EL25-49-002 · 2026-06-18 · FERC

PJM co-location rehearing order

195 FERC ¶ 61,209 
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. 
Allegheny Electric Cooperative, Inc. 
American Transmission Systems, Incorporated 
Atlantic City Electric Company 
Baltimore Gas and Electric Company 
Delmarva Power & Light Company 
Duke Energy Ohio, Inc. 
Duke Energy Kentucky, Inc. 
East Kentucky Power Cooperative, Inc. 
Essential Power Rock Springs, LLC 
Hudson Transmission Partners, LLC 
Jersey Central Power & Light Company 
Mid-Atlantic Interstate Transmission, LLC 
Neptune Regional Transmission System, LLC 
Old Dominion Electric Cooperative 
PECO Energy Company 
PPL Electric Utilities Corporation 
Potomac Electric Power Company 
Public Service Electric and Gas Company 
Rockland Electric Company 
Trans-Allegheny Interstate Line Company 
Transource West Virginia, LLC 
UGI Utilities, Inc. 
Monongahela Power Company 
The Potomac Edison Company 
Commonwealth Edison Company 
Commonwealth Edison Company of Indiana, Inc. 
The Dayton Power and Light 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. 
Appalachian Power Company 
Indiana Michigan Power Company 
Docket Nos. EL25-49-002 
EL25-49-000

Docket No. EL25-49-002, et al. 
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Kentucky Power Company 
Kingsport Power Company 
Ohio Power Company 
Wheeling Power Company 
Duquesne Light Company 
Virginia Electric and Power Company 
Linden VFT, LLC 
City of Cleveland, Department of Public Utilities, 
Division of Cleveland Public Power 
City of Hamilton, OH 
Southern Maryland Electric Cooperative, Inc. 
Ohio Valley Electric Corporation 
AMP Transmission, LLC 
Silver Run Electric, LLC 
NextEra Energy Transmission MidAtlantic Indiana, Inc. 
Wabash Valley Power Association, Inc. 
Keystone Appalachian Transmission Company 
Large Loads Co-Located at Generating Facilities  
Constellation Energy Generation, LLC 
v.  
PJM Interconnection, L.L.C. 
PJM Interconnection, L.L.C. 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
AD24-11-001 
 
EL25-20-001 
(consolidated) 
 
 
 
 
ER26-1479-000 
 
ORDER ON REHEARING, CLARIFICATION, COMPLIANCE FILING, AND PAPER 
HEARING 
 
(Issued June 18, 2026) 
 
 
On December 18, 2025, the Commission issued an order in the show cause 
proceeding in Docket No. EL25-49-000, et al., pursuant to section 206 of the Federal 
Power Act (FPA),1 finding PJM Interconnection, L.L.C.’s (PJM) Tariff 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 generators serving 
 
1 16 U.S.C. § 824e.

Docket No. EL25-49-002, et al. 
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Co-Located Load and Eligible Customers taking transmission service on behalf of       
Co-Located Load.2   
 
The Commission directed PJM to file, within 60 days of the date of issuance of the 
order, a compliance filing to revise its Tariff to set forth specific terms and conditions 
that an Interconnection Customer in PJM seeking to serve Co-Located Load must follow 
to effectuate a Co-Location Arrangement.  In addition, the Commission directed PJM to 
submit in its compliance filing revisions to its Tariff to require that the Eligible Customer 
taking transmission service on behalf of the Co-Located Load takes one of three 
transmission services:  (1) Network Integration Transmission Service (NITS), including a 
new interim, non-firm transmission service available until all Network Upgrades 
necessary to provide the requested NITS are complete (Interim NITS), (2) a new Firm 
Contract Demand (FCD) transmission service, or (3) a new Non-Firm Contract Demand 
(NFCD) transmission service.3  The Commission established a paper hearing to 
determine the just and reasonable rates, terms, and conditions for these new transmission 
services.   
 
The Commission also found the Behind the Meter Generation (BTMG) rules in the 
Tariff to be no longer just and reasonable, and the Commission directed PJM to submit in 
its compliance filing revisions to its Tariff to revise the retail BTMG netting rules and to 
implement a transition process for existing BTMG participants.4   
 
2 PJM Interconnection, L.L.C., 193 FERC ¶ 61,217, at P 2 (2025) (December 
Order).  The December Order defined the Tariff as PJM’s Open Access Transmission 
Tariff (OATT), the Amended and Restated Operating Agreement of PJM, and the 
Reliability Assurance Agreement Among Load Serving Entities in the PJM Region.  See 
Appendix for tariff records accepted in this order. 
3 Capitalized terms used but not otherwise defined in this order have the meanings 
ascribed to them in the Tariff. 
4 PJM defines BTMG as “a generation unit that delivers energy to load without 
using the Transmission System or any distribution facilities (unless the entity that owns 
or leases the distribution facilities has consented to such use of the distribution facilities 
and such consent has been demonstrated to the satisfaction of the Office of the 
Interconnection); provided, however, that [BTMG] does not include:  (i) at any time, any 
portion of such generating unit’s capacity that is designated as a Generation Capacity 
Resource; or (ii) in an hour, any portion of the output of such generating unit that is sold 
to another entity for consumption at another electrical location or into the PJM 
Interchange Energy Market.”  PJM, Intra-PJM Tariffs, OATT, § I.1 Definitions – A-B 
(21.0.0) (defining BTMG).

Docket No. EL25-49-002, et al. 
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On January 16, 2026, Exelon and FirstEnergy5 timely filed a request for rehearing 
of the December Order.  On January 20, 2026, Industrials6 timely filed a request for 
clarification or, in the alternative, rehearing.  On January 20, 2026, Constellation Energy 
Generation, LLC (Constellation) filed a request for clarification or, in the alternative, 
rehearing.  On January 20, 2026, PIOs7 filed a limited request for clarification.  On 
January 20, 2026, Joint Parties8 filed a request for clarification.  On February 9, 2026, 
Andrew Hinz filed a late request for rehearing. 
 
On February 23, 2026, in Docket No. ER26-1479-000, PJM filed its second 
compliance filing as directed by the December Order. 
 
On February 23, 2026, in Docket No. EL25-49-000, PJM and the Indicated TOs9 
each submitted an initial brief to address the Commission’s paper hearing questions with 
 
5 The request for rehearing was filed only by (1) Exelon Corporation (Exelon), 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; and (2) 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 (collectively, FirstEnergy). 
6 As to the request for clarification or, in the alternative, rehearing, Industrials are 
the PJM Industrial Customer Coalition (PJM ICC) and the Industrial Energy Consumers 
of America (IECA). 
7 As to the request for clarification, PIOs are EarthJustice, Environmental Defense 
Fund, and Sierra Club. 
8 As to the request for clarification, Joint Parties are Eolian LP, Antora Energy 
LLC, and Verrus LLC. 
9 We refer to the Indicated PJM Transmission Owners that submitted briefing 
jointly in the paper hearing as Indicated TOs.  The transmission owners that submitted 
briefing jointly in the paper hearing are:  American Electric Power Service Corporation 
on behalf of its affiliates, Appalachian Power Company, Indiana Michigan Power 
Company, Kentucky Power Company, Kingsport Power Company, Ohio Power 
Company, Wheeling Power Company, AEP Appalachian Transmission Company, AEP 
Indiana Michigan Transmission Company, AEP Kentucky Transmission Company, AEP 
Ohio Transmission Company, and AEP West Virginia Transmission Company; The 
Dayton Power and Light Company d/b/a AES Ohio; Dominion Energy Services, Inc. on 
behalf of Virginia Electric and Power Company d/b/a Dominion Energy Virginia; Duke

Docket No. EL25-49-002, et al. 
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respect to the new transmission services.  On March 25, 2026, and on April 24, 2026, 
parties submitted response briefs and reply briefs, respectively. 
 
In this order, we address the requests for rehearing and clarification of the 
December Order, PJM’s compliance filing, and the paper hearing on the new 
transmission services.  Pursuant to Allegheny Defense Project v. FERC,10 the rehearing 
requests filed in this proceeding may be deemed denied by operation of law.  However, 
as permitted by section 313(a) of the FPA,11 we are modifying the discussion in the 
December Order and setting aside the order, in part, as discussed below.12  In addition, 
we are granting, in part, and denying, in part, the requests for clarification.   
 
Next, we find that PJM’s compliance filing partially complies with the directives 
of the December Order.  As such, we accept in part and reject in part PJM’s proposed 
Tariff revisions, and we direct PJM to file, within 60 days of the date of issuance of this 
order, a further compliance filing. 
 
Finally, in response to the record developed in the paper hearing, we establish as 
just and reasonable certain rates, terms, and conditions for the new transmission services 
directed in the December Order (i.e., Interim NITS, FCD transmission service, and 
NFCD transmission service).  We direct PJM to file, within 60 days of the date of 
issuance of this order, a compliance filing to revise its Tariff.  We also direct the PJM 
transmission owners to file, within 60 days of the date of issuance of this order, a 
compliance filing to revise the Tariff. 
 
Energy Business Services, LLC for Duke Energy Kentucky, Inc. and Duke Energy Ohio, 
Inc.; Duquesne Light Company; East Kentucky Power Cooperative; Exelon; FirstEnergy; 
PPL Electric Utilities Corporation; Public Service Electric and Gas Company; Rockland 
Electric Company; and the Southern Maryland Electric Cooperative. 
10 964 F.3d 1 (D.C. Cir. 2020) (en banc).   
11 16 U.S.C. § 825l(a) (“Until the record in a proceeding shall have been filed in a 
court of appeals, as provided in subsection (b), the Commission may at any time, upon 
reasonable notice and in such manner as it shall deem proper, modify or set aside, in 
whole or in part, any finding or order made or issued by it under the provisions of this 
chapter.”). 
12 Allegheny Def. Project, 964 F.3d at 16-17.

