise our exclusive 
jurisdiction over generator interconnection to ensure the availability of generator 
interconnection processes specifically tailored to the unique operational characteristics of 
generating facilities dedicated to serving electrically proximate large loads and co-located 
loads, as defined below.  The Commission has exercised this jurisdiction previously in 
requiring generator interconnection services that allow certain generating facilities to 
interconnect more quickly through the use of provisional interconnection service and 
surplus interconnection service,212 and has approved interconnection processes that allow 
 
208 16 U.S.C. § 824(b)(1). 
209 Id.; Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 475 F.3d at 1280-82 
(affirming Order No. 2003 and observing that “interconnections appear to be 
relationships between parties with respect to electricity flowing over facilities. . . By 
establishing standard agreements [the Commission] has exercised its jurisdiction over 
the terms of those relationships.”); see Pac. Gas & Elec. Co., 115 FERC ¶ 61,193 at P 36 
(“[I]interconnection is part and parcel of transmission of electric energy in interstate 
commerce, and thus interconnection service is part and parcel of jurisdictional 
transmission service.”).  
210 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 171. 
211 See, e.g., Citizens Action Coal. of Ind., Inc. v. FERC, 125 F.4th at 238 (citing 
16 U.S.C. § 824(b)(1)).  
212 Reform of Generator Interconnection Procs. & Agreements, Order No. 845, 
163 FERC ¶ 61,043, at PP 438, 467 (2018), order on reh’g & clarification, Order        
No. 845-A, 166 FERC ¶ 61,137, order on reh’g & clarification, Order No. 845-B,       
168 FERC ¶ 61,092 (2019); Order No. 2023, 184 FERC ¶ 61,054 at P 1436; PJM 
Interconnection, L.L.C., 190 FERC ¶ 61,083 (2025).

Docket No. EL26-67-000 
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certain generating facilities to interconnect more quickly by replacing a retiring existing 
generating facility.213   
2. 
Definitions 
 
For purposes of this order, it appears to be reasonable to use the term “electrically 
proximate large load” to mean a large load, as defined in this order,214 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 (e.g., large load 
that is located no more than two substations away from the generating facility).  We will 
consider proposed revisions to this definition that ensure it is appropriately tailored to 
PJM’s transmission system. 
3. 
Tariff Provisions 
 
We preliminarily find that PJM’s Tariff appears to be unjust and unreasonable 
because it does not contain provisions allowing an interconnection customer to seek the 
generator interconnection service(s) that reflects the operational dynamics of serving 
either:  (1) an electrically proximate large load; or (2) a co-located load, as defined in the 
PJM Co-Location Order,215 that has a high peak load (i.e., large co-located loads that are 
50 MW or greater).216  Specifically, we preliminarily find that PJM’s Tariff appears to be 
unjust and unreasonable because it lacks a generator interconnection study process and/or 
generator interconnection service to reflect an interconnection customer’s commitment in 
an interconnection agreement to limit the generating facility’s output to minimize the 
impact on the transmission system while serving an electrically proximate large load or 
large co-located load.  We are concerned that PJM’s Tariff lacks, for example, generator 
interconnection study procedures and generator interconnection services that reflect (a) 
an interconnection customer’s commitment in an interconnection agreement to limit a 
generating facility’s output to match the hourly forecast of an electrically proximate large 
load or large co-located load; and/or (b) a generating facility with necessary control 
technologies and/or protection systems, which may include a special protection 
 
213 See, e.g., PJM Interconnection, L.L.C., 194 FERC ¶ 61,079 (2026); 
Midcontinent Indep. Sys. Operator Inc., 167 FERC ¶ 61,146 (2019).  
214 See supra P 58. 
215 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 164. 
216 We note that generator interconnection service in and of itself does not convey 
transmission service.

Docket No. EL26-67-000 
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scheme,217 that ensure that the injection does not exceed the limit in the existing or new 
interconnection agreement.  Where a generating facility’s output is matched to the 
demand of the electrically proximate large load or large co-located load or if the 
generating facility’s output is limited to ensure no new injection, the impacts to the 
transmission system of interconnecting the generating facility to serve that electrically 
proximate large load or large co-located load may be limited,218 thereby potentially 
reducing the need for Network Upgrades, which can accelerate the generator 
interconnection process.219  In the absence of Tariff provisions accounting for these 
operational dynamics when an interconnection customer’s generating facility is serving 
electrically proximate large loads or large co-located loads, new shovel-ready generating 
facilities may face unnecessary delays in reaching commercial operation under current 
generator interconnection processes and will be unable to serve the immediate demand of 
new large loads or large co-located loads.220    
 
217 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. 
218 In other words, because the generating facility and load are located so closely 
on the transmission system, if the generating facility’s output matches the load’s demand, 
then the transmission provider would need to study only the local impacts because 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. 
219 See, e.g., AEU November 21 ANOPR Comments at 13 (“To the extent that a 
new large load and new generation or storage resource are geographically and electrically 
proximate, studying them together would reduce network upgrades, lower costs, and 
reduce the need for critical supply chain components.”); DTE November 21 ANOPR 
Comments at 10 (integrating the study of load and its supporting generation “reduces the 
need for network upgrades, optimizes the use of existing infrastructure, and accelerates 
the timeline for bringing both load and generation online”); Eolian November 21 ANOPR 
Comments at 18 (“It is obvious from basic engineering principles that generation located 
near load requires less transmission infrastructure to serve that load than generation 
located distant from load.”); GridStor November 21 ANOPR Comments at 5 (“Siting a 
large load near or at the same point of interconnection as a new generating facility could 
reduce the network upgrades needed to interconnect only the load or only the generating 
facility.”).  
220 See AEP December 5 ANOPR Comments at 1; Base Power November 21 
ANOPR Comments at 7; CEBA November 21 ANOPR Comments at 8; DCC            
November 21 ANOPR Comments at 6 (asserting that a clear framework to study large 
loads paired with generation would resolve development bottlenecks); Eolian              
November 21 ANOPR Comments at 18-19; Eolian May 19 ANOPR Comments at 2;

Docket No. EL26-67-000 
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As commenters in the ANOPR proceeding have recognized, the status quo may 
result in inefficient and unnecessary development of infrastructure, which leads to 
unnecessarily higher Network Upgrade costs that may result in unjust and unreasonable 
rates.221  The Commission has already determined in the PJM Co-Location Order that 
without the new transmission services that reflect the operational dynamics of co-location 
arrangements, there could be unnecessary, costly, and inefficient Network Upgrades, 
increasing Network Upgrade costs.222  The same result may occur in the absence of new 
generator interconnection study procedures and generator interconnection services 
tailored to a new generating facility coming online for the express purpose of serving an 
electrically proximate large load or large co-located load.223    
 
SPP recognized this problem and submitted an FPA section 205 filing to 
implement a new, interim, generator interconnection service and related generator 
interconnection process, HILLGA, to facilitate the prompt interconnection of generating 
facilities that are specifically identified for and limited to serving a HILL, which the 
Commission accepted.224  The Commission found that HILLGA “reasonably provides a 
flexible, expedited, and separate serial interconnection process that will facilitate the 
prompt interconnection of generating facilities that are limited to serving a HILL in the 
 
Google November 21 ANOPR Comments at 7 (calling for nationwide rules enabling 
proximate load-generation interconnection to “accelerate the pace at which new 
generation comes online”); Longroad November 21 ANOPR Comments at 8. 
221 See, e.g., AEU November 21 ANOPR Comments at 13, AEP December 5 
ANOPR Comments at 1-2; Longroad November 21 ANOPR Comments at 8; OPSI 
November 21 ANOPR Comments at 11. 
222 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 177 (“[F]or Eligible 
Customers taking service on behalf of Co-Located Loads that do not reserve 
transmission . . . requiring such Eligible Customers to take NITS on behalf of these            
Co-Located Loads may in some circumstances result in costly and inefficient 
transmission system buildout that may not be necessary if such Eligible Customers are 
willing and able to take a transmission service that requires fewer Network Upgrades to 
provide, and therefore may result in lower Network Upgrade costs, than would NITS.”). 
223 See AEP December 5 ANOPR Comments at 1-2 (stating that current processes 
produce insufficient/inefficient infrastructure and “potentially unsustainable price 
increases”); Eolian May 19 ANOPR Comments at 2, 10 (contending that a lack of 
coordinated study leads to unjust and unreasonable outcomes).  
224 SPP HILL Order, 194 FERC ¶ 61,031.

Docket No. EL26-67-000 
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same local area.”225  We do not expect or propose that PJM adopt an identical process to 
SPP’s HILLGA process, nor do we preliminarily find that the absence of Tariff 
provisions specifically mirroring SPP’s Tariff renders PJM’s Tariff unjust and 
unreasonable.  Nevertheless, we remain concerned that the Tariff may be unjust and 
unreasonable without any uniquely tailored interconnection study process and/or 
generator interconnection service to recognize the reduced transmission system impacts 
that may result from the interconnection of a generating facility where the 
interconnection customer has committed, in an interconnection agreement, to limit the 
generating facility’s output to match the hourly forecast of an electrically proximate large 
load or large co-located load.226  To the extent that the interconnection customer’s 
generating facility is serving an electrically proximate large load, we believe that the 
generator interconnection service should be of an interim nature until the interconnection 
customer obtains Energy Resource Interconnection Service (ERIS) or Network Resource 
Interconnection Service (NRIS).  To the extent that the interconnection customer’s 
generating facility is serving a large co-located load, it may be reasonable for the 
generator interconnection service to be permanent because there will be no injections 
onto the transmission system and therefore it does not present operational or planning 
risks for reliability.   
 
Another potentially reasonable approach to address our concerns could be to 
develop a generator interconnection study process that would allow the use of existing 
ERIS or NRIS of an existing generator to connect a new generating facility and a new 
large load behind the same point of interconnection of the existing generator with 
necessary control technologies and/or protection systems, which may include a special 
protection scheme, that ensure that the net injection does not exceed the amount in the 
existing generator interconnection agreement.227  Such an approach could expedite the 
interconnection study process for a generator planning to serve an electrically proximate 
 
225 Id. P 64. 
226 While, as discussed above, we view such a process that permits generation to 
serve electrically proximate loads no more than two substations away from the generators 
to be reasonable, we understand the unique features of PJM’s transmission system may 
warrant consideration of a more limited definition of electrically proximate.  See Duke 
November 21 ANOPR Comments at 21-22; DTE November 21 ANOPR Comments               
at 8-11 (asserting that studying large loads with electrically proximate generation 
streamlines interconnection and reduces upgrades); AEU November 21 ANOPR 
Comments at 13-15. 
227 See Constellation June 5 ANOPR Comments at 1-2, 10-13.

Docket No. EL26-67-000 
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(in this case at the same point of interconnection) large load.228  An additional potentially 
reasonable approach could be a new load-limited generator interconnection service that 
allows a new generating facility and new large co-located load seeking to interconnect 
behind the same new point of interconnection, with necessary control technologies and/or 
protection systems, which may include a special protection scheme, to ensure that there is 
no injection to the transmission system.229  It may be reasonable for such a load-limited 
generator interconnection service to be or not to be of an interim nature.  We invite PJM 
and/or Transmission Owners, in responding to this order or in an FPA section 205 filing, 
to submit original proposals designed to address the concerns expressed herein and 
tailored to their unique circumstances.  
 
We are concerned that the absence of generator interconnection study procedures 
and generator interconnection services facilitating the interconnection of a new 
generating facility that is being brought onto the transmission system in order to serve an 
electrically proximate large load or large co-located load will result in PJM’s current 
generator interconnection process failing to keep pace with the new large loads seeking to 
be integrated onto PJM’s transmission system.230  We preliminarily find that this 
outcome may be unjust and unreasonable because reliance on PJM’s current generator 
interconnection processes for generating facilities serving electrically proximate large 
loads or large co-located loads could result in unnecessary interconnection delays, 
unnecessary Network Upgrades, and an otherwise inefficient expansion of the 
transmission system, imposing unnecessary delays and costs on transmission customers. 
 PJM should explain whether the Tariff remains just and reasonable without, for 
example, provisions that establish:  (1) a new generator interconnection study process and 
new interim generator interconnection service that reflect an interconnection customer’s 
 
228 See id. at 5 (explaining that when new generation load pairings “are sited at an 
existing generator’s Point of Interconnection and fall within the same study parameters 
reflected by that existing generator’s interconnection, they benefit from studies and 
upgrades already completed for that existing generator and can come on more rapidly 
without jeopardizing reliability”). 
229 See MISO November 21 ANOPR Comments at 13; see also MISO TOs April 3 
ANOPR Comments at 13-14.   
230 See Helion November 21 ANOPR Comments at 1 (noting interconnection 
delays are the biggest barrier to adding new generation); Oracle November 21 ANOPR 
Comments at 1 (noting significant delays in access to sufficient energy for data centers); 
OPSI November 21 ANOPR Comments at 11 (explaining that expedited study 
encourages loads to bring their own generation); Enchanted Rock November 21 ANOPR 
Comments at 4; Microsoft November 21 ANOPR Comments at 8-9.