Docket No. EL25-49-002, et al. 
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Contents 
I. 
Background .............................................................................................................. - 9 - 
A. 
February Order .................................................................................................. - 9 - 
B. 
December Order .............................................................................................. - 11 - 
II. 
Notice of Filings and Responsive Pleadings ...................................................... - 14 - 
A. 
PJM’s Compliance Filing ............................................................................... - 14 - 
B. 
Paper Hearing on New Transmission Services ............................................... - 15 - 
III. 
Procedural Matters ............................................................................................. - 16 - 
IV. 
Requests for Rehearing and/or Clarification ...................................................... - 18 - 
A. 
Jurisdiction ...................................................................................................... - 19 - 
1. Sales for Resale in Interstate Commerce ........................................................ - 19 - 
2. Retail Allocation of Commission-Jurisdictional Rates ................................... - 20 - 
3. Retail BTMG................................................................................................... - 22 - 
4. Retail Backup Service ..................................................................................... - 24 - 
B. 
Show Cause Findings ...................................................................................... - 26 - 
1. Overview, Transmission Service, Regulation and Black Start ....................... - 26 - 
2. Retail BTMG Netting Rules ........................................................................... - 41 - 
3. Transmission Service Options for BTMG ...................................................... - 50 - 
C. 
Replacement Rate ........................................................................................... - 52 - 
1. Transmission Services .................................................................................... - 52 - 
2. Necessary Study Process for Existing Interconnection Customers ................ - 87 - 
3. New Generators Serving Co-Located Load .................................................... - 95 - 
D. 
Informational Report ....................................................................................... - 97 - 
1. December Order .............................................................................................. - 97 - 
2. Request for Clarification ................................................................................. - 98 - 
3. Determination.................................................................................................. - 99 - 
V. 
Compliance ......................................................................................................... - 99 - 
A. 
BTMG Rules ................................................................................................... - 99 - 
1. Materiality Threshold ...................................................................................... - 99 - 
2. Grandfathering and Transition Period .......................................................... - 116 -

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3. QFs and Cogeneration Facilities ................................................................... - 121 - 
B. 
Transmission Service .................................................................................... - 127 - 
1. December Order ............................................................................................ - 127 - 
2. PJM Compliance Filing ................................................................................ - 129 - 
3. Pleadings ....................................................................................................... - 130 - 
4. Answers ......................................................................................................... - 131 - 
5. Determination................................................................................................ - 132 - 
C. 
Necessary Studies ......................................................................................... - 135 - 
1. December Order ............................................................................................ - 135 - 
2. PJM Compliance Filing ................................................................................ - 136 - 
3. Pleadings ....................................................................................................... - 136 - 
4. Determination................................................................................................ - 139 - 
D. 
Other .............................................................................................................. - 143 - 
1. December Order ............................................................................................ - 143 - 
2. PJM Compliance Filing ................................................................................ - 144 - 
3. Pleadings ....................................................................................................... - 147 - 
4. Answers ......................................................................................................... - 150 - 
5. Determination................................................................................................ - 150 - 
E. 
Effective Date ............................................................................................... - 154 - 
1. PJM Compliance Filing ................................................................................ - 154 - 
2. Effective Date Pleadings ............................................................................... - 154 - 
3. Determination................................................................................................ - 155 - 
VI. 
Paper Hearing ................................................................................................... - 155 - 
A. 
Rates, Terms, and Conditions for Firm and Non-Firm Contract Demand 
Transmission Service .............................................................................................. - 156 - 
1. December Order ............................................................................................ - 156 - 
2. Nature of FCD and NFCD Transmission Services ....................................... - 157 - 
3. Study Process ................................................................................................ - 171 - 
4. Rates and Charges ......................................................................................... - 179 - 
5. Other .............................................................................................................. - 193 - 
B. 
Additional Charge for Eligible Customers Taking FCD and/or NFCD 
Transmission Service .............................................................................................. - 199 - 
1. December Order ............................................................................................ - 199 -

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2. Initial Briefs .................................................................................................. - 200 - 
3. Response Briefs............................................................................................. - 201 - 
4. Reply Briefs .................................................................................................. - 204 - 
5. Answers ......................................................................................................... - 206 - 
6. Determination................................................................................................ - 207 - 
C. 
Interconnection Requirements and Operational Practices for Necessary Control 
Technologies and/or Protection Systems ................................................................ - 208 - 
1. Initial Briefs .................................................................................................. - 208 - 
2. Response Briefs............................................................................................. - 209 - 
3. Reply Briefs .................................................................................................. - 211 - 
4. Answer .......................................................................................................... - 214 - 
5. Determination................................................................................................ - 214 - 
D. 
Penalty Charge or Other Remedial Action for New Transmission Services - 218 - 
1. Initial Briefs .................................................................................................. - 218 - 
2. Response Briefs............................................................................................. - 220 - 
3. Reply Briefs .................................................................................................. - 223 - 
4. Answer .......................................................................................................... - 227 - 
5. Determination................................................................................................ - 227 - 
E. 
Anti-Toggling Mechanisms for Firm Contract Demand Transmission Service ..... - 
237 - 
1. Initial Briefs .................................................................................................. - 237 - 
2. Response Briefs............................................................................................. - 238 - 
3. Determination................................................................................................ - 238 - 
F. 
Communications, Alarm, SCADA, or Other Requirements ......................... - 240 - 
1. Initial Briefs .................................................................................................. - 240 - 
2. Response Briefs............................................................................................. - 240 - 
3. Determination................................................................................................ - 240 - 
G. 
Curtailment Procedures for Interim NITS and Non-Firm Contract Demand 
Transmission Service .............................................................................................. - 241 - 
1. Initial Briefs .................................................................................................. - 241 - 
2. Response Briefs............................................................................................. - 242 - 
3. Reply Briefs .................................................................................................. - 243 - 
4. Answers ......................................................................................................... - 244 -

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5. Determination................................................................................................ - 244 - 
H. 
Rates, Terms, and Conditions for Interim NITS ........................................... - 246 - 
1. Initial Briefs .................................................................................................. - 246 - 
2. Response Briefs............................................................................................. - 247 - 
3. Reply Briefs .................................................................................................. - 250 - 
4. Answers ......................................................................................................... - 251 - 
5. Determination................................................................................................ - 252 - 
I. 
Annual Report on New Transmission Services ................................................ - 256 - 
J. 
Proposed Effective Date ................................................................................... - 258 - 
1. Initial Briefs .................................................................................................. - 258 - 
2. Response Briefs............................................................................................. - 259 - 
3. Reply Briefs .................................................................................................. - 262 - 
4. Answer .......................................................................................................... - 264 - 
5. Determination................................................................................................ - 264 - 
K. 
Additional Arguments ................................................................................... - 265 - 
1. Behind the Meter Generation ........................................................................ - 265 - 
2. Reliability Backstop Auction ........................................................................ - 265 - 
3. Eligible Customer Requirements .................................................................. - 267 - 
4. Demand Side Pathways ................................................................................. - 268 - 
5. Interconnection.............................................................................................. - 269 - 
6. Co-Location Arrangement with Electric Storage Resource ......................... - 270 - 
 
I. 
Background 
A. 
February Order 
 
In February 2025, the Commission instituted a new proceeding in Docket                     
No. EL25-49-000 to examine whether the Tariff remains just and reasonable and not 
unduly discriminatory or preferential without provisions addressing with sufficient clarity 
or consistency the rates, terms, and conditions of service that apply to co-location 
arrangements.13  The February 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 
 
13 PJM Interconnection, L.L.C., 190 FERC ¶ 61,115, at P 2 (2025) (February 
Order).

Docket No. EL25-49-002, et al. 
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or planned Customer Facility on the Interconnection Customer’s side of the Point of 
Interconnection to the PJM Transmission System.’”14  As in the February Order, when 
referring to both the Co-Located Load and the associated generator, we will use the term 
Co-Location Arrangement. 
 
As explained in the February Order, Co-Location Arrangements are becoming 
increasingly common in PJM and, since the issuance of the February Order, entities 
continue to raise issues involving Co-Location Arrangements with the Commission.15  
The Commission set forth, in the February Order, the principles relating to the 
Commission’s jurisdiction over the matters relevant to Co-Location Arrangements.16  The 
Commission also made several preliminary findings about the justness and 
reasonableness of the Tariff.  First, the Commission found that the Tariff appears to be 
unjust and unreasonable or unduly discriminatory or preferential because it does not 
contain provisions addressing with sufficient clarity or consistency the rates, terms, and 
 
14 Id. P 3 & n.4.  We note that, in the February Order, the Commission adopted 
this definition from the Guidance Document that PJM developed on Co-Located Load.  
See id.  PJM rescinded this document pending Commission guidance in this docket.  PJM 
March 24, 2025 Response at 33.  Prior to PJM’s transition to its new interconnection 
process, PJM used the terms Interconnection Customer and Generation Interconnection 
Customer.  The Tariff defines Generation Interconnection Customer as “an entity that 
submits an Interconnection Request to interconnect a new generation facility or to 
increase the capacity of an existing generation facility interconnected with 
the Transmission System in the PJM Region.”  PJM, Intra-PJM Tariffs, OATT, § I.1 
Definitions – G – H) (9.0.1) (defining Generation Interconnection Customer).  The 
Tariff’s new rules for generation interconnection, effective January 3, 2023, utilize the 
terms Project Developer and Generation Project Developer.  The Tariff defines 
Generation Project Developer as “an entity that submits a Generation Interconnection 
Request to interconnect a new generation facility or to increase the capacity of an existing 
generation facility interconnected with the Transmission System in the PJM Region.”  
PJM, Intra-PJM Tariffs, OATT, § VIII subpt. A 400 (Definitions G) (0.1.0) (defining 
Generation Project Developer).  For simplicity, in this order, and consistent with the 
February Order and December Order, the Commission will use the term Interconnection 
Customer to refer to both the Tariff definitions of Generation Interconnection Customer 
and Generation Project Developer. 
15 See, e.g., PJM Interconnection, L.L.C., 191 FERC ¶ 61,112 (2025) (accepting 
necessary studies agreement).  The February Order consolidated the new show cause 
proceeding with a pending complaint proceeding in Docket No. EL25-20-000 involving 
Co-Located Load.   
16 February Order, 190 FERC ¶ 61,115 at P 66.

Docket No. EL25-49-002, et al. 
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conditions of service that apply to Co-Location Arrangements.17  In addition, the 
Commission preliminarily found that this lack of applicable Tariff provisions raises the 
potential for undue discrimination or preferential treatment.18  
 
As to specific concerns raised regarding Co-Location Arrangements, the 
Commission found that the Tariff may be unjust, unreasonable, unduly discriminatory, or 
preferential because it does not specify the transmission service that Co-Location 
Arrangements must take, if any, or otherwise provide a process to ensure that                          
Co-Location Arrangements are paying for the benefits they receive from the transmission 
system consistent with cost causation principles, which provide that all                      
Commission-jurisdictional rates and charges must “reflect to some degree the costs 
actually caused by the customer who must pay for them,” and that costs must be allocated 
in a manner that is at least roughly commensurate with the benefits that entity receives.19  
The Commission also found that the absence of rates, terms, and conditions of 
interconnection service specific to Co-Location Arrangements, and, especially regarding 
studies of the impacts of those arrangements, may render the Tariff unjust and 
unreasonable or unduly discriminatory or preferential.20  Moreover, the Commission 
found that the absence of rates, terms, and conditions governing the use and sale of 
ancillary services and black start services by Co-Location Arrangements may render the 
Tariff unjust and unreasonable or unduly discriminatory or preferential.21  The 
Commission directed briefing to build a record on these issues as well as a possible 
replacement rate. 
B. 
December Order 
 
In the December Order, the Commission found the Tariff 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 
 
17 Id. P 74. 
18 Id. P 75. 
19 Id. PP 74-78 (citing 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)). 
20 Id. P 79. 
21 Id. P 82.