Docket No. EL26-67-000 
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commitment, in a generator interconnection agreement, to limit a generating facility’s 
output to match the hourly forecast of an electrically proximate large load or large               
co-located load; or (2) a generator interconnection study process that allows the use of the 
existing ERIS or NRIS of an existing generator to connect a new generating facility and a 
new large load behind the same point of interconnection of the existing generator with 
necessary control technologies and/or protection systems, which may include a special 
protection scheme, that ensures that the net injection does not exceed the amount in the 
existing generator interconnection agreement; or (3) a new generator interconnection 
service that allows a new generating facility and new large co-located load seeking to 
interconnect behind the same new point of interconnection with necessary control 
technologies and/or protection systems, which may include a special protection scheme, 
to ensure that there is no injection to the transmission system.  We note that, with respect 
to numbers (2) or (3), these approaches could be either interim or permanent.  These 
approaches may not be mutually exclusive. 
 Given that generator interconnection service in and of itself does not convey 
transmission service, we encourage PJM to consider, in responding to these concerns, 
what type of transmission service an Eligible Customer will need to take on behalf of the 
electrically proximate large load or large co-located load.231  We note that, in the PJM 
Co-Location Order, the Commission found that the Eligible Customer must take 
transmission service on behalf of co-located load that will not withdraw energy from the 
transmission system, even if it is 0 MW.232 
E. 
Informational Report 
 The rapid addition and proliferation of large loads without commensurate 
additions of supply or demand-side resources presents resource adequacy concerns.  As 
discussed above and highlighted in the ANOPR, the growth of demand, and the speed of 
such growth, is driven in large part by the interconnection of large loads.  While not 
expressly contemplated in the ANOPR, commenters highlight the strain rapid demand 
growth is putting on resource adequacy in many regions.233  Indeed, the relative speed 
and concentration at which large loads are seeking to interconnect appears to be 
outpacing the addition of new generation, which in turn heightens reliability risks and 
 
231 See SPP HILL Order, 194 FERC ¶ 61,031 at P 34. 
232 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 206. 
233 See, e.g., Entergy November 21 ANOPR Comments at 29-30; Eolian 
November 21 ANOPR Comments at 16-17; Industrial Customers November 21 ANOPR 
Comments at 24-26; R Street November 21 ANOPR Comments at 1; South Dakota 
Commission November 13 ANOPR Comments at 5; Talen December 5 ANOPR 
Comments at 7.

Docket No. EL26-67-000 
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drives up costs to ratepayers.234  We are concerned that PJM and load serving entities are 
unable to plan adequate generation to serve all load at the pace such load seeks to 
connect.   
 We recognize that RTOs/ISOs are engaging in efforts to more rapidly interconnect 
generation that is needed to serve this unprecedented growth in load.  In particular, PJM’s 
Reliability Resource Initiative and Expedited Interconnection Track have provided 
pathways for expedited interconnection for generation.235  Further, as detailed above and 
in informational reports submitted by PJM,236 PJM has ongoing stakeholder processes to 
address resource adequacy issues related to large load additions, including a voluntary 
“Bring Your Own New Generation” pathway for large loads, a “connect-and-manage” 
framework applicable to new large loads that do not bring commensurate new generating 
capacity, and a reliability backstop procurement.237  While we are encouraged by the 
implementation of such processes to ensure resource adequacy and faster interconnection 
and ongoing stakeholder discussions, we remain concerned that these efforts may fall 
short in light of generator retirements and tightening supply conditions. 
 Accordingly, we direct PJM to submit in Docket No. EL26-67-000, within 30 days 
of the date of issuance of this order, a detailed informational report on the current status 
of proposals under consideration in its stakeholder process to address the issue of 
resource adequacy to serve new large loads.  We also strongly encourage new proposals 
to the extent necessary to address these concerns.  The informational report must include 
a detailed schedule of key milestones, such as stakeholder or PJM Board votes, that 
includes the estimated date on which PJM expects to file any such proposals with the 
Commission.  Additionally, as part of this informational report, we direct PJM to identify 
any problem statements, issue charges, or other ongoing stakeholder processes that aim to 
increase the pace of adding generating capacity in the PJM region.  The informational 
 
234 See, e.g., Eolian November 21 ANOPR Comments at 16-17; David Gardiner & 
Associates November 21 ANOPR Comments at 1-2; Joint Consumer Advocates 
December 5 ANOPR Comments at 2; PSEG November 21 ANOPR Comments at 8; 
Southern California Edison December 5 ANOPR Comments at 3. 
235 PJM Interconnection, L.L.C., 190 FERC ¶ 61,084; order on reh’g, 192 FERC 
¶ 61,085 (2025); PJM EIT Order, 195 FERC ¶ 61,197. 
236 PJM Interconnection, L.L.C., Informational Report, Docket No. EL25-49-000,  
et al. (filed Jan. 20, 2026); PJM Interconnection, L.L.C., Supplemental Informational 
Report, Docket No. EL25-49-000, et al. (filed Feb. 23, 2026); PJM Interconnection, 
L.L.C., Second Supplemental Informational Report, Docket No. EL25-49-000, et al. 
(filed Mar. 9, 2026). 
237 See supra P 33.

Docket No. EL26-67-000 
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report must include a detailed schedule of such initiatives, including timing of the 
stakeholder process and dates of any anticipated filings with the Commission.   
IV. 
Briefing Questions 
 We note that large loads, including data centers, are actively working with 
transmission owners and other relevant entities to interconnect to, and to take 
interconnection and/or transmission service from, the transmission system and may be at 
varying stages of that process.  We appreciate that different large loads are currently at 
different stages of that process.  We also understand that large loads and Eligible 
Customers taking transmission service on behalf of large loads are negotiating, entering 
into, and/or have executed various agreements related to interconnecting to the 
transmission system and/or the provision of transmission service.  We direct further 
briefing regarding how PJM and the Transmission Owners, in responding to the order to 
show cause, should protect existing commercial arrangements including:  (1) what would 
be a reasonable implementation period to ensure minimal disruption to such existing 
commercial arrangements, and (2) how to allow a reasonable amount of time to finalize 
ongoing agreements that are nearing completion as of the date such Tariff provisions are 
filed with the Commission.  
 Today’s order proposes, as part of a potential replacement rate, to establish new 
transmission services that recognize flexible large loads’ ability and willingness to limit 
their use of the transmission system under certain conditions.  As we assess this proposal, 
we also consider how these new transmission services might affect other parts of PJM’s 
Tariff and/or processes.  Specifically, what, if any, potential impacts on regional and 
local transmission planning would arise from the introduction of the new transmission 
services discussed herein?  For example, when planning for load growth, how would 
transmission providers and planners account for flexible large loads’ potential preference 
to take the new transmission services, including potential uncertainties around the type, 
location, and quantity of such expected loads?     
 Today’s order preliminarily finds that PJM’s Tariff appears to be unjust and 
unreasonable without the inclusion of cost shifting protections.  We find that there may 
be a variety of possible approaches to protect customers from significant cost shifts 
associated with Network Upgrades triggered by large loads.  To that end, we direct 
respondents to include information regarding potential structures for agreements between 
the transmission owner/provider and an Eligible Customer to prevent unjust and 
unreasonable cost shifts among transmission customers related to Network Upgrade costs 
required for large loads.  Further, please include information on what an appropriate 
minimum level of cost recovery and financial security from an Eligible Customer would 
be under any such agreements.

Docket No. EL26-67-000 
- 70 - 
 Today’s order preliminarily finds that PJM’s Tariff appears to be unjust and 
unreasonable because it lacks clear and consistent provisions requiring the evaluation of 
alternative transmission technologies.  The order directs PJM to explain whether the 
Tariff remains just and reasonable without provisions that:  (1) require the evaluation of 
alternative transmission technologies in transmission service request studies, using 
models that are capable of evaluating the transmission system to accurately account for 
advanced transmission technologies, in all instances, without the need for a request from 
the Eligible Customer seeking transmission service on behalf of large load; and (2) if 
traditional Network Upgrades are selected instead of alternative transmission 
technologies, inclusion in the study report to the Eligible Customer seeking transmission 
service on behalf of large load of a sufficiently clear demonstration of why alternative 
transmission technologies are not feasible (i.e., would not resolve reliability violations 
identified or meet the relevant planning criteria) or would not result in lower costs or a 
faster timeline for accommodating the transmission service request.  As noted above, to 
the extent stakeholders believe that specific characteristics of providing transmission 
service to Eligible Customers on behalf of large loads warrant requirements beyond those 
contemplated here, we seek further briefing. 
 Today’s order preliminarily finds that PJM’s Tariff appears to be unjust and 
unreasonable because it does not contain provisions allowing an interconnection 
customer serving electrically proximate large load or large co-located load to seek 
generator interconnection service(s) that reflects the operational dynamics of serving such 
loads.  Any filings or tariff changes submitted in response to this order should address the 
following questions:  
a. To what extent would PJM allow an interconnection customer’s generating 
facility serving electrically proximate large load or large co-located load to 
participate in PJM’s energy and ancillary services market, and if PJM were 
to allow them to participate, what restrictions or mitigation would PJM 
apply? 
b. To the extent that PJM plans for the electrically proximate large load or 
large co-located load associated with an interconnection customer’s 
generating facility for resource adequacy purposes, would PJM account for 
the generating facilities serving electrically proximate large load or large 
co-located load in the resource adequacy construct?  If applicable, would 
PJM allow the generating facilities serving electrically proximate large load 
or large co-located load to participate in PJM’s capacity market?  If so, 
would PJM accredit these generating facilities using the same method as 
other PJM generating facilities? 
The Commission orders:

Docket No. EL26-67-000 
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(A) 
Pursuant to the authority contained in and subject to the jurisdiction 
conferred upon the Federal Energy Regulatory Commission by section 402(a) of the 
Department of Energy Organization Act and by the FPA, particularly section 206 thereof, 
and pursuant to the Commission’s Rules of Practice and Procedure and the regulations 
under the FPA (18 C.F.R. Chapter I), the Commission hereby institutes a proceeding in 
Docket No. EL26-67-000 as discussed in the body of this order. 
(B) 
PJM and the Transmission Owners are hereby directed, within 60 days of 
the date of the order, either:  (1) to show cause as to why the Tariff remains just and 
reasonable and not unduly discriminatory or preferential; or (2) to explain what changes 
to the Tariff they believe would remedy the identified concerns if the Commission were 
to determine that the Tariff has in fact become unjust and unreasonable or unduly 
discriminatory or preferential and, therefore, proceeds to establish a replacement Tariff. 
(C) 
PJM is directed to submit an informational report within 30 days of the date 
of issuance of this order, as discussed in the body of this order. 
(D) 
Any interested person desiring to be heard in Docket No. EL26-67-000 
must file a notice of intervention or motion to intervene, as appropriate, with the          
Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC  20426, 
in accordance with Rule 214 of the Commission’s Rules of Practice and Procedure,           
18 C.F.R. § 385.214 (2025), within 21 days of the date of issuance of this order.  The 
Commission encourages electronic submission of interventions in lieu of paper using the 
“eFiling” link at http://www.ferc.gov.  Persons unable to file electronically may file by 
U.S. mail addressed to Federal Energy Regulatory Commission, Secretary of the 
Commission, 888 First Street, N.E., Washington, DC  20426, or by hand (including 
courier) delivery to Federal Energy Regulatory Commission, 12225 Wilkins Avenue, 
Rockville, MD  20852. 
(E) 
Interested entities may respond within 30 days of PJM’s and the 
Transmission Owners’ filing, addressing either or both of:  (1) whether the Tariff remains 
just and reasonable and not unduly discriminatory or preferential; and (2) if not, what 
changes to the Tariff should be implemented as a replacement rate. 
(F) 
The Secretary shall promptly publish in the Federal Register a notice of the 
Commission’s initiation of the proceeding under section 206 of the FPA in Docket               
No. EL26-67-000. 
(G) 
The refund effective date in Docket No. EL26-67-000 pursuant to               
section 206 of the FPA shall be the date of publication in the Federal Register of the 
notice discussed in Ordering Paragraph (F) above. 
By the Commission.  Chairman Swett is concurring with a separate statement attached. 
 
 
 
  Commissioner Rosner is concurring with a separate statement

Docket No. EL26-67-000 
- 72 - 
 
 
 
  attached. 
 
 
 
  Commissioner See is concurring with a separate statement attached. 
 
 
 
  Commissioner Chang is concurring with a separate statement 
  
 
 
  attached. 
 
 
 
  Commissioner LaCerte is concurring with a separate statement 
  
 
 
  attached. 
 
( S E A L ) 
 
 
 
 
 
 
 
 
 
 
Debbie-Anne A. Reese, 
Secretary.

Docket No. EL26-67-000 
- 73 - 
Appendix - Commenters in Docket No. RM26-4-000 
 
Advanced Energy Management Alliance (AEMA) 
Advanced Energy United (AEU) 
Advancing Modern Powerlines Coalition (together with Working for Advanced 
Transmission Technologies Coalition, WATT and Advancing Modern Powerlines) 
Advocates for Consumer Regulated Electricity 
AES Corporation (AES) 
AI Supply Chain Alliance 
Alexandre Figueras, on behalf of Monza Tech 
Alliance for Tribal Clean Energy 
Alliant Energy Corporate Services, Inc. 
Amazon Energy LLC (Amazon) 
America’s Power  
American Chemistry Council  
American Clean Power Association  
American Conservation Coalition 
American Council on Renewable Energy (ACORE) 
American Electric Power Service Corporation238 
American Public Gas Association 
American Public Power Association (APPA) 
American Terawatt, Inc. (American Terawatt) 
American Transmission Company LLC239 
Americans for a Clean Energy Grid 
Antora Energy, Inc.  
Arevia Power 
Arizona Public Service Company 
Arkansas Public Service Commission 
Attorney General of the State of Oklahoma 
 
238 American Electric Power Service Corporation submitted comments on behalf 
of its affiliates Appalachian Power Company, Indiana Michigan Power Company, 
Kentucky Power Company, Kingsport Power Company, Ohio Power Company, 
Wheeling Power Company, Public Service Company of Oklahoma, Southwestern 
Electric Power Company, AEP Appalachian Transmission Company, Inc., AEP Indiana 
Michigan Transmission Company, Inc., AEP Kentucky Transmission Company, Inc., 
AEP Ohio Transmission Company, Inc., AEP West Virginia Transmission Company, 
Inc., AEP Oklahoma Transmission Company, Inc., and AEP Southwestern Transmission 
Company, Inc. 
239 American Transmission Company LLC submitted comments on behalf of itself 
and its corporate manager ATC Management Inc.