Docket No. EL25-49-002, et al. 
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of Co-Located Load.22  The Commission explained that the absence of such provisions 
leaves entities unable to determine what steps they must take to effectuate Co-Location 
Arrangements and creates uncertainty that has resulted in disparate treatment in PJM 
because transmission owners have taken different approaches to performing the necessary 
steps that apply to Interconnection Customers seeking to serve Co-Located Load through 
a Co-Location Arrangement.23  The Commission found that the absence of such 
provisions also introduces the risk that Co-Located Load may benefit from regulation and 
black start services without contributing to cost recovery for such services.24   
 
Specifically, the Commission found the Tariff 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.25  As part of 
the replacement rate, the Commission directed PJM to file revisions to the generation 
interconnection procedures of the Tariff, including to require an Interconnection 
Customer who will use its generator to serve Co-Located Load to specify an Eligible 
Customer who will take transmission service on behalf of the Co-Located Load, and 
revisions to clarify its Necessary Study process.26  The Commission also directed PJM to 
revise its Tariff to clarify that an Interconnection Customer seeking to serve a                            
Co-Located Load with a newly interconnecting generator may:  (1) request 
interconnection service at a level below its maximum facility output; (2) use existing 
procedures in the Tariff to accelerate the study of the interconnection service request if 
the request has no cost allocation for Network Upgrades and does not require further 
studies; (3) request provisional interconnection service; and (4) request Surplus 
Interconnection Service.27   
 
The Commission also found the Tariff unjust and unreasonable because it does not 
include transmission services that reflect Eligible Customers taking service on behalf of 
Co-Located Loads that are willing and able to limit their energy withdrawals from the 
transmission system under certain conditions.28  The Commission further found the Tariff 
 
22 December Order, 193 FERC ¶ 61,217 at P 175. 
23 Id. 
24 Id. 
25 Id. P 176. 
26 Id. PP 176, 187-192, 225-230. 
27 Id. PP 176, 231-235. 
28 Id. PP 177, 193.

Docket No. EL25-49-002, et al. 
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unjust and unreasonable because it does not address charges related to Co-Located 
Loads’ use of regulation and black start services, which introduces the risk that                       
Co-Located Load may benefit from regulation and black start services without 
contributing to cost recovery for such services and, thereby, the risk that costs may be 
allocated entirely to other transmission customers and passed through to residential 
customers, among others.29  The Commission found that NITS charged on a gross 
demand basis is one just and reasonable transmission service option for Eligible 
Customers taking transmission service on behalf of Co-Located Loads, but it is not the 
only option.30  The Commission thus directed PJM to revise its Tariff to create three new 
transmission services (i.e., Interim NITS, FCD transmission service, and NFCD 
transmission service) that reflect that Eligible Customers taking service on behalf of     
Co-Located Loads are willing and able to limit their energy withdrawals from the 
transmission system under certain conditions.31  Specific to these new transmission 
services, the Commission established paper hearing procedures to determine the just and 
reasonable rates, terms, and conditions for such services.32   
 
The Commission also found the existing retail BTMG netting rules in the Tariff to 
be unjust and unreasonable.  PJM’s existing Tariff allows load serving entities (LSE) that 
provide service to loads with qualifying BTMG to reduce their costs by netting output 
from BTMG in the calculation of their peak demand for the purpose of determining NITS 
charges.33  The Commission explained that these retail BTMG netting rules may lead to 
both reliability and resource adequacy risks because PJM, per its Tariff, is obligated to 
serve transmission customers using BTMG but does not consider such customers’ full 
gross load in transmission and resource adequacy planning.34  Thus, the Commission 
directed PJM to revise its retail BTMG netting rules.35  In recognizing concerns about the 
potential impacts on existing BTMG customers, the Commission directed PJM to 
maintain the current retail BTMG netting rules for customers that fall below a new MW 
materiality threshold for the amount of load at a particular electrical location that 
Network Customers may net using BTMG and to implement a two-part transition process 
 
29 Id. P 177. 
30 Id. PP 195-196. 
31 Id. PP 178, 200-202, 206, 208-218. 
32 Id. PP 178, 194, 203, 207, 219. 
33 Id. P 7. 
34 Id. PP 179, 186. 
35 Id. PP 179, 221.

Docket No. EL25-49-002, et al. 
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for retail BTMG including:  (1) the establishment of a three-year transition period; and 
(2) the ability to grandfather certain entities with existing contracts.36   
II. 
Notice of Filings and Responsive Pleadings 
A. 
PJM’s Compliance Filing 
 
Notice of PJM’s compliance filing in Docket No. ER26-1479-000 was published 
in the Federal Register, 91 Fed. Reg. 9849 (Feb. 27, 2026) with interventions and 
protests due on or before March 16, 2026. 
 
Timely motions to intervene were filed by American Forest & Paper Association 
(AF&PA); PJM Industrial Customer Coalition (PJM ICC); Industrial Energy Consumers 
of America (IECA); Monitoring Analytics, LLC, acting in its capacity as the Independent 
Market Monitor for PJM (Market Monitor); LS Power Development, LLC; Enchanted 
Rock, LLC (Enchanted Rock); Illinois Municipal Electric Agency; American Clean 
Power Association; New Jersey Division of Rate Counsel; PJM Power Providers Group; 
American Electric Power Service Corporation; Exelon Corporation; Constellation Energy 
Generation, LLC (Constellation); Public Citizen, Inc.; East Kentucky Power Cooperative, 
Inc.; Clean Energy Buyers Association; Edison Electric Institute; Maryland Office of 
People’s Counsel (Maryland OPC); EDF Power Solutions, Inc. (EDFps); Solar Energy 
Industries Association (SEIA); Advanced Energy United (AEU); Buckeye Power, Inc.; 
Electric Power Supply Association; Duquesne Light Company; North Carolina Electric 
Membership Corporation; New Jersey Board of Public Utilities; Appalachian Voices; 
Pennsylvania Office of Consumer Advocate; Public Service Electric and Gas Company, 
PSEG Power LLC and PSEG Energy Resources & Trade LLC (collectively, PSEG 
Companies); Old Dominion Electric Cooperative (ODEC); National Railroad Passenger 
Corporation (Amtrak); Dominion Energy Services, Inc.; Crusoe Energy Systems, Inc. 
(Crusoe); Consolidated Edison Company of New York, Inc.; PPL Electric Utilities 
Corporation (PPL); Rockland Electric Company; Illinois Industrial Energy Consumers; 
American Municipal Power, Inc. (AMP); Grid Reform; Invenergy Renewables LLC and 
Invenergy Thermal LLC (Invenergy); Data Center Coalition (DCC); Eastman Chemical 
Company (Eastman); Northern Virginia Electric Cooperative, Inc. (NOVEC); Vistra 
Corp. (Vistra); Mainspring Energy; Northeastern REMC; Borough of Chambersburg, 
Pennsylvania; Capital Power Corporation; Eolian, L.P. (Eolian); Antora Energy, Inc. 
(Antora); Calibrant Energy (Calibrant); Convergent Energy and Power (Convergent); and 
Verrus, LLC (Verrus). 
 
Motions to intervene out of time were filed by Arkon Energy Hannibal and Office 
of the Illinois Attorney General. 
 
36 Id. PP 179, 221, 223-224.

Docket No. EL25-49-002, et al. 
- 15 - 
 
Timely comments and/or protests were filed by Eastman; EDFps; Digital Power 
Network; Vistra; Maryland OPC; AEU/SEIA; Eolian, Antora, Calibrant, Convergent, 
Mainspring, and Verrus (together, Joint Parties); Calibrant, Antora, Convergent, Eolian, 
and Mainspring (together, BTMG Parties); Invenergy; Energy Artisans, LLC (Energy 
Artisans); DCC; PJM ICC, IECA, AF&PA (collectively, Industrials) and Amtrak 
(Industrials/Amtrak); Digital Power Network; Crusoe; AMP; Appalachian Voices; and 
Constellation. 
 
On April 8, 2026, Constellation filed a motion for leave and supplemental protest 
in this compliance proceeding and in Docket No. ER26-1088-000.  On April 14, 2026, 
Exelon filed an answer to Constellation’s motion.  On April 24, 2026, Indicated TOs filed 
a motion for leave to answer and answer to certain protests and comments.  On May 8, 
2026, the BTMG Parties and Industrials/Amtrak each filed a motion for leave to answer 
and answer the Indicated TOs’ April 24 answer.  On May 12, 2026, Eastman filed a 
motion for leave to answer and answer the Indicated TOs’ April 24 answer.  On June 3, 
2026, Indicated TOs filed a motion for leave to answer and answer. 
 
Several parties filed briefs for the paper hearing in Docket No. EL25-49-000 and 
filed these submissions in this compliance proceeding as well.  Specifically, in this 
compliance proceeding:  on March 25, 2026, Enchanted Rock filed its reply brief; on 
March 26, 2026, Alliance to Save Energy filed comments; and on April 24, 2026, 
Earthjustice filed its reply brief. 
B. 
Paper Hearing on New Transmission Services 
 
On February 23, 2026, in Docket No. EL25-49-000, PJM and Indicated TOs each 
submitted an initial brief.  On March 25, 2026, response briefs were submitted by: 
Market Monitor; Geronimo Power, LLC; AEU/SEIA; Constellation; Eolian, Antora, 
Calibrant, Convergent, Mainspring, Verrus, and U.S. Energy Storage Coalition 
(collectively, Joint Co-Location Developers); Vistra; ODEC; Enchanted Rock; Indicated 
TOs; Industrials/Amtrak; NOVEC; DCC; and Alliance to Save Energy (Alliance).  On 
April 24, 2026, reply briefs were submitted by: Earthjustice; ODEC; PJM; Maryland 
OPC; Constellation; Indicated TOs; Joint Co-Location Developers; and 
Industrials/Amtrak.  On May 7, 2026, Enchanted Rock filed a motion for leave to answer 
and answer to PJM’s reply brief.  On May 11, 2026, Constellation filed a motion for 
leave to answer and answer to PJM’s and Indicated TOs’ reply briefs.  On May 21, 2026, 
Geronimo Power filed a motion for leave to answer and answer to PJM’s and Indicated 
TOs’ reply briefs.  On May 28, 2026, Indicated TOs filed a motion for leave to answer 
and answer to various reply briefs and Constellation’s May 11 answer.  
 
On December 29, 2025, American Clean Power Association filed a motion to 
intervene out of time in this proceeding.  On January 12, 2026, Vitol, Inc. filed a motion 
to intervene out of time in this proceeding.  On January 13, 2026, Pennsylvania Office of

Docket No. EL25-49-002, et al. 
- 16 - 
Consumer Advocate filed a motion to intervene out of time in this proceeding.  On 
January 16, 2026, Voltus, Inc. filed a motion to intervene out of time in this proceeding.  
On January 16, 2026, Emerald AI submitted comments out-of-time in Docket                              
No. EL25-49-000.  On January 26, 2026, Andrew D. Hinz filed a motion to intervene out 
of time and comments.  On March 20, 2026, Amtrak and AF&PA each filed a motion to 
intervene out of time in this proceeding.  On March 25, 2026, Calibrant, Convergent, 
Verrus, and U.S. Energy Storage Coalition filed a motion to intervene out of time in this 
proceeding. 
III. 
Procedural Matters 
 
Pursuant to Rule 214 of the Commission’s Rules of Practice and Procedure,                         
18 C.F.R. § 385.214 (2025), the notices of intervention and timely, unopposed motions to 
intervene in Docket Nos. ER26-1479-000 and EL25-49-000 serve to make the entities 
that filed them parties to these proceedings. 
 