Docket No. EL26-67-000 
- 74 - 
Base Power Company, Inc (Base Power). 
Bloom Energy Corporation 
Buckeye Power, Inc. (Buckeye) 
Calibrant Energy Holdings, LLC (Calibrant) 
California Department of Water Resources State Water Project (California DWR) 
California Independent System Operator Corporation 
California Public Utilities Commission (CPUC) 
Center for Biological Diversity 
Chevron U.S.A., Inc. 
Clean Energy Buyers Association (CEBA) 
ClearPath, Inc. (ClearPath) 
Confederated Tribes and Bands of the Yakama Nation 
Constellation Energy Generation, LLC (Constellation) 
Consumer Energy Alliance 
Consumers Energy Company 
Critical Loop, Inc. (Critical Loop) 
Crusoe Energy Systems, Inc. (Crusoe) 
CTC Global Corporation 
Data Center Coalition (DCC) 
David Gardiner & Associates  
Delaware Division of the Public Advocate (together with Pennsylvania Office of  
Consumer Advocate, Joint Consumer Advocates)240 
Digital Energy Council  
Digital Power Network 
Distributed Capacity Parties241 
Dr. Elisa Nelson 
DTE Electric Company (DTE) 
Duke Energy Corporation (Duke) 
EDF Power Solutions, Inc. (EDF Power) 
Edison Electric Institute (EEI) 
Electricity Consumers Resource Council (ELCON) 
Electricity Customers Alliance (ECA) 
Electric Power Supply Association (EPSA) 
Emerald AI (Emerald) 
Enchanted Rock, LLC  
Energy New England, LLC 
 
240 The Illinois Attorney General joined the Joint Consumer Advocates in filing 
reply comments. 
241 Distributed Capacity Parties include:  Cloverleaf Infrastructure; Spark 
Community Investment d/b/a Sparkfund; and Voltus, Inc.

Docket No. EL26-67-000 
- 75 - 
Energy Trading Institute 
ENGIE North America, Inc. (ENGIE) 
Entergy Services, LLC (Entergy)242 
Environmental Law & Policy Center 
Eolian L.P. (Eolian) 
Equinix, Inc. 
esVolta, LP 
ETX Upstream, LLC 
Eversource Energy243 
Exelon Corporation (Exelon)244 
Fervo Energy Company (Fervo) 
FirstEnergy Service Company245 
Fluence 
Front Door Technologies LLC 
FuelCell Energy, Inc. 
Georgia Public Service Commission  
Geronimo Power, LLC (Geronimo) 
Google LLC (Google) 
Governors Josh Shapiro and Glenn Youngkin 
GridCARE 
GridStor LLC (GridStor) 
Harvard Electricity Law Initiative 
 
242 Entergy submitted comments on behalf of the Entergy Operating Companies, 
which include Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, 
LLC, Entergy New Orleans, LLC, and Entergy Texas, Inc. 
243 Eversource Energy submitted comments on behalf of its affiliates The 
Connecticut Light and Power Company, NSTAR Electric Company, and Public Service 
Company of New Hampshire, and through its agent Eversource Energy Service 
Company. 
244 Exelon submitted comments on behalf of itself and its affiliates Atlantic City 
Electric Company, Baltimore Gas and Electric Company, Commonwealth Edison 
Company, Commonwealth Edison Company of Indiana, Inc., Delmarva Power and Light 
Company, PECO Energy Company, and Potomac Electric Power Company. 
245 FirstEnergy Service Company submitted comments on behalf of itself and its 
affiliates American Transmission Systems, Inc., Jersey Central Power & Light Company, 
Mid-Atlantic Interstate Transmission LLC, Keystone Appalachian Transmission 
Company, The Potomac Edison Company, Monongahela Power Company, and                 
Trans-Allegheny Interstate Line Company.

Docket No. EL26-67-000 
- 76 - 
Helion Energy (Helion) 
Herbert Schrayschuen 
Heron Power Electronics Company  
Indiana Energy Association 
Indicated PJM Transmission Owners (PJM TOs)246 
Industrial Customer Organizations (Industrial Customers)247 
Information Technology Industry Council 
Infrastructure Masons, Inc. (Infrastructure Masons) 
Institute for Progress 
International Energy Credit Association 
Invenergy248 
Iron Mountain Data Centers, LLC 
 
246 PJM TOs include:  AEP on behalf of Appalachian Power Company, Indiana 
Michigan Power Company, Kentucky Power Company, Kingsport Power Company, 
Ohio Power Company, Wheeling Power Company, AEP Appalachian Transmission 
Company, Inc., AEP Indiana Michigan Transmission Company, Inc., AEP Kentucky 
Transmission Company, Inc., AEP Ohio Transmission Company, Inc., and AEP West 
Virginia Transmission Company, Inc.; AMP Transmission, LLC; City of Cleveland, 
Department of Public Utilities, Division of Cleveland Public Power; City of Hamilton, 
OH; Dominion Energy Services, Inc. on behalf of Virginia Electric and Power Company 
d/b/a Dominion Energy Virginia; Duke Energy Corporation on behalf of its affiliates 
Duke Energy Ohio, Inc., Duke Energy Kentucky, Inc., and Duke Energy Business 
Services LLC; Duquesne Light Company; East Kentucky Power Cooperative; Exelon 
Corporation, on behalf of Atlantic City Electric Company, Baltimore Gas and Electric 
Company, Commonwealth Edison Company, Commonwealth Edison Company of 
Indiana, Inc., Delmarva Power & Light Company, PECO Energy Company, and Potomac 
Electric Power Company; FirstEnergy Service Company, as agent for its affiliates 
American Transmission Systems, Incorporated, Jersey Central Power & Light Company, 
Mid-Atlantic Interstate Transmission LLC, Keystone Appalachian Transmission 
Company, The Potomac Edison Company, Monongahela Power Company and Trans-
Allegheny Interstate Line Company; Old Dominion Electric Cooperative; PPL Electric 
Utilities Corporation; Rockland Electric Company; Southern Maryland Electric 
Cooperative, Inc.; UGI Utilities Inc; and Wabash Valley Power Association, Inc. 
247 Industrial Customers include:  the Industrial Energy Consumers of America, 
the American Forest & Paper Association, the PJM Industrial Customer Coalition, and 
the Coalition of MISO Transmission Customers 
248 Invenergy includes:  Invenergy Wind Development North America LLC, 
Invenergy Solar Development North America LLC, and Invenergy Thermal Development 
Holdings LLC.

Docket No. EL26-67-000 
- 77 - 
ISO New England, Inc. 
ITC Holdings Corp. (ITC) 
Jason Miller, on behalf of VEIR Inc. 
Kansas Corporation Commission (Kansas Commission) 
L. Lynne Kiesling 
L.M. Marlowe 
Land Trust Alliance 
Large Public Power Council 
Lauren Hopkins 
LEAN Energy US 
Load Flexibility Parties249 
Long Island Power Authority 
Longroad Energy Holdings, LLC (Longroad) 
Louisiana Public Service Commission  
LS Power Development, LLC (LS Power) 
Maine Office of the Public Advocate 
Maryland Energy Administration  
Maryland Public Service Commission (Maryland Commission) 
Maven Solutions  
MCC Economics and Finance 
Meta Platforms, Inc. 
Michigan Attorney General Dana Nessel 
Microsoft, Inc. (Microsoft) 
Midcontinent Independent System Operator, Inc. 
MISO Transmission Owners (MISO TOs)250 
 
249 Load Flexibility Parties include:  Enerwise Global Technologies, LLC d/b/a 
CPower, Enel North America, Inc., and Voltus, Inc. 
250 MISO TOs include:  Ameren Services Company, as agent for Union Electric 
Company d/b/a Ameren Missouri, Ameren Illinois Company d/b/a Ameren Illinois and 
Ameren Transmission Company of Illinois; American Transmission Company LLC; Big 
Rivers Electric Corporation; Central Minnesota Municipal Power Agency; Citizens 
Electric Corporation; City Water, Light & Power (Springfield, IL); Cleco Power LLC; 
Cooperative Energy; Dairyland Power Cooperative; Duke Energy Business Services, 
LLC for Duke Energy Indiana, LLC; East Texas Electric Cooperative; Entergy Arkansas, 
LLC; Entergy Louisiana, LLC; Entergy Mississippi, LLC; Entergy New Orleans, LLC; 
Entergy Texas, Inc.; Great River Energy; GridLiance Heartland LLC; Hoosier Energy 
Rural Electric Cooperative, Inc.; Indiana Municipal Power Agency; Indianapolis Power 
& Light Company d/b/a AES Indiana; Lafayette Utilities System; MidAmerican Energy 
Company; Minnesota Power (and its subsidiary Superior Water, L&P); Montana-Dakota 
Utilities Co.; Northern Indiana Public Service Company LLC; Northern States Power 
Company, a Minnesota corporation, and Northern States Power Company, a Wisconsin

Docket No. EL26-67-000 
- 78 - 
Mississippi Public Service Commission  
Missouri Public Service Commission (Missouri Commission) 
Monitoring Analytics, LLC, acting in its capacity as the Independent Market Monitor for 
PJM (PJM IMM) 
Nathan Peterson 
National Association of Regulatory Utility Commissioners  
National Association of State Utility Consumer Advocates 
National Conference of State Legislatures (NCSL) 
National Congress of American Indians 
National Grid PLC (National Grid)251 
National Rural Electric Cooperative Association (NRECA) 
Nebraska Power Review Board (Nebraska Board) 
New England States Committee on Electricity 
New England Conference of Public Utility Commissioners 
New England Consumer-Owned Systems252  
 
corporation, subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric 
Company; Otter Tail Power Company; Prairie Power, Inc.; Republic Transmission, LLC; 
Southern Illinois Power Cooperative; Southern Indiana Gas & Electric Company (d/b/a 
CenterPoint Energy Indiana South); Southern Minnesota Municipal Power Agency; 
Wabash Valley Power Association, Inc.; and Wolverine Power Supply Cooperative, Inc 
251 National Grid submitted comments behalf of its affiliates:  Niagara Mohawk 
Power Corporation; New England Power Company; New England Electric Transmission 
Corporation; New England Hydro-Transmission Corporation; New England                   
Hydro-Transmission Electric Company, Inc.; and Massachusetts Electric Company. 
252 New England Consumer-Owned Systems include:  Belmont Municipal Light 
Department, Block Island Utility District, Braintree Electric Light Department, Concord 
Municipal Light Plant, Danvers Electric Division, Georgetown Municipal Light 
Department, Groveland Electric Light Department, Hingham Municipal Lighting Plant, 
Hudson Light & Power Department, Littleton Electric Light & Water Department, 
Merrimac Municipal Light Department, Middleborough Gas & Electric Department, 
Middleton Electric Light Department, North Attleborough Electric Department, Norwood 
Municipal Light Department, Clear River Electric & Water District, Rowley Municipal 
Lighting Plant, Stowe Electric Department, Taunton Municipal Lighting Plant, Town of 
Wallingford, Connecticut Department of Public Utilities Electric Division, Westfield Gas 
and Electric Light Department, and Mid-Coast Regional Redevelopment Authority.

Docket No. EL26-67-000 
- 79 - 
New England Public Systems253 
New Mexico Public Regulation Commission (New Mexico Commission) 
New York Independent System Operator, Inc. 
New York State Department of State Utility Intervention Unit (NY UIU) 
New York Public Service Commission 
New York State Reliability Council 
New York Transmission Owners254 
North American Electric Reliability Corporation 
North Carolina Utilities Commission 
North Carolina Utilities Commission Public Staff 
North Dakota Public Service Commission 
Northeastern Rural Electric Membership Corporation 
NRG Energy, Inc. 
Office of the Illinois Attorney General (Illinois AG) 
Office of the Ohio Consumers’ Counsel (OCC) 
Oklahoma Corporation Commission 
Oklo Inc. (Oklo) 
Old Dominion Electric Cooperative (ODEC) 
Oncor Electric Delivery Company LLC 
ON Energy Storage, Inc. 
OpenAI Inc. 
Oracle America, Inc. (Oracle) 
Organization of MISO States, Inc. (OMS) 
Organization of PJM States, Inc. (OPSI) 
Paces AI Inc. 
Pacific Gas & Electric Company 
Paige Lambermont, on behalf of Competitive Enterprise Institute 
Paul Statchen 
Pennsylvania Office of Consumer Advocate 
Pennsylvania Public Utility Commission (Pennsylvania Commission) 
Pew Charitable Trusts Energy Modernization Project 
PJM Interconnection, LLC (PJM) 
 
253 New England Public Systems include:  Connecticut Municipal Electric 
Cooperative, Massachusetts Municipal Wholesale Electric Company, and Vermont 
Public Power Supply Authority. 
254 New York Transmission Owners include:  Central Hudson Gas & Electric 
Corporation, Consolidated Edison Company of New York, Inc., New York Power 
Authority, New York State Electric & Gas Corporation, Niagara Mohawk Power Corp. 
(d/b/a National Grid), Orange and Rockland Utilities, Inc., Long Island Power Authority, 
and Rochester Gas and Electric Corporation.