Pursuant to Rule 214(d) of the Commission’s Rules of Practice and Procedure,               
18 C.F.R. § 385.214(d), we grant the late-filed motions to intervene in Docket                       
Nos. ER26-1479-000 and EL25-49-000 given these entities’ interests in the proceedings, 
the early stage of the proceedings, and the absence of undue prejudice or delay.  
Interventions in Docket No. EL25-49-000 are prospective only and such entities may not 
challenge the December Order. 
 
We note that Verrus did not intervene until after the December Order.  When, as 
here, late intervention is sought after the issuance of a dispositive order, the prejudice to 
other parties and burden upon the Commission of granting the late intervention may be 
substantial.  Thus, movants bear a higher burden to demonstrate good cause for granting 
such late intervention.37  Verrus indicates the proceeding has changed significantly with 
the initiation of the paper hearing proceeding.38  We do not find this explanation to be 
sufficient to meet the higher burden to show good cause for granting intervention 
following a dispositive order.  As discussed above, we grant Verrus’s motion to intervene 
as-of the filing date (March 25, 2026); however, we dismiss it to the extent Verrus joins 
Eolian and Antora in the request for clarification of the December Order.39 
 
37 PJM Interconnection, L.L.C., 167 FERC ¶ 61,209, at P 24 (2019); PJM 
Interconnection, L.L.C., 157 FERC ¶ 61,193, at P 10 (2016).   
38 Reply Brief of Joint Co-Location Developers and Motion to Intervene                        
Out-of-Tome of Calibrant, Convergent, U.S. Energy Storage Coalition, and Verrus at 6. 
39 PJM Interconnection, L.L.C., 157 FERC ¶ 61,193 at P 10; Pac. Gas & Elec. 
Co., 100 FERC ¶ 61,097, at P 5 (2002).

Docket No. EL25-49-002, et al. 
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Rule 213(a)(2) of the Commission’s Rules of Practice and Procedure, 18 C.F.R. 
§ 385.213(a)(2) (2025), prohibits an answer to a protest or answer unless otherwise 
ordered by the decisional authority.  We accept the answers submitted in Docket Nos. 
EL25-49-000 and in ER26-1479-000, as well as Constellation’s supplemental protest, 
because they have provided information that assisted us in our decision-making process. 
 
On February 2, 2026, Constellation filed a motion for leave and answer to Exelon 
and FirstEnergy’s request for rehearing.  On February 12, 2026, Exelon and FirstEnergy 
filed an answer in opposition to that motion.  On February 19, 2026, the Pennsylvania 
Office of Consumer Advocate filed a motion for leave to answer and answer in support of 
Industrials’ request for clarification or rehearing.40  On February 5 and March 9, 2026, 
respectively, Market Monitor and PJM filed answers and motions for leave to answer 
Constellation’s request for clarification or rehearing.  On February 20 and March 24, 
2026, Constellation filed motions for leave and answers to, respectively, Market 
Monitor’s and PJM’s answers.  Rule 713(d) of the Commission’s Rules of Practice and 
Procedure41 prohibits an answer to a request for rehearing.42  Accordingly, we deny these 
motions and we reject these answers filed by Constellation, Exelon and FirstEnergy, 
Pennsylvania Office of Consumer Advocate, Market Monitor, and PJM.43 
 
On February 9, 2026, Andrew Hinz filed a request for rehearing.  Pursuant to 
section 313(a) of the FPA,44 an aggrieved party must file an application for rehearing 
within 30 days after the issuance of the Commission’s order; in this case, that deadline is 
 
40 Pennsylvania Office of Consumer Advocate is not a party to this proceeding 
with respect to rehearing or clarification of the December Order and therefore may not 
file an answer to a request for rehearing or clarification.  
41 18 C.F.R. § 385.713(d)(1) (2025). 
42 Id. 
43 We note that the Pennsylvania Office of Consumer Advocate’s, Market 
Monitor’s, and PJM’s motions and answers responded to requests for clarification and, in 
the alternative, rehearing.  Because the Commission has discretion in how to characterize 
pleadings and examines the substance of pleadings, we construe these pleadings as 
ultimately functioning in substance to respond to requests for rehearing and thus treat 
them as such.  Sw. Power Pool, Inc., 182 FERC ¶ 61,083, at P 14 (2023).  
44 16 U.S.C. § 825l(a).

Docket No. EL25-49-002, et al. 
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no later than 5:00 PM U.S. Eastern Time45 on January 19, 2026.  Because the 30-day 
rehearing deadline is a statutory requirement, it cannot be waived or extended.46  
Therefore, we reject Andrew Hinz’s request for rehearing as untimely.   
IV. 
Requests for Rehearing and/or Clarification 
 
As discussed further below, we sustain our finding that the Tariff is 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.47  We also sustain our finding that the Tariff is unjust and 
unreasonable because it does not include transmission services that reflect the willingness 
and ability of an Eligible Customer taking service on behalf of a Co-Located Load to 
limit its energy withdrawals from the transmission system under certain conditions.48  As 
a replacement rate, we continue to direct PJM to establish the new transmission services 
discussed in the December Order.49   
 
We also set aside, in part, the December Order; we find that requiring Eligible 
Customers taking transmission service on behalf of load with BTMG to take NITS, 
without the option to instead take such alternative transmission services, would be unjust 
and unreasonable for the same reasons we made the same finding in the December Order 
with respect to Eligible Customers taking transmission service on behalf of Co-Located 
Load.  As a replacement rate, we direct PJM to revise its Tariff to extend the new 
transmission services to Eligible Customers taking service on behalf of load with BTMG. 
 
45 The Commission’s regular business hours end at 5:00 p.m., U.S. Eastern Time. 
18 C.F.R. § 375.101(c) (2025); 18 C.F.R. § 385.2003(c) (2025); FERC, eFiling User 
Guide (May 23, 2024), https://www.ferc.gov/media/efiling-user-guide. 
46 See, e.g., City of Campbell v. FERC, 770 F.2d 1180, 1183 (D.C. Cir. 1985) 
(“The 30-day time requirement of the [FPA] is as much a part of the jurisdictional 
threshold as the mandate to file for a rehearing.”); Bos. Gas Co. v. FERC, 575 F.2d 975, 
977-98, 979 (1st Cir. 1978) (describing identical rehearing provision of Natural Gas Act 
as “a tightly structured and formal provision” and holding that “[n]either the Commission 
or the courts are given any form of jurisdictional discretion”). 
47 December Order, 193 FERC ¶ 61,217 at P 159. 
48 Id. 
49 Id. P 160.

Docket No. EL25-49-002, et al. 
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We also continue to find that PJM’s retail BTMG netting rules are unjust and 
unreasonable.50  We continue to direct PJM to revise the Tariff’s retail BTMG netting 
rules.51  We also set aside, in part, the December Order; we find that it is just and 
reasonable to allow certain cogeneration Qualifying Facilities (QFs) that are Network 
Customers to be able to net by using BTMG, without being subject to the new materiality 
threshold, if they demonstrate that they are integrated with load such that, when their 
generating facility trips offline, the load follows. 
 
We also continue to direct PJM to clarify its interconnection procedures and 
agreements to ensure that it is clear to both new and existing Interconnection Customers 
how to interconnect in a Co-Location Arrangement.52 
A. 
Jurisdiction 
1. 
Sales for Resale in Interstate Commerce 
a. 
December Order 
 
In the December Order, the Commission found that several aspects of Co-Location 
Arrangements fall squarely within the jurisdiction of the states.  In particular, the 
Commission affirmed that “states have authority over their generation resource mix, 
including through their siting authority” and further explained that “[t]his authority 
means that which generating facilities are sited and allowed to serve Co-Located Load is 
also a question of state law.”53  In addition, the Commission “decline[d] in this 
proceeding to comprehensively address jurisdictional matters regarding the 
interconnection of retail loads served through a Co-Location Arrangement to the 
interstate transmission system.”54 
b. 
Request for Clarification and/or Rehearing 
 
Constellation requests that the Commission clarify that the Commission has 
jurisdiction over the wholesale sale of energy by a generator to a retail supplier even if 
the retail supplier then resells that energy to a Co-Located Load.  Constellation states that 
 
50 Id. P 186.  
51 Id. PP 221-224.  
52 Id. P 161. 
53 Id. P 169. 
54 Id. P 170.

Docket No. EL25-49-002, et al. 
- 20 - 
the December Order is unclear in that it states that “states have authority over their 
generation resource mix, including through their siting authority” and that “which 
generating facilities are sited and allowed to serve Co-Located Load is also a question of 
state law.”55  Constellation explains that generators often do not serve Co-Located Load 
directly and instead sell electricity at wholesale to an entity, such as a retail supplier, that 
will then engage in the ultimate retail sale to the Co-Located Load.  In such 
circumstances, Constellation argues that such sales for resale are exclusively within the 
Commission’s jurisdiction.56 
c. 
Determination 
 
In response to Constellation’s request for clarification or rehearing, we reiterate 
that, where a generator sells electricity at wholesale in interstate commerce to another 
entity that then resells that electricity at retail to a Co-Located Load, the generator’s sale 
for resale is exclusively within the Commission’s jurisdiction.57  Thus, state authority 
does not extend to the wholesale sale of energy by a generator to a retail supplier, 
regardless of the specific type of ultimate retail customer.  However, as the Commission 
explained in the December Order, both “which generating facilities are sited” and which 
generating facilities are “allowed to serve Co-Located Load” are “question[s] of state 
law.”58   
2. 
Retail Allocation of Commission-Jurisdictional Rates 
a. 
December Order 
 
In the December Order, the Commission held that “states have exclusive 
jurisdiction over how the costs assigned to Eligible Customers on behalf of Co-Located 
Load taking Commission-jurisdictional transmission services,” including the new 
transmission services, “are allocated to individual retail consumers that are Co-Located 
Load, just as states have exclusive jurisdiction over how to allocate the costs of all 
 
55 Constellation Request for Clarification or Rehearing at 6-7 (citing December 
Order, 193 FERC ¶ 61,217 at P 169) (emphasis in original).  
56 Id. at 6-7 (citing 16 U.S.C. § 824(b)(1); Orangeburg v. FERC, 862 F.3d 1071, 
1086-87 (D.C. Cir. 2017)). 
57 Orangeburg, 862 F.3d at 1086-87 (“FERC—not state commissions—has 
‘exclusive authority to regulate the . . . sale at wholesale of electric energy in interstate 
commerce.’”) (quoting New Eng. Power Co. v. N.H., 455 U.S. 331, 340 (1982)). 
58 December Order, 193 FERC ¶ 61,217 at P 169.

Docket No. EL25-49-002, et al. 
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Commission-jurisdictional rates (including for energy, capacity, and transmission) among 
retail customers, including allocating costs among different classes of retail customers.”59 
b. 
Request for Clarification and/or Rehearing 
 
Constellation requests that the Commission clarify that states do not have 
unlimited authority over how to allocate the costs of all Commission-jurisdictional rates 
and that they cannot use their authority over retail allocation to indirectly regulate the 
interconnection of generators serving Co-Located Load.60  For example, Constellation 
claims that a state cannot impose via the exercise of its jurisdiction over retail sales a 
requirement that attempts to prohibit a transaction that the Commission says is 
permitted.61  Constellation asserts that some utilities have asked their state commission 
for authority to condition retail service in the state on the load’s acceptance of a 
Transmission Security Agreement that calculates its security requirement based on a 
gross NITS rate despite the fact that the Commission has said that other rates must be 
made available.62  Constellation argues that the December Order is unclear in that it 
provides that “states have exclusive jurisdiction over how to allocate the costs of all 
Commission-jurisdictional rates (including for energy, capacity, and transmission) among 
retail customers, including allocating costs among different classes of retail customers.”63 
c. 
Determination 
 
In response to Constellation’s request, we deny clarification and sustain the 
December Order.  In the December Order, the Commission appropriately explained that 
“states have exclusive jurisdiction over how to allocate the costs of all                      
Commission-jurisdictional rates (including for energy, capacity, and transmission) among 
retail customers, including allocating costs among different classes of retail customers.”64  
On the other hand, we note that states “may not seek to achieve ends, however legitimate, 
through regulatory means that intrude on FERC’s authority over interstate wholesale 
 
59 Id. P 167. 
60 Constellation Request for Clarification or Rehearing at 8 (citing Hughes v. Talen 
Energy Mktg., LLC, 578 U.S. 150, 164-65 (2016); Nantahala Power & Light Co. v. 
Thornburg, 476 U.S. 953, 966 (1986)). 
61 Id. 
62 Id.   
63 Id. at 7 (citing December Order, 193 FERC ¶ 61,217 at P 167). 
64 December Order, 193 FERC ¶ 61,217 at P 167 (emphasis added).

Docket No. EL25-49-002, et al. 
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rates . . . .”65  While Constellation frames its request around the jurisdictional findings in 
the December Order, Constellation raises a specific matter that is not the subject of and is 
otherwise outside the scope of this proceeding, i.e., the terms of transmission security 
agreements.  We nonetheless reiterate that:  (1) Eligible Customers taking transmission 
service on behalf of Co-Located Load must have the option to take one of three 
transmission services, i.e., NITS or Interim NITS, FCD transmission service, or NFCD 
transmission service;66 and (2) while it remains just and reasonable for an Eligible 
Customer taking transmission service on behalf of Co-Located Load to take NITS 
charged on a gross demand basis,67 an Eligible Customer may instead choose to take 
another transmission service.68   
3. 
Retail BTMG 
a. 
December Order 
 
In the December Order, the Commission found that circumstances have changed 
since the Commission approved PJM’s retail BTMG netting rules such that these rules 
are no longer just and reasonable.  In particular, the Commission found that PJM’s 
existing retail BTMG netting rules do not limit the amount of qualifying load that a 
Network Customer may net by using BTMG and do not provide any protections against 
potential transmission and resource adequacy planning problems or against the costs of 
maintaining sufficient resources to serve these loads being shifted onto other customers.69  
The Commission concluded that PJM’s retail BTMG netting rules are no longer 
consistent with cost causation principles because large loads configured in a BTMG 
arrangement with significant generation will raise cost-shifting concerns compared to 
loads pursuing smaller amounts of netting.70  
 
65 Hughes v. Talen Energy Mktg., LLC, 578 U.S. 150, 164. 
66 December Order, 193 FERC ¶ 61,217 at P 193. 
67 Id. P 195. 
68 Id. P 199. 
69 Id. P 186. 
70 Id.

Docket No. EL25-49-002, et al. 
- 23 - 
b. 
Request for Clarification and/or Rehearing 
 
Industrials argue that the Commission failed to explain and justify its assertion of 
jurisdiction over “retail BTMG that merely offsets retail load.”71  Industrials contend that 
“retail BTMG [is not within] the Commission’s jurisdiction over the transmission of 
electric energy in interstate commerce” because “[b]y definition, BTMG is produced by a 
generation unit ‘that delivers energy to load without using the Transmission System.’”72  
Industrials assert that the Commission’s finding “necessarily entails piercing the retail 
meter veil, which serves as the bright-line boundary of the Commission’s statutory 
authority.”73  Industrials further maintain that the Commission failed to provide a                 
well-reasoned basis for the assertion of jurisdiction over the configurations of retail 
customers whose BTMG is not selling wholesale power and is not using the transmission 
system.74  Industrials argue that, here, “retail BTMG involves neither jurisdictional sales 
nor jurisdictional transmission.”75 
c. 
Determination 
 
We disagree with Industrials that the BTMG netting rules are outside of the 
Commission’s jurisdiction.  Industrials misunderstand the December Order as targeting 
retail sales from BTMG or the delivery of energy from BTMG to load, but this is not the 
case.  The BTMG netting rules instead allow PJM to calculate the charges for 
 
71 Industrials Request for Clarification or Rehearing at 39.  
72 Id. at 40 (citing PJM, Intra-PJM Tariffs, OATT, § I.1 (Definitions – A-B) 
(22.0.0)). 
73 Id. 
74 Id. at 40-41 (citing Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 475 F.3d 
1277, 1280 (D.C. Cir. 2007); Detroit Edison Co. v. FERC, 334 F.3d 48, 53 (D.C. Cir. 
2003)).  
75 Id. at 41-42.

Docket No. EL25-49-002, et al. 
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transmission service in interstate commerce.76  The calculation of such transmission 
charges is squarely within the Commission’s jurisdiction under the FPA.77 
4. 
Retail Backup Service 
a. 
December Order 
 
In the December Order, the Commission required that PJM modify its Tariff to 
require that an Eligible Customer taking transmission service on behalf of a Co-Located 
Load take one of three transmission services:  (1) NITS or Interim NITS; (2) FCD 
transmission service; or (3) NFCD transmission service.78 
b. 
Request for Rehearing 
 
Exelon and FirstEnergy contend that the Commission’s new FCD and NFCD 
transmission services infringe on state retail authority, asserting that the states, not the 
Commission, have jurisdiction to decide when and in what circumstances retail load will 
be curtailed, and how utilities should charge and treat retail customers in those 
circumstances.79  Exelon and FirstEnergy claim that, for example, states might require the 
provision of backup service to retail customers who lost supply from their contracted 
supplier, would regulate the distribution system costs associated with such service that 
would be charged to the retail customer, and would regulate the costs and terms of the 
backup service.80  Exelon and FirstEnergy assert that the Commission’s order appears to 
create a new federal construct because it defines the extent and terms of backup service to 
 
76 PJM, Intra-PJM Tariffs, OATT, § III, § 34.2 (Netting of Behind the Meter 
Generation) (0.0.0); see December Order, 193 FERC ¶ 61,217 at P 7 (“[T]he Tariff 
allows load serving entities . . . that provide service to loads with qualifying BTMG to 
reduce their costs by netting output from BTMG in the calculation of their peak demand 
for the purpose of determining NITS charges.”) (emphasis added). 
77 Orangeburg, 862 F.3d at 1086-87 (“FERC—not state commissions—has 
‘exclusive authority to regulate the transmission . . . of electric energy in interstate 
commerce.’”) (quoting New Eng. Power Co., 455 U.S. at 340); Calpine Corp. v. FERC, 
702 F.3d 41, 50 (D.C. Cir. 2012) (“[T]he regulation of transmission charges is 
undoubtedly within FERC’s jurisdiction . . . .”). 
78 December Order, 193 FERC ¶ 61,217 at P 193. 
79 Exelon and FirstEnergy Request for Rehearing at 53.  
80 Id.

Docket No. EL25-49-002, et al. 
- 25 - 
retail customers who lose their contracted retail power supplier.81  Exelon and 
FirstEnergy argue that the Commission’s new transmission services lack the limitation in 
the Commission’s wholesale demand response programs, which allow states to prohibit 
retail consumers from participating in wholesale demand response.82 
c. 
Determination 
 
We are not persuaded by Exelon and FirstEnergy’s assertions that FCD and NFCD 
transmission services infringe on state retail authority.  In the December Order, the 
Commission held that Eligible Customers taking transmission service on behalf of a              
Co-Located Load must have the option to take one of three transmission services:  
(1) NITS or Interim NITS; (2) FCD transmission service; or (3) NFCD transmission 
service.83  Exelon and FirstEnergy do not explain how FCD and NFCD transmission 
services define the extent and terms of backup service to retail customers who lose their 
contracted power supplier and cite no specific aspect of the December Order that does 
so.84  As such, we find that Exelon and FirstEnergy fail to demonstrate that the 
Commission’s replacement rate regulates the terms of retail service.85  
 
81 Id. at 53, 55. 
82 Id. at 54 (citing FERC v. EPSA, 577 U.S. 260, 275 (2016)). 
83 December Order, 193 FERC ¶ 61,217 at P 193. 
84 FPA section 313(a) requires that an “application for rehearing shall set forth 
specifically” its grounds. 16 U.S.C. § 825l(a) (emphasis added).  We follow Commission 
practice, with which courts have agreed, and reject arguments, like this one, on rehearing 
lacking sufficient specificity.  PJM Interconnection, L.L.C., 171 FERC ¶ 61,040, at P 22 
(2020); see also Ind. Util. Regul. Comm’n v. FERC, 668 F.3d 735, 736 (D.C. Cir. 2012); 
LA Storage, LLC, 182 FERC ¶ 61,026, at P 25 & n.75 (2023).   
85 Exelon and FirstEnergy argue that the Commission’s new transmission services 
lack the limitation in the Commission’s wholesale demand response programs, which 
allows states to prohibit retail consumers from participating in wholesale demand 
response.  Exelon and FirstEnergy Request for Rehearing at 54 (citing FERC v. EPSA, 
577 U.S. at 275).  The considerations that led the Commission to include that “opt-out” in 
the rulemakings that led to Order Nos. 719 and 745, such as a confluence of federal and 
state jurisdiction with respect to demand response, are not present in this proceeding.  
Moreover, the Commission was not required to include the “opt-out” even in those 
rulemakings.  See Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 964 F.3d 1177, 1187 
(D.C. Cir. 2020) (“But because FERC has the exclusive authority to determine who may

Docket No. EL25-49-002, et al. 
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B. 
Show Cause Findings 
1. 
Overview, Transmission Service, Regulation and Black Start 
a. 
December Order 
 
As relevant here, the Commission found in the December Order that the Tariff is 
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.  The Commission also found that the 
Tariff is unjust and unreasonable because it does not include transmission services that 
reflect Eligible Customers taking service on behalf of Co-Located Loads that are willing 
and able to limit their energy withdrawals from the transmission system under certain 
conditions.86   
b. 
Request for Rehearing 
 
Exelon and FirstEnergy argue that the Commission did not meet its burden under 
FPA section 206 to show that the existing PJM Tariff is unjust and unreasonable.87  
Exelon and FirstEnergy argue that the Commission provides no evidentiary support for 
its finding that the Tariff is 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.88  
Exelon and FirstEnergy allege that the Tariff already has provisions explaining how to 
serve load in PJM and the Commission does not even mention them.89 
 
Exelon and FirstEnergy dispute that the Constellation Complaint supports the 
Commission’s finding of uncertainty.90  Exelon and FirstEnergy contend that the actual 
 
participate in the wholesale markets, the Supremacy Clause—not Order No. 841—
requires that States not interfere.”). 
86 December Order, 193 FERC ¶ 61,217 at P 177. 
87 Exelon and FirstEnergy Request for Rehearing at 13. 
88 Id. at 14 (citing December Order, 193 FERC ¶ 61,217 at P 175). 
89 Id. at 15 (discussing and citing Tariff provisions). 
90 Id.