Docket No. EL26-67-000 
- 80 - 
Power for Tomorrow 
PPL Corporation255 
Prime Mover Institute 
PSEG Companies (PSEG)256 
Public Citizen, Inc. 
Public Interest Organizations (PIOs)257 
Public Utilities Commission of Ohio’s Office of the Federal Energy Advocate (Ohio  
FEA) 
R Street Institute (R Street) 
Rewiring America 
MCC Economics Ltd. 
RWE Clean Energy, LLC 
Sarah McKinley 
Shell Energy North America (US), L.P. 
Sierra Club 
SMA Solar Technology AG 
Solar Energy Industries Association 
South Carolina Office of Regulatory Staff 
South Dakota Public Utilities Commission (South Dakota Commission) 
Southeast Public Interest Organizations (Southeast PIOs)258 
Southern California Edison Company (Southern California Edison) 
Southern Companies259 
 
255 PPL Corporation submitted comments on behalf of the PPL Companies, which 
include PPL Electric Utilities Corporation, Louisville Gas & Electric Company and 
Kentucky Utilities, and The Narragansett Electric Company d/b/a Rhode Island Energy. 
256 PSEG Companies include:  Public Service and Gas Company, PSEG Power 
LLC, and PSEG Energy Resources & Trade LLC, which are each wholly-owned, direct 
or indirect subsidiaries of Public Service Enterprise Group Incorporated. 
257 PIOs include:  Clean Air Task Force, Inc., Coalition for Affordable Utility 
Services and Energy Efficiency in Pennsylvania, Earthjustice, Environmental Defense 
Fund, Montana Environmental Information Center, Natural Resources Defense Council, 
Sustainable FERC Project, Sierra Club, and Southern Environmental Law Center. 
258 Southeast PIOs include:  Southern Environmental Law Center, Appalachian 
Voices, North Carolina Sustainable Energy Association, South Carolina Coastal 
Conservation League, and Southern Alliance for Clean Energy. 
259 Southern Companies include:  Georgia Power Company, Alabama Power 
Company, and Mississippi Power Company.

Docket No. EL26-67-000 
- 81 - 
Southern Maryland Electric Cooperative, Inc. 
Southwest Power Pool, Inc. 
Southwest Power Pool Transmission Owner Group260 
Splight Inc. (Splight) 
State Entities261 
Steel Manufacturers Association 
Switch, Ltd. (Switch) 
Talen Energy Corporation (Talen) 
Terraflux LLC (Terraflux) 
Tesla, Inc. 
Texas Blockchain Council 
Thermal Battery Alliance 
Tract Holding Company I, LLC (Tract) 
Transmission Access Policy Study Group (TAPS) 
Tri-State Generation and Transmission Association, Inc. (Tri-State) 
Travis Fisher, on behalf of Cato Institute 
U.S. Chamber of Commerce (Chamber of Commerce) 
U.S. Energy Storage Coalition 
U.S. House of Representatives Committee on Energy and Commerce Ranking  
Members262 
U.S. Representatives263 
U.S. Senate Committee on Energy and Natural Resources 
 
260 Southwest Power Pool Transmission Owner Group includes:  American 
Electric Power Service Corporation, Evergy Kansas Central, Inc., Evergy Metro, Inc., 
Evergy Missouri West, Inc., Oklahoma Gas and Electric Company, and Xcel Energy 
Services Inc., on behalf of Southwestern Public Service Company. 
261 State Entities include:  Massachusetts Attorney General’s Office, the Arizona 
Attorney General’s Office, the Colorado Attorney General’s Office, the Connecticut 
Office of Consumer Counsel, the Maryland Office of People’s Counsel, the Minnesota 
Attorney General’s Office, the Office of the Nevada Attorney General, Bureau of 
Consumer Protection, the New Hampshire Office of the Consumer Advocate, the Oregon 
Attorney General, and the Rhode Island Division of Public Utilities and Carriers. 
262 Submitted by Frank Pallone, Jr. (Ranking Member) and Kathy Castor (Ranking 
Member, Subcommittee on Energy). 
263 The U.S. Representatives that submitted comments include:  Suhas 
Subramanyam, John W. Mannion, Mike Quigley, and Donald S. Beyer Jr.

Docket No. EL26-67-000 
- 82 - 
U.S. Senators264 
U.S. Senator Jon Ossoff 
Union of Concerned Scientists (UCS) 
Vantage Data Centers (Vantage) 
Verrus 
Virginia State Corporation Commission (Virginia Commission)  
Vistra Corp. (Vistra) 
Washington Utilities and Transportation Commission 
WIRES 
Wisconsin Electric Company 
Wisconsin Public Service Corporation  
 
 
 
264 The U.S. Senators that submitted comments include:  Edward J. Markey, Chris 
Van Hollen, Elizabeth Warren, Peter Welch, Raphael Warnock, Richard Blumenthal, and 
Adam B. Schiff.

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
 
PJM Interconnection, L.L.C.  
AEP Appalachian Transmission Company, Inc. 
AEP Indiana Michigan Transmission Company, Inc. 
AEP Kentucky Transmission Company, Inc. 
AEP Ohio Transmission Company, Inc. 
AEP West Virginia Transmission Company, Inc. 
Allegheny Electric Cooperative, Inc. 
American Transmission Systems, Incorporated 
Appalachian Power Company 
Atlantic City Electric Company 
Baltimore Gas and Electric Company 
Commonwealth Edison Company 
Commonwealth Edison Company of Indiana, Inc. 
Dayton Power and Light Company 
Delmarva Power & Light Company 
Duke Energy Kentucky, Inc. 
Duke Energy Ohio, Inc. 
Duquesne Light Company 
Essential Power Rock Springs, LLC 
Hudson Transmission Partners, LLC 
Indiana Michigan Power Company 
Jersey Central Power & Light Company 
Kentucky Power Company 
Keystone Appalachian Transmission Company 
Kingsport Power Company 
Linden VFT, LLC 
Mid-Atlantic Interstate Transmission, LLC 
Monongahela Power Company 
Neptune Regional Transmission System, LLC 
NextEra Energy Transmission MidAtlantic Indiana, Inc. 
Ohio Power Company 
Ohio Valley Electric Corporation 
Old Dominion Electric Cooperative 
PECO Energy Company 
PPL Electric Utilities Corporation 
The Potomac Edison Company 
Potomac Electric Power Company 
Public Service Electric and Gas Company 
Rockland Electric Company 
Docket No. EL26-67-000

Docket No. EL26-67-000  
 
- 2 - 
 
 
Silver Run Electric, LLC 
Trans-Allegheny Interstate Line Company 
Transource West Virginia, LLC 
UGI Utilities, Inc. 
Virginia Electric and Power Company 
Wabash Valley Power Association, Inc. 
Wheeling Power Company 
 
(Issued June 18, 2026) 
 
SWETT, Chairman, concurring: 
 
 
Today, we take historic action to push our country’s electric markets and economy 
into the future—a future of fair cost allocation, unprecedented transparency for the 
American ratepayer, respect for states’ rights, efficient markets and speed to power.  Last 
October, Secretary Wright articulated the monumental, generational and “urgent” 
challenge FERC must solve for our country when he directed us to develop “reforms to 
ensure the timely and orderly interconnection of large loads to the transmission system.”1  
I strongly agree.  And now, through this suite of six orders, we deliver.     
 
Simply put, the show cause orders the Commission issues today to each of the six 
electric markets subject to its jurisdiction find that the status quo across much of the 
country is not good enough.2  Nowhere close.  The record prompted by the Secretary’s 
ANOPR leaves no doubt that most of the markets (and their existing rules) are inherently 
slow and prohibitive of the dexterity necessary to adapt to and power societal evolution—
whether brought about by technological innovation or sustaining the great industrial 
economy that anchors America.     
 
I wholeheartedly, fully concur with these orders, which we carefully crafted to 
execute upon the problems the Secretary identified in a manner that is quick, efficient, 
 
1 Advance notice of proposed rulemaking (ANOPR) Interconnection of Large 
Loads to the Interstate Transmission System, Advance Notice of Proposed Rulemaking 
(Oct. 23, 2025) (ANOPR); see Letter from Chris Wright, Sec’y, U.S. Dep’t of Energy 
(Oct. 23, 2025) (Secretary’s Letter). 
2 Cal. Indep. Sys. Operator Corp., 195 FERC ¶ 61,214 (2026) (CAISO); ISO New 
Eng. Inc., 195 FERC ¶ 61,215 (2026) (ISO-NE); Midcontinent Indep. Sys. Operator, Inc., 
195 FERC ¶ 61,212 (2026) (MISO); N.Y. Indep. Sys. Operator, Inc., 195 FERC ¶ 61,216 
(2026) (NYISO); PJM Interconnection, L.L.C., 195 FERC ¶ 61,211 (2026) (PJM); Sw. 
Power Pool, Inc., 195 FERC ¶ 61,213 (2026) (SPP) (collectively, Orders to Show 
Cause).

Docket No. EL26-67-000  
 
- 3 - 
 
 
and legally durable.  I write separately to highlight certain considerations underlying the 
Commission’s procedural approach to delivering on the ANOPR and to today’s orders.   
 
Based on my analysis of the extensive record and numerous ongoing substantive 
stakeholder interactions, I have determined that the most productive way to “build upon 
the[] principles”3 in the ANOPR and “work expeditiously”4 towards a solution is to issue 
individualized orders to show cause to each market.5  That is so for two main reasons. 
 
First, the record the Commission collected in response to the challenges identified 
in the ANOPR and subsequent resulting developments indicate that an approach that 
honors the ANOPR principles but accounts for widening regional variation may now be 
more efficient than a one-size-fits-all rule.6  The world has changed a great deal since last 
October.  The ANOPR itself, including the articulated principles, appears to have shifted 
the playing field and prompted great progress across several electric markets.  This 
change (and the Commission’s alignment with the Secretary) is well illustrated by a 
number of landmark orders approving several market new constructs that we issued since 
October, which together operationalize the Secretary’s principles and laid groundwork 
for meaningful reform and today’s actions.7  While working to develop those orders, the 
 
3 Secretary’s Letter at 2. 
4 Id. 
5 See SEC v. Chenery Corp., 332 U.S. 194, 202-03 (1947) (“[A]n administrative 
agency must be equipped to act either by general rule or individual order.  To insist upon 
one form of action to the exclusion of the other is to exalt form over necessity. . . . [T]he 
choice made between proceeding by general rule or by individual, ad hoc litigation is one 
that lies primarily in the informed discretion of the administrative agency.”); Wis. Gas 
Co. v. FERC, 770 F.2d 1144, 1166 (D.C. Cir. 1985) (“It is a well-settled principle of 
administrative law that the decision whether to proceed by rulemaking or adjudication 
lies within the broad discretion of the agency.”). 
6 “[T]he Commission may rely on ‘generic’ or ‘general’ findings of a systemic 
problem to support imposition of an industry-wide solution.”  Interstate Nat. Gas Ass’n 
of Am. v. FERC, 285 F.3d 18, 37 (D.C. Cir. 2002) (internal citations omitted).  However, 
the Commission “has long allowed different regional transmission organizations to 
follow different rules, in recognition of regional variations including potential differences 
in ‘geographic size and location.’”  Cent. Hudson Gas & Elec. Corp. v. FERC, 138 F.4th 
531, 539 (D.C. Cir. 2025) (internal citations omitted). 
7 See id. P 2 & nn.6-11.

Docket No. EL26-67-000  
 
- 4 - 
 
 
Commission has simultaneously devoted significant attention to evaluating the various 
procedural paths through which we might comprehensively deliver. 
 
Individual show cause proceedings will allow the Commission to ensure that 
solutions to the problems the Secretary identified are tailored to the specific, varied 
circumstances and market constructs of each region.  Indeed, a careful review of today’s 
six orders reveals the many ways in which those orders are customized for each market’s 
unique circumstances and progress (or lack thereof) towards serving large load.  To name 
just a few examples, the orders recognize ongoing stakeholder processes in various 
regions and are adapted to existing tariff provisions concerning large and co-located 
loads; account for regional variances in allocating rights and responsibilities among 
RTOs/ISOs and the transmission owners; leave room for each market to tailor operational 
requirements for large loads that are particular to their region; and otherwise account for 
incumbent regional differences on topics such as cost allocation and cost transparency, 
study processes, and network upgrade procedures. 
 
Proceeding via show cause proceedings will also allow the markets (and their 
respective transmission owners) to explain, in the first instance, how to address the 
Commission’s concerns.  These entities have the deepest understanding of their 
respective regions and are best positioned to implement solutions we identified, in the 
most expeditious manner.  The Commission will promptly evaluate their responses to 
today’s orders, and, with input from stakeholders, swiftly establish appropriate reforms.   
 
Second, proceeding via individual show cause orders will allow the Commission 
to act more quickly than through traditional rulemaking.  Notice-and-comment 
rulemaking may not capitalize upon individual market progress prompted since October 
and would be unduly time-consuming,8 as it also inevitably would require the additional 
steps of accommodating the regional variations of the approach we take today.  
Rulemaking efforts can be particularly inefficient when, as here, they risk incubating 
uncertainty after progress has begun, and diverting scarce stakeholder resources away 
from other endeavors, such as the development of market-specific reforms submitted to 
the Commission under section 205 of the Federal Power Act (FPA).  (To be clear, we 
very much encourage 205 submissions encapsulating the principles we articulate in the 
206s, and with all due deliberate haste.) 
 
Furthermore, rulemaking requires a lengthy series of steps before the proposed 
reforms would actually take effect—e.g., a NOPR, then a final rule, then potential orders 
on rehearing, and then a “compliance” process in which affected parties make filings (or, 
more likely, multiple rounds of filings) explaining how they intend to implement the rule. 
 
8 See, e.g., Comments of Talen Energy Corporation, Docket No. RM26-4, at 5-6 
(filed Nov. 21, 2025).

Docket No. EL26-67-000  
 
- 5 - 
 
 
By their nature, these procedures take time.  For example, the compliance process for the 
Commission’s Order No. 20239 (which matured out of an ANOPR issued in July 2021 
and a NOPR issued in June 2022) still is not fully complete as of June 2026.  The 
compliance process for Order No. 222210 (NOPR issued in November 2016) could be 
considered completed in May 2026; however, even with that timing, not all of the 
RTOs/ISOs have yet fully implemented their Commission-accepted market rules.  I 
provide these examples not to suggest that the completion of a rulemaking process on the 
interconnection of large loads would take this long,11 but rather to make clear the scope 
of the years-long delays in implementation that might be expected if the Commission 
elected to proceed via a NOPR.  By contrast, we expect that individual show cause 
proceedings for each of the RTO/ISOs will enable the Commission to spearhead lasting 
reform much more expeditiously.   
 
The six markets together cover nearly two-thirds of load subject to Commission-
jurisdictional rates, and therefore focusing initially on those regions is a prudent first step.  
But I am under no illusion that the challenges discussed in today’s orders are somehow 
unique to the RTO/ISO regions.  Our actions today do not foreclose the possibility of a 
future rulemaking, and nor do they prevent us from acting on filings made under sections 
205 and 206 of the FPA.  I encourage transmission providers and other stakeholders 
outside RTO/ISO regions to make individual filings to address the issues we discuss 
today. 
 
FERC is no longer the sleepy, responsive agency of the past—our country cannot 
afford for it to be.  This is a time for the best thinkers we have to collaborate on solving 
our biggest problems, and thus it is my great honor to deliver a solution that honors the 
Secretary’s goals.   
 
9 Improvements to Generator Interconnection Procs. & Agreements, Order No. 
2023, 184 FERC ¶ 61,054, order on reh’g, 185 FERC ¶ 61,063 (2023), order on reh’g, 
Order No. 2023-A, 186 FERC ¶ 61,199, errata notice, 188 FERC ¶ 61,134 (2024). 
10 Participation of Distributed Energy Res. Aggregations in Mkts. Operated by 
Reg’l Transmission Orgs. & Indep. Sys. Operators, Order No. 2222, 172 FERC ¶ 61,247 
(2020), order on reh’g, Order No. 2222-A, 174 FERC ¶ 61,197, order on reh’g, Order 
No. 2222-B, 175 FERC ¶ 61,227 (2021). 
11 I do not mean to suggest that the public utilities subject to compliance under 
these rulemakings—or the Commission itself—have been derelict.  The time-consuming 
nature of the compliance process is a natural consequence of complex, nuanced efforts 
toward tariff reform.  As Chairman, I will continue to evaluate Commission directives to 
ensure that obligations on regulated entities are not unduly burdensome and to make 
certain that Commission action during the compliance process is as timely as possible.

Docket No. EL26-67-000  
 
- 6 - 
 
 
For these reasons, I respectfully concur.   
______________________ 
Laura V. Swett 
Chairman

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
 
PJM Interconnection, L.L.C.  
AEP Appalachian Transmission Company, Inc. 
AEP Indiana Michigan Transmission Company, Inc. 
AEP Kentucky Transmission Company, Inc. 
AEP Ohio Transmission Company, Inc. 
AEP West Virginia Transmission Company, Inc. 
Allegheny Electric Cooperative, Inc. 
American Transmission Systems, Incorporated 
Appalachian Power Company 
Atlantic City Electric Company 
Baltimore Gas and Electric Company 
Commonwealth Edison Company 
Commonwealth Edison Company of Indiana, Inc. 
Dayton Power and Light Company 
Delmarva Power & Light Company 
Duke Energy Kentucky, Inc. 
Duke Energy Ohio, Inc. 
Duquesne Light Company 
Essential Power Rock Springs, LLC 
Hudson Transmission Partners, LLC 
Indiana Michigan Power Company 
Jersey Central Power & Light Company 
Kentucky Power Company 
Keystone Appalachian Transmission Company 
Kingsport Power Company 
Linden VFT, LLC 
Mid-Atlantic Interstate Transmission, LLC 
Monongahela Power Company 
Neptune Regional Transmission System, LLC 
NextEra Energy Transmission MidAtlantic Indiana, Inc. 
Ohio Power Company 
Ohio Valley Electric Corporation 
Old Dominion Electric Cooperative 
PECO Energy Company 
PPL Electric Utilities Corporation 
The Potomac Edison Company 
Potomac Electric Power Company 
Public Service Electric and Gas Company 
Rockland Electric Company 
Docket No. EL26-67-000

Docket No. EL26-67-000  
- 2 - 
 
 
Silver Run Electric, LLC 
Trans-Allegheny Interstate Line Company 
Transource West Virginia, LLC 
UGI Utilities, Inc. 
Virginia Electric and Power Company 
Wabash Valley Power Association, Inc. 
Wheeling Power Company 
 
(Issued June 18, 2026) 
 
ROSNER, Commissioner, concurring:  
 
 
The electric industry is in the midst of changes not seen in a generation.  
Compared to more traditional load growth, the large loads seeking to connect to the grid 
today are larger, sometimes by orders of magnitude, and more concentrated.  They also 
exhibit different operational characteristics, such as the ability to quickly change their 
energy consumption, sometimes in seconds.  Often, these large loads seek to connect to 
the grid as quickly as possible.  And because of these dynamics, large loads are rapidly 
driving the need for new transmission infrastructure and energy supply.  This creates new 
challenges that, if unaddressed, could jeopardize the reliability and affordability of the 
grid on which we all depend. 
 
Today, we are taking an important step toward addressing these challenges.  We 
are opening a dialogue with each of the six RTO/ISOs on a series of reforms that are 
tailored to address the unique reliability and affordability challenges posed by large load 
growth and the infrastructure buildout needed to serve dramatically growing demand.  
Informed by the record developed in response to the Secretary of Energy’s October 2025 
ANOPR,1 and by innovative proposals that stakeholders have filed with the Commission 
under FPA section 205, today’s orders are aimed at ensuring that the grid remains reliable 
and affordable for all customers, especially residential customers.  It is also crucial that 
we unlock the immense economic opportunity that once-in-a-generation growth 
represents.  While each order’s specific focus varies according to the progress that each 
RTO/ISO has made, our actions today fit broadly into four key pillars that, taken 
together, provide a foundation for durable reform.  Today, we are: (1) Protecting 
Consumers, (2) Safeguarding Reliability, (3) Enhancing Transparency, and (4) Fostering 
Innovation (see Figure 1).  I write separately to explain how. 
 
1 U.S. Dep’t of Energy, Secretary of Energy Chris Wright, Direction that the 
Commission Initiate Rulemaking Procedures and Proposal Regarding the Interconnection 
of Large Loads Pursuant to the Secretary’s Authority Under Section 403 of the 
Department of Energy Organization Act (Oct. 23, 2025).

Docket No. EL26-67-000  
- 3 - 
 
 
***** 
 
Protecting Consumers:  Today’s orders include key protections that promote 
affordability.  First, today’s orders require “Cost Recovery Agreements”, which are 
designed to ensure that large loads pay their fair share of the costs incurred to serve them, 
regardless of whether the large load comes online as planned.  Thus, if new infrastructure 
is built to accommodate a data center, and that data center doesn’t show up, residential 
customers are not left on the hook to pay the costs.  Cost Recovery Agreements prevent 
those costs from being shifted to residential customers.  Depending on how they are 
structured, Cost Recovery Agreements can also address the potentially uneven pacing of 
new infrastructure costs, where grid upgrade costs may hit customer bills before the large 
load is fully online and energized.  Data centers have committed to paying their own 
way.2  Today, with “Cost Recovery Agreements,” we are taking steps to ensure that those 
commitments are honored.  I note, however, that the door remains open to other creative, 
regionally-specific ideas to protect consumers.  If there are other ways to accomplish that 
goal, I welcome those proposals. 
 
Another win for consumers is requiring RTO/ISOs to consider grid enhancing 
technologies (GETs), including dynamic line ratings, when adding new large loads to the 
grid.  GETs are technologies that squeeze more juice out of the existing grid, reducing the 
need for expensive upgrades and speeding up the time connect.  Ensuring that RTO/ISOs 
consider GETs in the planning process—and if GETs are not used, explain why—not 
only helps new large loads get connected more quickly, but is also a commonsense step 
towards saving all consumers money.  Put differently, today’s orders will help us 
understand if we are leaving efficiencies on the table, an outcome we cannot afford. 
 
Safeguarding Reliability:  Today’s orders safeguard reliability.  They help ensure 
that RTO/ISOs use study procedures and operational requirements that reflect large 
loads’ unique characteristics and the reliability impacts of connecting them to the grid.  
Those novel characteristics and reliability impacts are well-documented, and it is not 
clear if existing study procedures or operational requirements account for them.  Clear, 
comprehensive, and specifically tailored study procedures and operational requirements 
are needed, such as enhanced data reporting and telemetry to increase visibility into how 
these loads interact with the grid, and today’s orders represent progress towards this goal. 
 
Finally, although not part of today’s orders, I want to highlight NERC’s ongoing 
efforts to establish registration criteria for large computational loads and to develop 
reliability standards.3  NERC’s goal is to finish the first phase of this critical work this 
 
2 See Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026). 
3 NERC, Large Loads Action Plan Q1 2026 Update (Apr. 2026), 
https://www.nerc.com/globalassets/initiatives/large-loads-action-plan/llap-quarterly-

Docket No. EL26-67-000  
- 4 - 
 
 
year.  It is essential that NERC meet this deadline.  I encourage all stakeholders to 
participate in NERC’s process. 
 
Enhancing Transparency:  Today’s orders provide regulators—the Commission 
and, critically, our state partners—and customers with data on how connecting large 
loads to the grid affects bills.  Today’s orders embody a commonsense approach: if a  
Network Upgrade is built to connect a large load to the grid, consumers should know who 
that upgrade was built for and what it cost. 
 
Transparency is important because “who pays?” has been and continues to be a 
fraught and contentious question for large load interconnection.  Stakeholders, including 
state regulators and the ratepayers that they represent, must know the costs, for whom 
they are being incurred, and how they are being allocated, to know that everyone is 
paying their fair share.  Today’s orders ensure that this information is public, accessible, 
and clear.  State regulators in more than half of the country have enacted large load 
tariffs.4  Our action today helps them as they continue their critically important work. 
 
The Commission’s action today also addresses speculative load interconnection 
requests, which clog up load interconnection queues, divert resources, and distort 
forecasts.  Under current rules, data centers can (and are incentivized to) “shop around” 
their prospective projects with different utilities to identify the fastest and cheapest 
location to connect.  This wastes time and resources studying projects that are not real.  
Worse yet, it can inflate expected load growth by modeling projects that do not 
materialize, leading to double counting, inaccurate market signals, and unnecessarily high 
prices for consumers.  Today, we target speculative projects by establishing escalating 
readiness requirements for distinct phases of the study process to deter duplicative or 
speculative requests for transmission service.  I strongly encourage RTO/ISOs to pursue 
other improvements to load forecasts, such as using objective screening criteria like 
physical site control, to ensure that the data used to plan the grid is as accurate as 
possible.5   
 
update-q1-2026.pdf. 
4 See, e.g., National Association of Regulatory Utility Commissioners 
Supplemental Comments at 2-6; Edison Electric Institute Supplemental Comments at 
App. 9-13. 
5 See Comm’r David Rosner, Letter to the RTOs/ISOs on Large Load Forecasting 
(Sept. 18, 2025), https://www.ferc.gov/news-events/news/chairman-rosners-letter-
rtosisos-large-load-forecasting.

Docket No. EL26-67-000  
- 5 - 
 
 
 
Fostering Innovation:  As I have said, to meet the moment, “a business-as-usual 
approach . . . will not suffice.”6  Building new infrastructure is difficult and costly, which 
delays efforts to connect large loads to the grid quickly, reliably, and cost effectively.  
This is doubly true when generation and load are planned and studied separately.  
Today’s orders push beyond this status quo. 
 
First, today’s orders promote flexible transmission services—that is, non-firm 
service to a co-located load that is willing and able to limit withdrawals from the grid—in 
every RTO/ISO (see Figure 2).  As we explained when we first created these 
transmission services in PJM for co-located loads, customers willing to embrace 
flexibility can reduce the need for Network Upgrades and generating capacity to serve a 
co-located load, which speeds up connecting to the grid and reduces costs for the co-
located load as well as other retail customers. 
 
Second, today’s orders recognize that extending these same transmission services 
to large loads that are not co-located but that may also be willing to limit their 
withdrawals from the grid can unlock even more efficiency.  Just as for co-located loads, 
legalizing flexible transmission service options for more large load customers can speed 
interconnection, avoid constructing unnecessary transmission upgrades, reduce strain on 
the grid, and make power bills cheaper for everyone. 
 