Docket No. EL25-49-002, et al. 
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situation described in the Constellation Complaint giving rise to the purposed uncertainty 
revealed that “any delay resulted from a decision made by Constellation in its attempt to 
bypass retail service requirements and to obtain service in violation of Illinois law.”91  
Exelon and FirstEnergy argue that, if any clarification was necessary, the Commission 
has now clarified that Co-Location Arrangements must be properly metered and 
designate and involve transmission service to an Eligible Customer.  Exelon and 
FirstEnergy allege that service can proceed in an orderly fashion.  Exelon and 
FirstEnergy argue that the Commission ignored record evidence that customers’ load 
service requests proceed on a timely basis when customers take service through an 
Eligible Customer.92  Exelon and FirstEnergy also maintain that Talen Energy’s recent 
changes to its Co-Location Arrangement with Susquehanna Nuclear, LLC show that the 
Tariff works.93 
 
Exelon and FirstEnergy next challenge the Commission’s finding that the Tariff is 
unjust and unreasonable because it does not include transmission services that reflect that 
an Eligible Customer taking service on behalf of a Co-Located Load that is willing and 
able to limit its energy withdrawals from the transmission system under certain 
conditions.94  Exelon and FirstEnergy allege that there is no evidence that the cost of 
NITS deters service or impacts data center development.  Exelon and FirstEnergy also 
argue that there is no evidence to support the Commission’s statement that requiring 
NITS could necessitate inefficient and costly transmission buildout and costs paid by 
transmission customers that may not be necessary if Eligible Customers taking 
transmission service on behalf of Co-Located Loads are willing to limit their energy 
withdrawals and take a transmission service that requires fewer Network Upgrades.95  
Exelon and FirstEnergy maintain that charging load on a contract demand basis does not 
change the physical and engineering impacts of the load.96  Exelon and FirstEnergy 
acknowledge that installing systems to limit grid usage might change system impacts and 
the need for upgrades, but there is nothing in the record demonstrating that such systems 
are more beneficial for Co-Located Load than other loads or that such systems warrant 
 
91 Id. at 15-16 (citing Constellation, Docket No. EL25-20-000, Complaint, Ex. 5, 
attach. 1). 
92 Id. at 17. 
93 Id. at 17-18 (citing PJM, Docket No. ER24-2172-000, Amended ISA, attach. A, 
Schedule F, Part F.4 (filed June 3, 2024)). 
94 Id. at 18 (citing December Order, 193 FERC ¶ 61,217 at P 159). 
95 Id. at 19 (citing December Order, 193 FERC ¶ 61,217 at P 199). 
96 Id.

Docket No. EL25-49-002, et al. 
- 28 - 
the use of different ratemaking principles for Co-Located Load as compared to other 
loads.97  Exelon and FirstEnergy argue that system impacts may be reduced when a load 
is located near a generator, but that is true whether the load contracts with remote 
generation or an abutting generator.  Exelon and FirstEnergy assert that the study process 
can determine how to site to reduce transmission upgrades for the customer using the 
customer’s gross load.  
 
Exelon and FirstEnergy argue that the Commission provides no support for its 
statement 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.98  Exelon and FirstEnergy assert that the transmission 
system is affected even when no net power is withdrawn from the system.99  Exelon and 
FirstEnergy contend that the Commission endorses an unsound approach by suggesting 
that loads that do not withdraw from the system can be interconnected on a fast track 
without studying physical impacts. 
 
Exelon and FirstEnergy highlight the Commission’s statement that, while the 
Commission finds that NITS charged on a gross demand basis is one just and reasonable 
transmission service option for Eligible Customer taking transmission service on behalf 
of Co-Located Loads, it is not the only option.100  Exelon and FirstEnergy state that the 
Commission itself acknowledges that the existing service options are feasible and just 
and reasonable, but the Commission merely wants more options.  Exelon and FirstEnergy 
argue that when the Commission finds a tariff not unjust and unreasonable under the first 
prong of FPA section 206, as it suggests here, the Commission does not need to set a 
remedy.  
 
Exelon and FirstEnergy disagree with the Commission’s assessment that                    
Co-Located Loads merit a different rate based on the combination of transmission system 
burdens and benefits.  Exelon and FirstEnergy first state that Co-Located Loads benefit 
from regulation and black start, as the Commission recognized.101  Exelon and 
FirstEnergy argue that transmission interconnections provide an avenue for data center 
loads to readily acquire back-up power when co-located generators are not available.  
 
97 Id. at 19-20. 
98 Id. at 20 (citing December Order, 193 FERC ¶ 61,217 at P 205). 
99 Id. at 21. 
100 Id. at 22 (citing December Order, 193 FERC ¶ 61,217 at P 195). 
101 Id. at 30 (citing December Order, 193 FERC ¶ 61,217 at PP 209, 219).

Docket No. EL25-49-002, et al. 
- 29 - 
Exelon and FirstEnergy argue that, based solely on these uses of the transmission system, 
Co-Located Loads have no greater claim to preferential rates than other similarly situated 
transmission customers.  Exelon and FirstEnergy argue that the Commission failed to 
consider the many advantages to Co-Located Loads when they connect to the 
transmission system.  For example, Exelon and FirstEnergy assert that, if the project were 
islanded instead of grid connected, all back-up generation would sit idled when not 
needed, forgoing significant revenues from selling surplus power into the wholesale 
market.  Exelon and FirstEnergy also allege that it is very difficult to supply islanded 
generation with black start and regulation.102 
 
Exelon and FirstEnergy argue that the Commission failed to respond to arguments 
about the unique aspects of co-location with nuclear plants.  Exelon and FirstEnergy state 
that a nuclear facility must be interconnected to the grid as a Nuclear Regulatory 
Commission licensing obligation, and thus a Co-Location Arrangement with a nuclear 
unit depends on the grid.103  Exelon and FirstEnergy assert that, in a Co-Location 
Arrangement with a nuclear unit, Co-Located Load depends on services such as 
regulation, voltage support, black start, and other ancillary services delivered over the 
grid all the time because nuclear units cannot provide these services.104 
c. 
Determination 
 
On rehearing, we sustain the Commission’s finding in the December Order that 
the Tariff is unjust and unreasonable.105  First, we continue to find that the Tariff 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 
 
102 Id. at 31. 
103 Id. at 32-33 (citing Exelon, Docket No. EL25-20-000, Comments, attach. 1,               
¶¶ 11-13, 16)). 
104 Id. at 32 (citing Exelon, Docket No. EL25-20-000, Comments, attach. 1,                       
¶¶ 14-19)). 
105 December Order, 193 FERC ¶ 61,217 at PP 175-177.  As discussed in the 
December Order, we continue to find the Tariff also unjust and unreasonable in 
additional related ways—for example, we continue to find that the Tariff is unjust and 
unreasonable because it does not address charges for black start and regulation service to 
Eligible Customers taking transmission service on behalf of Co-Located Load.  Id. P 159.  
We do not interpret Exelon and FirstEnergy, however, to be disputing this finding.  
Separate portions of this order address our findings in this proceeding that additional 
aspects of the Tariff are unjust and unreasonable.

Docket No. EL25-49-002, et al. 
- 30 - 
and Eligible Customers taking transmission service on behalf of Co-Located Load.106  
Second, we continue to find that the Tariff does not include transmission services that 
reflect Eligible Customers taking service on behalf of Co-Located Loads that are willing 
and able to limit their energy withdrawals from the transmission system under certain 
conditions.107 
 
Substantial evidence supports the Commission’s finding that the Tariff lacks 
sufficient clarity as to the rules governing Interconnection Customers serving Co-Located 
Load and Eligible Customers taking transmission service on behalf of Co-Located 
Load.108  There is significant support in the record for this finding.109  In particular, PJM 
recognizes that its Tariff lacks sufficient clarity in this area.110  We also find persuasive 
the comments in the record from a range of stakeholders reflecting the uncertainty facing 
entities seeking to effectuate Co-location Arrangements within PJM.111   
 
106 Id. P 175.  
107 Id. P 177.  
108 Id. PP 175-176. 
109 Id. P 176 n.376. 
110 PJM March 24, 2025 Response at 32 (noting that its “Tariff provisions d[o] not 
contemplate the type of arrangements at issue in this docket”); id. at 35 (“The extent to 
which netting [rules under the Tariff] could . . . apply to co-located data center load is not 
clear at this time.”); see also Vistra April 23, 2025 Reply Comments at 11 (arguing that 
PJM has “effectively conceded” that the Tariff does not contain sufficient clarity). 
111 See Constellation May 8, 2025 Answer at 3-9 (collecting record support and 
concluding “[i]n sum, the record in this proceeding unequivocally supports the . . . 
finding that the PJM Tariff lacks clear co-location rules”); AEU April 23, 2025 Reply 
Comments at 19 (“Loads and generators pursuing [C]o-[L]ocation [A]rrangements need 
clarity as to how these arrangements will be studied, and how those studies will be 
evaluated.  There must be a level of uniformity and detail outlining study requirements to 
ensure regulatory certainty for large loads and new generation and storage resources 
seeking to serve large loads.  This level of uniformity is currently lacking in PJM’s 
interconnection procedures and cost allocation methodology . . . .”); Electric Power 
Supply Association (EPSA)/PJM Power Providers Group (P3) April 23, 2025 Reply 
Comments at 2 (“EPSA and P3 agree with the Commission that PJM needs to establish 
tariff provisions and rules to accommodate the array of [C]o-[L]ocated [L]oad 
arrangements that will facilitate the timely and effective integration of large loads 
locating in the region.”); DCC April 23, 2025 Reply Comments at 7 (“. . . [T]he 
Commission should direct PJM to develop clear, enforceable tariff language that affirms

Docket No. EL25-49-002, et al. 
- 31 - 
 
Further, there has been significant confusion and dispute over what rules govern 
Co-Location Arrangements in PJM.  As the Commission found in the December Order, 
the absence of clear tariff provisions creates uncertainty that has resulted in disparate 
treatment of potential Co-Location Arrangements in PJM, where transmission owners 
have taken different approaches to performing the necessary steps that apply to 
Interconnection Customers seeking to serve Co-Located Load through a Co-Location 
Arrangement, leading to no consistent understanding of entities’ responsibilities with 
respect to their planned Co-Location Arrangements.112  Further, in 2024, PJM developed 
a now-rescinded “Guidance Document,” which included non-binding guidance for 
generators and loads seeking to enter into Co-Location Arrangements113—further 
suggesting that PJM’s existing Tariff did not provide sufficient clarity resulting in a lack 
of consistent understanding among stakeholders.  Indeed, parties have raised varying 
interpretations of the rules that apply to Co-Location Arrangements across Commission 
proceedings.114 
 
the permissibility of multiple co-location configurations, including those where load is 
served directly from a generation resource located on or near the same site.  Tariff clarity 
is essential to reduce unnecessary disputes, avoid case-by-case confusion, and enable 
transmission providers to process interconnection and load addition requests efficiently 
and predictably.”). 
112 December Order, 193 FERC ¶ 61,217 at P 175 & n.375 (citing Constellation, 
Complaint, Docket No. EL25-20-000 (filed Nov. 22, 2024); Baltimore Gas & Electric 
Company and PECO Energy Company, Petition for Declaratory Order, Docket                        
No. EL24-149-000 (filed Sept. 30, 2024); Constellation April 23, 2025 Reply Comments 
at 4 n.4).  
113 PJM, PJM Guidance on Co-Located Load (Mar. 22, 2024) (updated Apr. 17, 
2024), https://www.pjm.com/-/media/DotCom/markets-ops/rpm/rpm-auction-info/pjm-
guidance-on-co-located-load.pdf. 
114 For instance, an amended ISA to which PPL was a party stated that “The                  
Co-Located Load is not Network Load, and it is intended that the Co-Located Load will 
never consume capacity and/or energy from the PJM Transmission System.”  PJM 
Interconnection, L.L.C. (Susquehanna), Amended Susquehanna ISA, Docket                               
No. ER24-2172, Schedule F, Part F (filed June 3, 2024); see also, e.g., PJM 
Interconnection, L.L.C., 189 FERC ¶ 61,078, at PP 14, 26 (2024).  On the other hand, 
there are allegations in the record that Exelon has delayed work on Constellation’s 
requests to co-locate load with certain of its generators due to Exelon’s concerns that 
such requests are not allowed under the Tariff without arranging for wholesale

Docket No. EL25-49-002, et al. 
- 32 - 
 
In fact, based on our review of the Tariff, the Tariff indeed does not contain 
provisions specifying the rules governing Co-Location Arrangements.115  For instance, 
the Tariff lacks provisions specifying:  the terms and conditions for Interconnection 
Customers seeking to use their generators to serve Co-Located Load;116 that an 
Interconnection Customer who will use its generator to serve Co-Located Load must 
designate an Eligible Customer who will take transmission service on behalf of the                  
Co-Located Load;117 the rules governing transmission service—including the rates, 
terms, and conditions of that service—taken by an Eligible Customer on behalf of Co-
Located Load;118 and the charges for black start and regulation service to Eligible 
Customers taking transmission service on behalf of Co-Located Load.119  In sum, due to 
the absence of these provisions, the Tariff lacks sufficiently clear answers to important 
questions about how to effectuate Co-Location Arrangements.   
 
The finding that the Tariff is unjust and unreasonable due to the lack of sufficient 
clarity is bolstered by several factors.  First, the lack of sufficient clarity leaves entities 
unable to determine what steps they can or must take to effectuate or administer                        
Co-Location Arrangements of various configurations.120  Interconnection Customers 
seeking to use their generators to serve Co-Located Load have no means of knowing their 
responsibilities with respect to serving Co-Location Arrangements and the terms and 
conditions that apply to these arrangements.121  Without an Eligible Customer designated 
to take transmission service on behalf of a Co-Located Load, the Tariff lacks a 
mechanism to address and ensure proper charges for situations in which a Co-Located 
Load withdraws energy from the transmission system.122  Second, an absence of 
 
transmission or retail distribution service.  February Order, 190 FERC ¶ 61,115 at PP 51, 
75. 
115 December Order, 193 FERC ¶ 61,217 at P 175.  
116 Id. P 176.   
117 Id.  
118 Id.; see also, e.g., id. P 175. 
119 Id. P 177; see also id. PP 159, 181-185. 
120 Id. P 175.  
121 Id. P 176.  
122 Id.  Indeed, Exelon and FirstEnergy concede that they agree that “[a]n Eligible 
Customer serving a co-located load must be designated because it is the Eligible

Docket No. EL25-49-002, et al. 
- 33 - 
sufficient clarity in these circumstances creates regulatory uncertainty, thus undermining 
a “central purpose” of the FPA—“predictability.”123  Third, the lack of sufficient clarity 
leads here to the potential for undue discrimination, preferential treatment, or otherwise 
unjustifiable disparate conduct.  As discussed above, disparate treatment has occurred in 
PJM, where transmission owners have taken different approaches to addressing                        
Co-Location Arrangements.124  Finally, the lack of sufficient clarity introduces the risk 
that costs related to Co-Location Arrangements may not be allocated consistent with cost 
causation principles because, for instance, Eligible Customers taking transmission service 
on behalf of Co-Located Load could benefit from regulation and black start services 
without contributing to cost recovery for such services, thus risking that costs may be 
allocated entirely to other transmission customers and passed through to residential 
customers, among others.125  In total, these factors are magnified by the facts that                   
Co-Location Arrangements are becoming increasingly common in PJM, entities continue 
to raise issues involving Co-Location Arrangements with the Commission,126 and                  
Co-Location Arrangements may include large amounts of load and generation.  Given 
these ramifications and consistent with precedent,127 the Commission appropriately found 
that the lack of sufficient clarity in the Tariff has rendered it unjust and unreasonable.  
 
Customer that seeks and obtains transmission service and pays for it.”  Exelon and 
FirstEnergy Request for Rehearing at 2.  
123 PJM Power Providers Grp. v. FERC, 96 F.4th 390, 401-02 (3d Cir. 2024) 
(describing a central purpose of the filed rate doctrine:  predictability).  Ensuring 
predictability ultimately supports a primary purpose of the FPA, “encourag[ing] the 
orderly development of plentiful supplies of electricity . . . at reasonable prices.”  Pub. 
Utils. Comm’n of Cal. v. FERC, 367 F.3d 925, 929 (D.C. Cir. 2004) (quoting NAACP v. 
FPC, 425 U.S. 662, 670 (1976); see EPSA, 577 U.S. at 290 (“The statute aims to protect 
‘against excessive prices’ and ensure effective transmission of electric power.” (citations 
omitted)).   
124 December Order, 193 FERC ¶ 61,217 at P 175; February Order, 190 FERC 
¶ 61,115 at P 75. 
125 December Order, 193 FERC ¶ 61,217 at P 177; see also id. PP 181-185.  
126 Id. P 4.  
127 E.g., Invenergy Transmission LLC v. Midcontinent Indep. Sys. Operator, Inc., 
193 FERC ¶ 61,033, at P 53 (2025) (finding tariff unjust and unreasonable because it did 
not address when and how certain transmission projects are incorporated into a 
transmission planning model and because existing provisions lacked “sufficient 
specificity and certainty”); PJM Interconnection, L.L.C., 167 FERC ¶ 61,030, at PP 22, 
41, 59 (2019) (“[W]e find that the PJM Operating Agreement is unjust and unreasonable

Docket No. EL25-49-002, et al. 
- 34 - 
 
Notwithstanding the Commission’s findings, Exelon and FirstEnergy argue that 
because the Tariff provides for NITS and point-to-point service (PTPS)—with terms 
governing them—“[t]here is no inability to determine how to serve [co-located] load in 
PJM.”128  Yet, the existence of provisions governing NITS and PTPS does not undermine 
our findings that the Tariff both lacks sufficient clarity and does not contain provisions 
specifying the rules governing Co-Location Arrangements.  The applicability, operation, 
and/or interpretation of the cited general provisions (among others) with respect to 
Eligible Customers taking transmission services on behalf of Co-Located Load and                
Co-Location Arrangements are the issues that, in part, give rise to the lack of sufficient 
clarity we target here.   
 
Next, Exelon and FirstEnergy respond to the Commission’s citation of the 
Constellation Complaint by blaming “any delay” giving rise to uncertainty on 
Constellation.129  But this response misunderstands the Commission’s reasoning.  The 
Commission cited the Constellation Complaint as one piece of evidence to demonstrate 
that there is “no consistent understanding” of the rules governing Co-Location 
Arrangements.130   
 
Similarly, Exelon and FirstEnergy allege that “in 2025, [Commonwealth Edison 
Company] received more than 25 customer service applications for large load service, 
representing new load in excess of 20 GW” and “[t]here is no suggestion in the record 
that any customer is encountering problems with those requests.”131  Beyond the fact 
there is no representation that any of those applications relate to Co-Located Load, this 
limited set of applications before a single Transmission Owner does not demonstrate 
 
because it fails to provide a sufficient level of clarity regarding the permissible 
components of energy market cost-based offers”); N.Y. Indep Sys. Operator, Inc.,                  
162 FERC ¶ 61,107, at PP 160, 173 (2018) (“We find this difference in definitions to be 
unclear and, therefore, unjust and unreasonable”); Dominion Energy Mktg., Inc., v. ISO 
New Eng. Inc., 155 FERC ¶ 61,121, at P 17 (2016) (“We find that [the] existing Tariff is 
unclear as to whether new incremental capacity and existing capacity at the same 
generating station must submit a composite offer in order to participate in [a capacity 
auction].  As a result of this lack of clarity, the Tariff fails to provide adequate notice of 
what the requirement is and, thus, we find the Tariff is unjust and unreasonable.”). 
128 Exelon and FirstEnergy Request for Rehearing at 14-15. 
129 Id. at 15-16. 
130 December Order, 193 FERC ¶ 61,217 at P 175. 
131 Exelon and FirstEnergy Request for Rehearing at 17.