Finally, today’s orders embrace yet another innovation.  Load and generation need 
not be co-located to reduce the number of Network Upgrades; in other words, literal co-
location is not the only way to facilitate faster, more efficient, and more cost-effective 
connections to the grid.  Rather, where a large load and an associated generator are 
electrically proximate (i.e., close together) and studied together, the reliability impacts on 
the grid may be more limited than if the load and generator are studied separately.  Just 
like with co-location, more limited impacts on the grid mean, all else equal, fewer 
Network Upgrades, which makes connecting to the grid faster, more efficient, and 
cheaper for both the large load and the associated generator.  That last point is key.  To 
add new supply to the grid, we must create incentives for “Bring Your Own New 
Generation.”  Today’s orders make BYONG faster and more efficient.  
 
SPP has been a leader in showing how to push beyond the status quo.  With its 
innovative HILLGA proposal, approved by the Commission in January,7 SPP leveraged 
the opportunity for speed and efficiency by studying load and generation together, and by 
creating a limited, expedited interconnection service to connect faster.  By matching the 
generator’s output to the electrically proximate large load’s demand, the impacts to the 
 
6 PJM Interconnection, L.L.C., 193 FERC ¶ 61,217 (2026), (Rosner, Comm’r, 
concurring) at P 3. 
7 See Sw. Power Pool, Inc., 194 FERC ¶ 61,031 (2026).

Docket No. EL26-67-000  
- 6 - 
 
 
grid are less than they otherwise would be, minimizing the need for time-consuming and 
costly Network Upgrades needed to connect.  HILLGA is one solution that works for 
SPP, but today’s orders direct other regions to follow SPP’s lead in ways that work for 
them.  Today’s orders add a key tool by ensuring that all RTO/ISOs can study load and 
generation together.  
***** 
 
The Commission’s action today is an important step forward, but the Commission 
cannot accomplish this work alone.  States are essential partners in this work.  The 
Commission’s actions here respect the long-standing jurisdictional line between federal 
and state authority provided by Congress and repeatedly affirmed by the Supreme Court.  
States retain exclusive jurisdiction to allocate the costs of FERC-jurisdictional 
transmission charges among their retail ratepayers, including co-located loads.  States 
also hold the keys to energy infrastructure permits, so we rely on their decisions to ensure 
that needed transmission and generation get built.  At a time when some large loads are 
retail customers that can consume as much energy as a small city, it is imperative that we 
work within our respective jurisdictions, but that we collaborate. I look forward to 
continued collaboration. 
 
Today’s orders begin an important dialogue with RTO/ISOs.  As a potential next 
step, today’s orders invite RTO/ISOs to respond by submitting proposals under FPA 
section 205.  I cannot encourage this enough.  I also encourage public utilities outside of 
RTO/ISOs across the country to do the same.  The electric industry is rapidly evolving 
with regions experiencing and addressing these challenges in different ways.  Many of 
the examples on which the actions in today’s orders are based on stakeholders thinking 
creatively to develop solutions, and I welcome other new, innovative, and regionally 
tailored proposals that build on the four key pillars set forth today:  (1) Protecting 
Consumers, (2) Safeguarding Reliability, (3) Enhancing Transparency, and (4) Fostering 
Innovation.  Only by working together can we rise to the occasion and meet this once-in-
a-generation moment to deliver the reliable and affordable energy on which we all 
depend.  It will not be easy, but I remain optimistic and look forward to the path ahead. 
For these reasons, I respectfully concur. 
 
 
 
________________________ 
David Rosner 
Commissioner

Figure 1

Figure 2

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
 
PJM Interconnection, L.L.C.  
AEP Appalachian Transmission Company, Inc. 
AEP Indiana Michigan Transmission Company, Inc. 
AEP Kentucky Transmission Company, Inc. 
AEP Ohio Transmission Company, Inc. 
AEP West Virginia Transmission Company, Inc. 
Allegheny Electric Cooperative, Inc. 
American Transmission Systems, Incorporated 
Appalachian Power Company 
Atlantic City Electric Company 
Baltimore Gas and Electric Company 
Commonwealth Edison Company 
Commonwealth Edison Company of Indiana, Inc. 
Dayton Power and Light Company 
Delmarva Power & Light Company 
Duke Energy Kentucky, Inc. 
Duke Energy Ohio, Inc. 
Duquesne Light Company 
Essential Power Rock Springs, LLC 
Hudson Transmission Partners, LLC 
Indiana Michigan Power Company 
Jersey Central Power & Light Company 
Kentucky Power Company 
Keystone Appalachian Transmission Company 
Kingsport Power Company 
Linden VFT, LLC 
Mid-Atlantic Interstate Transmission, LLC 
Monongahela Power Company 
Neptune Regional Transmission System, LLC 
NextEra Energy Transmission MidAtlantic Indiana, Inc. 
Ohio Power Company 
Ohio Valley Electric Corporation 
Old Dominion Electric Cooperative 
PECO Energy Company 
PPL Electric Utilities Corporation 
The Potomac Edison Company 
Potomac Electric Power Company 
Public Service Electric and Gas Company 
Rockland Electric Company 
Docket No. EL26-67-000

Docket No. EL26-67-000 
- 2 - 
 
 
Silver Run Electric, LLC 
Trans-Allegheny Interstate Line Company 
Transource West Virginia, LLC 
UGI Utilities, Inc. 
Virginia Electric and Power Company 
Wabash Valley Power Association, Inc. 
Wheeling Power Company 
 
(Issued June 18, 2026) 
 
SEE, Commissioner, concurring:  
 
 
Growing electricity demand underscores America’s economic strength and the 
opportunities that come with it.  And with new opportunities come new challenges.  The 
pace and scale of emerging large loads create new circumstances that require us to adapt 
in how we build and manage the grid.  Large and flexible loads can materially change 
system operations, for instance, as well as near-term planning needs, upgrade 
requirements, and how we allocate costs.  Most existing systems were not designed to 
accommodate those changes—especially not at the pace needed to support AI growth and 
advanced manufacturing that are central to America’s economic competitiveness.  As a 
result, uncertainty over the operative rules and delays in interconnecting large loads can 
undermine reliability and investment and add unacceptable and avoidable costs.  
 
Today, the Commission takes strong action within our jurisdictional sweep to 
address these and other challenges that large load growth poses to the interstate 
transmission system.  Today’s orders support both just and reasonable rates and speed to 
(reliable) power.  I’m deeply grateful for the many commenters who shared their insight 
and ideas in this action.  They let us build a record that highlights the need for clearer 
processes, better information, and faster analysis while our country moves new large load 
additions online.  As we press forward in these dockets, I will be looking to continue 
building on the momentum already underway across the country to craft more practical, 
region-specific solutions that support timely action while protecting consumers.  Our 
continued ability to deliver reliable and affordable electricity requires nothing less.   
 
Today’s orders speak for themselves.  I write separately to briefly highlight two 
principles baked throughout them and that I believe must remain central as the 
Commission evaluates further steps.   
 
First, these issues extend beyond the Commission.  Creating efficient, predictable 
large load interconnection processes is a joint and overlapping task for us, other federal 
agencies, the States, and the RTOs/ISOs and utilities.  My animating principle here is that 
we must use FERC’s statutory authority to bring clarity to the parts of this national issue 
we own, and to complement and aid others as they tackle theirs.  The very procedure the

Docket No. EL26-67-000 
- 3 - 
 
 
Commission deploys today reflects that goal: Recognizing the value in region-specific 
approaches, we are directing individual action in each of the RTO/ISO regions and 
encouraging—strongly—proposals under section 205 of the Federal Power Act from 
transmission providers or other entities that are molded to their unique system needs. 
 
Most critically, exercising our authority fully without hamstringing our regulatory 
and industry partners means respecting the States.  States make many of the key decisions 
that affect how we manage large loads.  States bring indispensable expertise over local 
conditions, siting needs, retail structures, and the resource decisions within their borders.  
And they have been hard at work pursuing the retail implications and other State-specific 
concerns that large load interconnection presents.1  All this effort flows from the States’ 
statutorily preserved role in regulating the power system.  Today’s order understands that 
limit—our power “extend[s] only to those matters which are not subject to regulation by 
the States.”2  It also embraces the value in a statutory lens that views large load issues as 
an area of shared federal-State responsibility.  As we require clear study and operational 
parameters for large load interconnection, we should remember that the nation’s energy 
landscape is not monolithic.  State and regional diversity is a strength, and today’s orders 
know that the best solutions reflect differing system characteristics.  Our action today is 
designed to support further State efforts in this urgent and fast-moving space, not 
override them. 
 
Second, affordability must be at the forefront as we protect consumers from 
unnecessary costs in a time of rising demand.  True, the Commission lacks authority over 
all the factors that drive electricity costs at the retail level.  Today’s orders recognize that.  
In response, the orders strive to aid the States in their front-line affordability duties by 
getting into their hands all relevant information about Commission-jurisdictional costs.  
As these matters move forward, I am particularly interested in continued feedback from 
the States on what information they most need to assess cost implications as new loads 
come online.  Are the cost transparency measures we identify today sufficient, or are 
additional or more granular data needed for States to appropriately suballocate 
transmission costs among retail customers?  Tools like alternative cost allocation 
structures, greater clarity in transmission service agreements, accounting for States’ 
large-load-specific tariffs, and direct assignment in appropriate cases may help States 
ensure that retail consumers do not bear costs incommensurate with the benefits they 
receive. 
 
1 See EEI Supplemental Comments at Appendix 9 – 13 (listing pending and 
approved State large load tariffs).  
2 16 U.S.C. § 824(a).

Docket No. EL26-67-000 
- 4 - 
 
 
 
Moving to areas where the Commission has a more direct role in ensuring cost 
responsibility, we need to pull all the levers we have to keep rates fair and transparent.  
Today we reaffirm our responsibility to assign jurisdictional costs to the customers who 
drive or benefit from grid upgrades, not shift them onto families and small businesses.  
For instance, today’s orders seek to reduce large-load driven network upgrade costs 
through alternative transmission technologies, or ATTs (also commonly called Grid 
Enhancing Technologies).  In determining how best to meet the needs of this historic 
large load growth, technologies that can improve system capability faster than traditional 
upgrades and at lower costs deserve a hard look.  ATTs may not be the best tool in every 
circumstance, but where they are they can support timely interconnections and avoid 
potentially tens or hundreds of millions of dollars in unnecessary network upgrade costs 
that would otherwise flow into transmission customers’ bills.    
 
So our approach today supports continuing the Commission’s policy to roll most 
network upgrade costs—including those in the large load space—into the embedded-cost 
rate most transmission customers pay.  But it includes an asterisk that this policy works 
for ratepayers only so long as we remain committed to pursuing technological 
innovations that keep those costs at a responsible and accountable level.  Today’s order 
thus calls for transmission providers to sufficiently evaluate ATTs to assess if and how 
they can meet large loads’ interconnection needs.  The answer may be yes or no in a 
given case.  But if the transmission provider opts for traditional network upgrades, they 
must demonstrate why ATTs are not feasible or would not result in lower costs or a faster 
timeline for the large load interconnection customer.  In short, the goal is to respect 
transmission providers’ engineering judgments while protecting against upgrade costs 
when ATTs could solve transmission needs faster and with a lower bill.    
 
I am also sensitive to novel questions about cost shifting that interconnecting large 
load may present.  Today’s findings on cost recovery agreements between transmission 
owners and Eligible Customers are an important step in mitigating the risks of stranded 
assets if large loads prove speculative.  We are also reducing unnecessary redundancy by 
allowing an Eligible Customer to meet its financial security requirements by relying on 
credit support or other financial security a large load customer may have posted under a 
retail agreement.  As we gain more experience studying transmission service requests on 
behalf of large loads, it may become appropriate to further streamline financial security 
arrangements.  Perhaps, for instance, cost -recovery agreements between a transmission 
owner and a large load customer itself could satisfy an Eligible Customer’s financial 
security requirements.  As we move forward, I’ll be looking to ensure cost-recovery 
agreements contain fair and transparent measures to ensure the right costs get on the right 
bills.  (Relatedly, the discussion about the full nature of transmission-related charges in 
our concurrent PJM Order on Rehearing, Clarification, Compliance, and Paper Hearing 3 
 
3 PJM Interconnection, L.L.C., 195 FERC ¶ 61,209 (2026).

Docket No. EL26-67-000 
- 5 - 
 
 
may prove relevant here: Real-world experience with new transmission services for co-
located load may clarify if future action becomes needed to address potential cost shifts 
as Eligible Customers take new transmission services on behalf of large loads.4)   
 
More generally, as we gain more experience as an industry and a country in 
getting large loads connected to the grid, I welcome bold proposals to keep affordability 
central.  Large load growth presents a real opportunity to build a stronger, more capable, 
and more reliable electric system that can benefit all ratepayers.  Meeting that opportunity 
at the pace we need and at an acceptable cost requires innovative thinking and fast action.  
I commend the States in their continued work in these areas.  I urge the RTOs and ISOs 
to continue their good work as they respond quickly to today’s orders.  I also remain 
committed to moving forward within the Commission’s statutory zone with clarity and 
decisiveness.  I am proud to support the Commission’s important steps today.  And we all 
have more work ahead.    
For these reasons, I respectfully concur.  
 
 
 
______________________________ 
Lindsay S. See 
Commissioner 
 
4 See id. P 456.

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
 
PJM Interconnection, L.L.C.  
AEP Appalachian Transmission Company, Inc. 
AEP Indiana Michigan Transmission Company, Inc. 
AEP Kentucky Transmission Company, Inc. 
AEP Ohio Transmission Company, Inc. 
AEP West Virginia Transmission Company, Inc. 
Allegheny Electric Cooperative, Inc. 
American Transmission Systems, Incorporated 
Appalachian Power Company 
Atlantic City Electric Company 
Baltimore Gas and Electric Company 
Commonwealth Edison Company 
Commonwealth Edison Company of Indiana, Inc. 
Dayton Power and Light Company 
Delmarva Power & Light Company 
Duke Energy Kentucky, Inc. 
Duke Energy Ohio, Inc. 
Duquesne Light Company 
Essential Power Rock Springs, LLC 
Hudson Transmission Partners, LLC 
Indiana Michigan Power Company 
Jersey Central Power & Light Company 
Kentucky Power Company 
Keystone Appalachian Transmission Company 
Kingsport Power Company 
Linden VFT, LLC 
Mid-Atlantic Interstate Transmission, LLC 
Monongahela Power Company 
Neptune Regional Transmission System, LLC 
NextEra Energy Transmission MidAtlantic Indiana, Inc. 
Ohio Power Company 
Ohio Valley Electric Corporation 
Old Dominion Electric Cooperative 
PECO Energy Company 
PPL Electric Utilities Corporation 
The Potomac Edison Company 
Potomac Electric Power Company 
Public Service Electric and Gas Company 
Rockland Electric Company 
Docket Nos. EL26-67-000

Docket No. EL26-67-000 
- 2 - 
 
 
Silver Run Electric, LLC 
Trans-Allegheny Interstate Line Company 
Transource West Virginia, LLC 
UGI Utilities, Inc. 
Virginia Electric and Power Company 
Wabash Valley Power Association, Inc. 
Wheeling Power Company 
 
(Issued June 18, 2026) 
 
CHANG, Commissioner, concurring: 
 
 
In a series of orders today, the Commission initiates separate proceedings under 
Federal Power Act (FPA) section 206 to explore the impact of the increasing growth of 
large loads in Regional Transmission Organization (RTO) and Independent System 
Operator (ISO) regions.  The preliminary findings in these orders, and the associated 
proposed reforms to RTO/ISO and transmission owner tariffs, could significantly change 
how loads procure, use, and pay for transmission service, with ramifications for 
RTO/ISO operations, planning, and markets.  I write separately to emphasize the 
importance of building actionable records in these proceedings, particularly with respect 
to our consideration of customer protection, transmission service, and alternative 
transmission technology reforms. 
I. 
Overview of Today’s Orders 
 
In each of today’s orders to show cause, the Commission identifies a series of 
issues raised by the ongoing growth of large loads, directs briefing on whether existing 
tariffs remain just and reasonable in light of those developments, and describes possible 
solutions to those issues if the Commission ultimately concludes that the relevant tariffs 
are unjust and unreasonable.  Each order is directed to a specific RTO/ISO and relevant 
transmission owners that play a role in interconnecting large loads to the Commission-
jurisdictional transmission system.  The Commission does not pursue the broad assertion 
of jurisdictional authority contemplated in the Advanced Notice of Proposed 
Rulemaking, which I hope assuages concerns raised by our state colleagues that the 
Commission ought not encroach upon matters properly left to their jurisdiction.1   
 
1 I will do my part to ensure that the Commission continues to be a collaborative 
partner to our state counterparts, other federal agencies, and the industry as we seek to 
address this wide-ranging challenge.  Accordingly, I welcome feedback from our state 
colleagues and others if they believe the Commission’s preliminary findings raise 
jurisdictional concerns.

Docket No. EL26-67-000 
- 3 - 
 
 
 
Broadly summarized, each order seeks regional input on a specific list of issues: 
(1) the clarity and consistency of existing rules governing how each RTO/ISO and its 
relevant transmission owners analyze the impact of providing transmission service to 
Eligible Customers on behalf of large loads; (2) whether each RTO/ISO tariff requires 
reforms to mitigate the risk of cost shifting among wholesale transmission customers; (3) 
whether each RTO/ISO tariff (other than PJM) requires additional clarity regarding the 
provisions addressing co-located generation and load arrangements; (4) the potential 
extension of new firm and non-firm transmission services to co-located load, load with 
behind the meter generation, and other flexible loads; and (5) the need for reforms, 
modeled on Southwest Power Pool, Inc.’s High Impact Large Load Generation 
Assessment concept, to facilitate a process through which a generator may temporarily 
serve a co-located or electrically proximate load until interconnection and transmission 
service is available.  The Commission also invites each region to submit FPA section 205 
filings that can address each issue identified in the orders, thereby resolving the 
Commission’s concerns.   
II. 
The Commission Needs Good Records to Ensure Reasoned Decision-Making   
 
I first want to emphasize that the Commission needs active participation from 
interested stakeholders to develop thorough records in each region.  The Commission 
cannot make reasoned decisions about whether reforms might be needed without an 
accurate understanding of the existing processes, which differ by region.  Because the 
Commission is acting via FPA section 206 rather than generically through a rulemaking, 
the issues addressed by these orders will be subject to ex parte restrictions across the 
RTOs/ISO regions, including with our state colleagues whose regulation can and will 
directly affect the individual transmission owners that need to comply with the orders 
issued today.  This will limit the Commission’s ability to engage in informal fact-finding 
and discussions with regional stakeholders, and thus, it is even more essential that the 
record in each region fully reflects the views of all interested parties.   
 
Second, I highlight three issues below that will be especially important to the 
success of this effort, and I hope that interested parties will take particular care in helping 
the Commission address those issues.  Importantly, I recognize that the record established 
in each RTO/ISO region will (and should) differ, which will allow the Commission to 
ensure any required changes to an RTO/ISO’s tariff are appropriately tailored to that 
region’s needs. 
III. 
The Commission Needs to Pursue Meaningful Customer Protection  
 
The FPA is fundamentally a customer protection statute,2 and the Commission has 
an obligation to ensure that the rates that wholesale and transmission customers pay are 
 
2 See, e.g., Mun. Light Bds. Of Reading and Wakefield v. FPC, 450 F.2d 1341,

Docket No. EL26-67-000 
- 4 - 
 
 
just and reasonable.  Rapid large load growth has strained planning and resource 
procurement processes around the country, as transmission owners, load serving entities, 
and generators accelerate the building of new infrastructure needed to serve these new 
loads.  As we develop the new infrastructure, many have raised concerns about whether 
these costs are being fairly assigned to new and existing customers, whose benefits must 
be commensurate with the costs they pay.  While individual states have been exploring or 
using various approaches to protect retail customers against unjustified cost shifts, the 
Commission to date has not initiated any proactive exploration of how to protect 
wholesale customers against unjustified cost shifts. I am laser-focused on this issue 
because we should not create unjustified costs for consumers in our efforts to connect and 
serve large loads.  
 
In today’s orders, the Commission launches an inquiry into whether existing 
RTO/ISO tariffs include adequate mechanisms to mitigate the risk of undue cost shifting 
among transmission customers.  To address this risk, the Commission preliminarily 
identifies a two-part solution: (1) that each RTO/ISO post public information about the 
amount of new large loads seeking to connect to the RTO’s/ISO’s transmission system, 
any Network Upgrades identified in the local transmission planning process to serve 
those loads, and the costs of those Network Upgrades; and (2) that each RTO/ISO adopt a 
pro forma cost recovery agreement to help ensure that Eligible Customers serving large 
loads bear the risk and are ultimately responsible for costs incurred to provide 
transmission service.  I strongly support this effort to provide additional transparency 
regarding jurisdictional transmission service requests and the costs associated with 
providing transmission service to the requesting parties, as the Commission cannot 
effectively execute its statutory responsibilities without sufficient understanding of the 
costs that feed into jurisdictional rates.   
 
Exploring how agreements between transmission owners and Eligible Customers 
can protect wholesale customers against cost shifts is important.  However, as I have 
previously explained, bilateral agreements that simply provide transmission revenue 
contributions untethered from any assessment of the actual cost of providing transmission 
service induced by individual large loads may be insufficient to adequately protect other 
customers against unjustified cost shifts.3  It is therefore important that the resulting 
regulatory and rate design are not limited to a pre-defined solution set, and that parties 
provide the Commission with comprehensive records outlining various and innovative 
 
1348 (D.C. Cir. 1971) (stating that the FPA’s “primary aim is the protection of 
consumers from excessive rates and charges”). 
3 E.g., PECO Energy Co., 193 FERC ¶ 61,148 (2025) (Comm’r 
Chang, concurring); Commonwealth Edison Co., 194 FERC ¶ 61,109 (2026) (Comm’r 
Chang, concurring).

Docket No. EL26-67-000 
- 5 - 
 
 
approaches to protect customers.  I am encouraged by the continued development of the 
ANOPR record on this subject,4 innovative solutions being developed at the state level,5 
and a growing body of thoughtful analyses and proposed approaches to provide customer 
protection for costs driven by large load growth.6  Without prejudging any particular 
proposed solution, the Commission needs a robust record in each docket and each region 
to ensure we establish the right cost shift protections for wholesale customers, including 
but not limited to the commitments outlined in the Ratepayer Protection Pledge.7   
 
I support initiating our own review of customer protection approaches, rather than 
simply relying on voluntary commitments that may fall short of optimal protection, 
because the Commission has the opportunity and obligation to get this issue right.  I 
therefore encourage interested parties to assist the Commission in that effort by clearly 
and comprehensively explaining the benefits and tradeoffs of alternative customer 
protection approaches.  How power infrastructure costs will be assigned across Eligible 
Customers that serve large loads and other customers is at the core of the efforts we 
initiate today.       
IV. 
The Commission Needs to Understand the Implications of Extending New 
Transmission Services to Additional Loads and Regions 
 
The orders also preliminarily find that the Commission should extend the 
transmission services developed in the PJM co-location proceeding – Interim NITS, Firm 
Contract Demand, and Non-Firm Contract Demand – to new types of load and new 
 
4 E.g., Interconnection of Large Loads to the Interstate Trans. Sys., Supplemental 
Comments of FirstEnergy Svc. Co., Docket No. RM26-4-000 (filed June 5, 2026); id., 
Comment of the Harvard Electricity Law Initiative, Docket No. RM26-4-000 (Apr. 15, 
2026); id., Supplemental Comments of WIRES, Docket No. RM26-4-000 (Mar. 30, 
2026). 
5 E.g., Utility Dive, Microsoft seeks Nevada tariff to shield ratepayers from data 
center costs (June 8, 2026), available at https://www.utilitydive.com/news/microsoft-
seeks-nevada-tariff-to-shield-ratepayers-from-data-center-costs/822250/. 
6 E.g., Travis Kavulla, How Will Data Centers Pay for Power?, American Affairs 
(may 2026), available at https://americanaffairsjournal.org/2026/05/how-will-data-
centers-pay-for-power/ ; Electricity Customer Alliance, A Customer-Centric Agenda for 
the Federal Energy Reg. Comm’n (Jan. 2026), available at https://lnkd.in/em-apfuQ; 
Grid Strategies, Federal Transmission Pricing Vol. 2, Options for Ensuring Affordability 
in an Era of High Load Growth (June 2026), available at 
https://gridstrategiesllc.com/project/federal-transmission-pricing.  
7 Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026).

Docket No. EL26-67-000 
- 6 - 
 
 
regions.  These new transmission services represent a fundamental paradigm shift from 
the traditional network service and point-to-point transmission service models established 
in Order No. 888 that have been used across the country for the last three decades.  While 
these services have the potential to facilitate more efficient use and build out of the 
transmission system, they also contemplate running the system “tighter” than we have 
done in the past, potentially with more loads on the system served by co-located or 
behind-the-meter generation, and potentially more use of batteries, load control systems, 
and backup resources to manage demand during system peaks or other stressed 
conditions.  While it is important to identify innovative solutions that can adapt to the 
needs of the system, the Commission and grid operators must also be careful not to 
implement changes that create unforeseen reliability risks.  Ultimately, we must find the 
proper balance (and I would argue we are exploring a new balance) between costs of 
investments versus reliability.   
 
The Commission’s experience in the PJM co-location proceeding highlights the 
complexities and challenges of introducing these new transmission services, which have 
significant ramifications for system operations, transmission planning, grid reliability, 
market dispatch, resource adequacy, and cost allocation.  As the Commission considers 
whether to expand these transmission services to new types of load and new regions, I 
encourage commenters to address what impacts the introduction of new firm and non-
firm transmission products would have in their regions, as well as any relevant 
characteristics that might distinguish their regions from the Commission’s findings in the 
PJM co-location docket.  Ultimately, this topic will have direct long-term impacts on how 
future transmission systems will be planned and configured, how efficiently future power 
markets will operate, and how customers will respond to prices and system needs.  
Therefore, I am specifically interested in understanding how extending the new 
transmission services might affect individual suppliers or customers, as well as how 
existing systems or processes might be affected by these new services.  I am open to 
understanding how these services might be helpful to a region or that they may create 
problems not yet anticipated.   
V. 
The Orders Recognize the Importance of Evaluating Advanced Transmission 
Technologies 
 
Lastly, today we preliminarily find that each RTO/ISO’s tariff is unjust and 
unreasonable because the tariff lacks clear and consistent provisions requiring the 
evaluation of alternative transmission technologies as potential solutions to accommodate 
an Eligible Customer’s request for transmission service on behalf of a large load.  
Specifically, it is important for RTO/ISOs and transmission owners to evaluate whether 
alternative transmission technologies are feasible in reducing the cost of transmission 
system upgrades or allow for a faster timeline for accommodating the transmission 
service request.  As many transmission owners have explored various alternative

Docket No. EL26-67-000 
- 7 - 
 
 
technologies in pilot projects,8 it is time to roll out all available technologies to reduce 
risks and costs for customers, as well as help the industry continue to develop new 
technologies that can increase the robustness of our transmission system while protecting 
customers from higher costs. 
VI. 
Conclusion 
 
Today’s orders address some of the most consequential issues currently in the 
industry and before the Commission.  I hope that these proceedings provide vehicles 
through which the Commission can provide much-needed clarity and direction, and it is 
imperative that we build strong and comprehensive records on each issue in each region 
to inform our decision-making.  I therefore encourage all interested parties to fully 
engage and help the Commission navigate these complex, multi-faceted challenges.  Our 
success will ultimately be measured by our shared ability to deliver reliable and 
affordable power to all customers, to ensure new loads can interconnect in a timely 
fashion while paying their fair share of system costs, and to protect existing customers 
against adverse reliability or economic impacts.   
 
8 See, e.g., Increasing Mkt. and Planning Efficiency Through Improved Software, 
Effective Congestion Mitigation with Transmission Topology Optimization at Alliant 
Energy and ATC, Docket No. AD10-12-016, available at 
https://www.ferc.gov/media/effective-congestion-mitigation-transmission-topology-
optimization-alliant-energy-and-atc (Alliant and ATC were able to save customers 
approximately $24 million over a 12-month period through the use of topology 
optimization); Pablo Ruiz and Derek Brown, “Reliable and Efficient Congestion 
Mitigation Using Transmission Reconfigurations,” NewGrid and Evergy presentation 
(Oct. 2022)¸ available at https://www.spp.org/Documents/67968/SAG%20Meeting%20 
Materials%2020221007.zip (identifying reconfigurations, had they been implemented, 
which could eliminate 98% of overloads and reduce congestion costs by 85% for 
congestion patterns associated with 10 significant constraints on Evergy’s system); 
Pacific Gas & Electric Press Release, PG&E and Smart Wires Enhance Grid Reliability, 
Capacity for Data Centers in San Jose (May 28, 2025), available at 
https://investor.pgecorp.com/news-events/press-releases/press-release-details/2025/PGE-
and-Smart-Wires-Enhance-Grid-Reliability-Capacity-for-Data-Centers-in-San-
Jose/default.aspx (describing PG&E’s deployment of advanced power flow control 
devices were able to mitigate thermal overloads by up to 34%, enabling an additional 100 
MW of firm power delivery over existing lines at a congested substation).

Docket No. EL26-67-000 
- 8 - 
 
 
For these reasons, I respectfully concur.  
 
 
________________________ 
Judy W. Chang 
Commissioner

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
PJM Interconnection, L.L.C.  
AEP Appalachian Transmission Company, Inc. 
AEP Indiana Michigan Transmission Company, Inc. 
AEP Kentucky Transmission Company, Inc. 
AEP Ohio Transmission Company, Inc. 
AEP West Virginia Transmission Company, Inc. 
Allegheny Electric Cooperative, Inc. 
American Transmission Systems, Incorporated 
Appalachian Power Company 
Atlantic City Electric Company 
Baltimore Gas and Electric Company 
Commonwealth Edison Company 
Commonwealth Edison Company of Indiana, Inc. 
Dayton Power and Light Company 
Delmarva Power & Light Company 
Duke Energy Kentucky, Inc. 
Duke Energy Ohio, Inc. 
Duquesne Light Company 
Essential Power Rock Springs, LLC 
Hudson Transmission Partners, LLC 
Indiana Michigan Power Company 
Jersey Central Power & Light Company 
Kentucky Power Company 
Keystone Appalachian Transmission Company 
Kingsport Power Company 
Linden VFT, LLC 
Mid-Atlantic Interstate Transmission, LLC 
Monongahela Power Company 
Neptune Regional Transmission System, LLC 
NextEra Energy Transmission MidAtlantic Indiana, Inc. 
Ohio Power Company 
Ohio Valley Electric Corporation 
Old Dominion Electric Cooperative 
PECO Energy Company 
PPL Electric Utilities Corporation 
The Potomac Edison Company 
Potomac Electric Power Company 
Public Service Electric and Gas Company 
Rockland Electric Company 
Silver Run Electric, LLC 
Docket No. EL26-67-000

Docket No. EL26-67-000 
- 2 - 
 
 
Trans-Allegheny Interstate Line Company 
Transource West Virginia, LLC 
UGI Utilities, Inc. 
Virginia Electric and Power Company 
Wabash Valley Power Association, Inc. 
Wheeling Power Company 
 
 
(Issued June 18, 2026) 
 
LACERTE, Commissioner, concurring: 
 
 
I support today’s fleet of show cause orders.  We are at an inflection point in the 
history of American energy infrastructure.  The extraordinary and rapid growth of large 
loads in RTOs and ISOs is faster than the current system can handle.  This order charts a 
course for addressing the potential gaps and shortcomings in PJM’s Tariff that need to be 
resolved to appropriately respond to this growth, as informed by careful review of the 
thousands of pages of comments received in response to the advance notice of proposed 
rulemaking (ANOPR).1  I write separately to underscore my expectation for RTOs and 
ISOs, including PJM, to timely submit their robust, thoughtful, and region-specific 
proposals to address the concerns that we have preliminarily identified in their respective 
tariffs and agreements.  By harnessing your region-specific expertise and creativity to 
bring tailored solutions to the table, together we can efficiently, reliably, and affordably 
integrate large load, co-located load and generation and/or storage, as well as electrically 
proximate large load onto the transmission system.  I also support the use of alternative 
transmission technologies to unlock every megawatt of existing capacity from our current 
transmission system.  We have the technology.  We should use it now to enable faster 
interconnection of large loads, lower costs to customers, and help prevent cost shifting. 
 
To that end, and in light of our action in today’s orders, I also ask the state public 
utility commissions—whether they have already approved large load retail tariffs, are in 
the process of crafting large load retail tariffs, or have yet to embark on this essential 
tariff design process—to take a hard look and ensure their large load retail tariff 
provisions insulate ratepayers from the negative impacts of data center growth.  
Additionally, I expect PJM to design proposals in response to this show cause order that 
dovetail with the efforts on the retail side to implement the Ratepayer Protection Pledge, 
 
1 Interconnection of Large Loads to the Interstate Transmission System, Advance 
Notice of Proposed Rulemaking, Docket No. RM26-4-000, (Oct. 23, 2025) (ANOPR); 
see also Letter from Chris Wright, Sec’y, U.S. Dep’t of Energy (Oct. 23, 2025) 
(Secretary’s Letter).

Docket No. EL26-67-000 
- 3 - 
 
 
protect customers, and ensure that large loads cover the costs they incur to integrate with 
the grid.   
 
The stakes here could not be higher and every gambler knows that the secret to 
surviving is knowing what to throw away and knowing what to keep.2  Today’s orders do 
exactly that—adopting thoughtful proposals that position our nation for success, driving 
meaningful change, and rejecting the gridlock, half-measures, and failure to plan that 
have gone on for far too long.  The data center odyssey that we embarked upon first with 
PJM, then SPP, we now aggressively extend to all the RTO/ISO regions.3  Enabling the 
swift and efficient interconnection of large loads to the transmission system while 
maintaining affordability, reliability, commitment to open access, competitive principles 
and cooperative federalism, will only be achieved through consistent, coordinated action 
and persistence.  But without that first step,4 there is no direction, no forward momentum, 
no journey, and no way to arrive at our future destination.  In the show cause orders we 
issue today, the Commission takes a series of long strides towards our ultimate large load 
interconnection destination:  we make preliminary findings that the RTO/ISO tariffs, 
including PJM may be unjust and unreasonable and/or unduly discriminatory or 
preferential because they lack features necessary to timely, reliably, and safely 
interconnect and serve new large loads in a way that produces just and reasonable rates. 
 
I commend each commentor for their robust and ongoing responses to the 
concerns that Secretary Wright and the Commission raised in the ANOPR proceeding.  
The comments helped us identify the common issues, common solutions, and individual 
differences among the RTOs/ISOs.  We heard a plea for broad flexibility and regionally 
tailored solutions.  And we will strive to work towards those solutions, not through top-
down, one-size-fits-all mandates, but through consideration of region-specific proposals.  
And we endeavor to support an appeal for federal policies that build upon rather than 
disrupt current and planned developments, reflecting state and local processes and 
stakeholder efforts.  Through these individually tailored and region-specific show cause 
orders, we are delivering to ensure that our transmission system can accommodate new 
large loads in a timely, safe, and reliable manner.  And, importantly, in a manner that 
 
2 Kenny Rogers, The Gambler (United Artists Records 1978). 
3 Interconnection of Large Loads to the Interstate Transmission System, 195 
FERC ¶ 61,045 at P 2 (2026) (Order Regarding Intent to Act) (citing PJM Co-Location 
Order, 193 FERC ¶ 61,217; SPP HILL Order, 194 FERC ¶ 61,031; Commonwealth 
Edison Co., 194 FERC ¶ 61,181 (2026); Tri-State Generation and Transmission Ass’n, 
193 FERC ¶ 61,070 (2025); Duke Energy Carolinas, LLC, 193 FERC ¶ 61,237 (2025)). 
4 Admittedly, we are further down the road in some regions as compared with 
others.

Docket No. EL26-67-000 
- 4 - 
 
 
ensures benefits and protection for all customers.  Affordability remains a top concern as 
we proceed forward.   
 
The collective voices in the ANOPR comments have shaped our decision to issue 
six separate individually tailored and region-specific show cause orders, rather than a 
proposed final rule at this time.  But the success of the next phase of this journey rests 
with you, PJM, and your stakeholders.  We are directing you to expeditiously bring 
forward for our consideration your novel, region-specific solution(s).  Time is of the 
essence.  By inviting you to proceed under FPA section 205, we are giving you 
significant perks:  the benefits of first wielder of the pen and the relatively capacious 
standard under FPA section 205 that allows us to accept a potentially broad range of 
proposals provided they are shown to be just and reasonable and not unduly 
discriminatory or preferential.5  We are even giving you flexibility to propose the 
implementation date for your innovative proposals.  But such freedom comes with great 
and concomitant responsibility.   
 
This is not a time to be cavalier and dodge the urgent need to meet the moment.  
While this is a long journey, even so, we must continue to move at breakneck pace to win  
the AI race.  So let me be direct.  If you choose not to submit timely, reasonable, non-
discriminatory or preferential, comprehensive, and substantiated proposal(s), as directed 
and as required under our applicable statutes, your deficient response will not go 
unnoticed.  I am prepared to play jurisdictional hardball, if needed.6  This Commission 
has appropriately exercised considerable restraint in asserting the full scope of our 
jurisdiction in these orders.  However, the Commission has very broad jurisdiction over 
transmission that we will not hesitate to utilize as necessary to ensure that we meet our 
objectives in all show cause proceedings, including this PJM proceeding we initiate here.  
If we find your Tariff is in fact unjust and unreasonable and unduly discriminatory or 
 
5 See, e.g., NRG Power Mktg, LLC v. FERC, 862 FERC 108, 105 (D.C. Cir. 2017) 
(FERC may not employ a rate design that follows “a completely different strategy” than, 
or is “methodologically distinct” from, a proposed rate) (internal quotations omitted); 
Oxy USA, Inc. v. FERC, 64 F.3d 679, 692 (D.C. Cir. 1995) (stating that a proposal under 
FPA section 205 “need not be the only reasonable methodology, or even the most 
accurate”); City of Winnfield v. FERC, 744 F.2d 871, at 874-875 (D.C. Cir. 1984) 
(comparing the respective authorities of the Commission and public utilities under 
sections 205 and 206). 
6 16 U.S.C. § 824(b); New York v. FERC, 535 U.S. 17 (2002) (“There is no 
language in the statute limiting FERC’s transmission jurisdiction to the wholesale 
market[.]”)) (emphasis in original); id. at 20 (stating that “the FPA authorizes FERC's 
jurisdiction over interstate transmissions, without regard to whether the transmissions are 
sold to a reseller or directly to a consumer[.]”).

Docket No. EL26-67-000 
- 5 - 
 
 
preferential, any failure on your end to provide a sufficient FPA filing or filings to 
address the large-load-related concerns that we have identified will result in the 
Commission dictating the solutions for you.  I say this not as a threat, but as a statement 
of duty.  While you may not like our remedies—I have often said that the federal 
government generally does not come up with the best solutions—this is an outcome we 
are prepared to pursue given the gravity of the moment and our statutory obligation.  
Notwithstanding our readiness to step in, it greatly benefits everyone for you to come up 
with an approach tailored to your region.  
 
I will end my concurrence where I began:  We have heard your concerns, and, let 
me underscore, now is the time for you to heed ours.  This is an extraordinarily 
consequential proceeding.  The stakes for reliability, for affordability, and for the 
American ratepayer could not be higher.  We owe it to the public to get this right.  I look 
forward to reviewing and acting as expeditiously as possible on your responses to this 
show cause order, which I expect will include an FPA section 205 proposal or proposals. 
 
For these reasons, I respectfully concur. 
 
 
______________________________ 
David LaCerte 
Commissioner