Docket No. EL25-49-002, et al. 
- 35 - 
sufficient clarity even if those requests “proceed on a timely basis.”132  As explained 
above, the Commission continues to be concerned about disparate treatment by different 
Transmission Owners in this context.133 
 
Exelon and FirstEnergy also state that in one proceeding pertaining to Co-Located 
Load, a load and generator entered into a “front-of-the-meter” arrangement and thus 
“conceded that PJM Network Service works . . . and is a service upon which all 
customers may rely.”134  A decision in one proceeding to abandon a Co-Location 
Arrangement does not undermine the Commission’s finding that there is a lack of 
sufficient clarity related to Co-Location Arrangements writ large (and, in fact, might 
support it).   
 
Finally, Exelon and FirstEnergy contend that “[t]o the extent clarification was 
needed, the Commission has now clarified . . . that these arrangements must be properly 
metered and must designate and involve transmission service to an Eligible Customer.”135  
This argument is misplaced.  Exelon and FirstEnergy’s argument that the replacement 
rate should be narrower—that only part of it would be sufficient—should be directed not 
to the finding that the Tariff is unjust and unreasonable but to the determination of a just 
and reasonable replacement rate.  Further, the portions of the replacement rate that 
Exelon and FirstEnergy reference—requiring proper metering and involving transmission 
service to an Eligible Customer—do not resolve the Commission’s concerns as to a lack 
of sufficient clarity in the Tariff.  For example, the Commission found a lack of sufficient 
clarity as to the terms and conditions for Interconnection Customers seeking to use their 
generators to serve Co-Located Load.136  
 
We also continue to find that the Tariff is unjust and unreasonable because it does 
not include transmission services that reflect Eligible Customers taking service on behalf 
of Co-Located Loads that are willing and able to limit their energy withdrawals from the 
transmission system under certain conditions.137  Requiring Eligible Customers taking 
 
132 Id. 
133 See supra notes 114, 126. 
134 Exelon and FirstEnergy Request for Rehearing at 17-18 (discussing the 
proceedings in Docket Nos. ER24-2172-000 and ER24-2171-001).  
135 Id. at 16-17.  
136 December Order, 193 FERC ¶ 61,217 at P 176. 
137 Id. P 177; see also S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 64-68 (D.C. 
Cir. 2014) (explaining that to find a practice unjust and unreasonable, the Commission 
need not rely on “empirical evidence” and can rely on “reasonable economic

Docket No. EL25-49-002, et al. 
- 36 - 
transmission service on behalf of Co-Located Load to take NITS, without the option to 
instead take such alternative transmission services, is economically inefficient.  Here, the 
record demonstrates that some Eligible Customers taking service on behalf of                      
Co-Located Loads are willing and able to limit their energy withdrawals.  With only the 
current services offered, having found that Eligible Customers taking NITS will be 
charged based on gross load, prospective Eligible Customers taking transmission service 
on behalf of Co-Located Load would have to take a transmission service that does not 
reflect the load’s willingness and ability to limit use of the transmission system—which 
is an inefficient result.  The Commission has long recognized that providing 
differentiated service options can produce more efficient results because customers can 
choose the service that is most closely tailored to their specific needs, rather than a             
one-service-fits-all approach.138  Requiring Eligible Customers taking service on behalf 
of Co-Located Loads to take NITS creates an unacceptable risk of more costly Network 
Upgrades that would be unnecessary if such Eligible Customers were willing and 
permitted to take a transmission service that reflects Co-Located Loads that are willing 
 
propositions” “likely enough to be within the Commission’s authority” and noting that 
the use of words such as “might, may, or could” does not make its determination legally 
deficient (internal quotation marks omitted)). 
138 See, e.g., Integration of Variable Energy Res., Order No. 764, 139 FERC 
¶ 61,246, at PP 2, 22, order on reh’g & clarification, Order No. 764-A, 141 FERC                    
¶ 61,232 (2012), order on clarification & reh’g, Order No. 764-B, 144 FERC ¶ 61,222 
(2013) (explaining that the Commission sought “to provide all transmission customers 
the option of using more frequent transmission scheduling intervals within each operating 
hour, at 15-minute intervals,” which will allow them “the flexibility to adjust their 
transmission schedules, thus limiting their exposure to imbalance charges” and lead to 
“more efficient utilization of transmission and generation resources”); Standardization of 
Generator Interconnection Agreements & Procs., Order No. 2003, 104 FERC ¶ 61,103 
(2003), order on reh’g, Order No. 2003-A, 106 FERC ¶ 61,220, at P 534, order on reh’g, 
Order No. 2003-B, 109 FERC ¶ 61,287 (2004), order on reh’g, Order No. 2003-C,                
111 FERC ¶ 61,401 (2005), aff’d sub nom. Nat’l Ass’n of Regul. Util. Comm’rs v. FERC,            
475 F.3d 1277 (D.C. Cir. 2007) (explaining that “an Interconnection Customer that elects 
to be studied for Network Resource Interconnection Service has the option also to be 
studied for Energy Resource Interconnection Service and proceed with Network 
Resource Interconnection Service or a lower level Interconnection Service whereby only 
certain Network Upgrades will be completed” and finding that “[t]his option thus allows 
the Interconnection Customer to avoid having to fund Network Upgrades that it does not 
need”).

Docket No. EL25-49-002, et al. 
- 37 - 
and able to limit their energy withdrawals.139  We further reiterate that there is support in 
the record for the foregoing analysis.140 
 
On rehearing, Exelon and FirstEnergy dispute the Commission’s finding that the 
Tariff is 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.141  First, Exelon and FirstEnergy argue that “there is no 
evidence that the cost of paying for Network Service deters service or has any impact 
whatsoever on development of data centers” because “data center development interest in 
PJM is overwhelming.”142  But the Commission was not required to show that its FPA 
section 206 step one findings would have a particular effect on data centers.  Instead, as 
explained in the prior paragraph, the Commission’s findings relate to economic and other 
harms from a lack of transmission services that reflect Eligible Customers taking service 
on behalf of Co-Located Loads that are willing and able to limit their energy withdrawals 
from the transmission system.143  In any event, we continue to reason that requiring 
Eligible Customers taking transmission service on behalf of Co-Located Load to take 
NITS does have a negative impact relative to transmission services that reflect these 
loads’ willingness and ability to limit energy withdrawals.  These negative impacts could 
include unnecessary Network Upgrade costs, which cause an unjust and unreasonable 
increase in transmission rates.  The assertion that “development interest” in data centers 
may currently be high, or will remain high if Eligible Customers taking transmission 
service on behalf of Co-Located Loads that are willing and able to limit their withdrawals 
from the transmission system are required to take NITS on a gross basis, does not address 
the counterfactual at issue (i.e., requiring Eligible Customers taking transmission service 
on behalf of Co-Located Load to take NITS relative to transmission services that reflect 
these loads’ willingness and ability to limit energy withdrawals).  
 
Second, Exelon and FirstEnergy contend that the Commission has no evidence144 
to support the risk of “costly and inefficient transmission system buildout” under NITS 
 
139 December Order, 193 FERC ¶ 61,217 at PP 177, 199, 205.  
140 Id. PP 199 & n.423, 205, 434; see also PP 160, 177-178.  
141 Exelon and FirstEnergy Request for Rehearing at 18. 
142 Id. at 18-19.  
143 December Order, 193 FERC ¶ 61,217 at P 177. 
144 Exelon and FirstEnergy Request for Rehearing at 19-20 (citing, among other 
things, December Order, 193 FERC ¶ 61,217 at P 199).

Docket No. EL25-49-002, et al. 
- 38 - 
compared to “fewer Network Upgrades” and “lower Network Upgrade costs” under an 
alternative service.145  To the contrary, the Commission has provided a robust rationale 
for this risk, as explained above.  Exelon and FirstEnergy state that “network studies are 
based on physics and engineering” so NITS cannot “impose[] unnecessary transmission 
upgrade costs.”146  We agree with the premise that studies are based on physics and 
engineering, but not the conclusion.  Many Network Upgrades are caused by the amount 
of MW flow on the transmission system but certain Network Upgrades are not (e.g., they 
may be caused by stability or voltage-related issues).147  Therefore, as Exelon and 
FirstEnergy concede, under a transmission service designed to reflect load’s willingness 
and ability to limit energy withdrawals, “if the load installs systems aimed at limiting its 
use of the grid, those might change the system impacts and need for upgrades.”148  
Conversely, NITS requires PJM to plan the transmission system to deliver power to 
load,149 even if that load does not intend to ever withdraw power from the system, which 
could result in unnecessary Network Upgrades.  Exelon and FirstEnergy also claim that 
“[t]he fact that a load is located near a generator may well reduce system impacts . . . 
 
145 December Order, 193 FERC ¶ 61,217 at P 177. 
146 Exelon and FirstEnergy Request for Rehearing at 19. 
147 Exelon and FirstEnergy additionally contend that “even when no net power is 
being withdrawn from the system . . . the transmission system is affected and needed by 
the load—indeed, the Commission agreed with this proposition when it found that co-
located loads do utilize load-following based on gross rather than net load.”  Id. at 19-21.  
Again, we do not find that the need for Network Upgrades is based only on withdrawals; 
instead, we find that reducing the amount of MW flow can lead to the need for fewer or 
less costly Network Upgrades.  The December Order does not promote ignoring impacts 
when no net power is being withdrawn. 
148 Id. at 19-20.  We note that Exelon and FirstEnergy also state that “the same can 
be said for similar systems applied to other loads.  Nothing in the record [supports] that 
such systems are more beneficial for co-located load projects than for any other load [or] 
the use of different ratemaking principles when such installations are in place.  To the 
contrary, . . . the Commission has consistently rejected arguments that different 
ratemaking should be applied even where there are physical limits to the amount of 
transmission system use.”  Id.  We understand these arguments as directed to the 
replacement rate, and thus we address them below.  To the extent they are directed to the 
Commission’s FPA section 206 step one finding, we disagree for the same reasons stated 
below. 
149 PJM, Intra-PJM Tariffs, OATT, § III, § 28.2 (Transmission Provider 
Responsibilities) (1.0.0).

Docket No. EL25-49-002, et al. 
- 39 - 
regardless of whether the load has contracted with the generator it abuts, or with remote 
generation.”150  This assertion ignores the fact that a new transmission service reflecting 
willingness and ability to limit energy withdrawals could further reduce system 
impacts—for instance through the “systems aimed at limiting [the] use of the grid” that 
Exelon and FirstEnergy reference.151  We similarly disagree with Exelon and 
FirstEnergy’s claim that a new transmission service would not “alter what must be 
studied in assessing the physics and engineering of any proposed new configuration.”152  
Studies for a customer taking a new transmission service that limits the amount of energy 
that may be withdrawn would reflect that limitation.153  Such potential transmission 
service could alter the level of steady-state transmission system usage studied (i.e., the 
“physics”) and the design of the physical facilities, necessary control technologies, and/or 
protection systems needed to effectuate that arrangement compared to a traditional 
Network Customer (i.e., the “engineering”), contrary to Exelon and FirstEnergy’s 
assertions. 
 
Third, Exelon and FirstEnergy assert that the Commission contradicted itself in 
finding the Tariff unjust and unreasonable in lacking alternative transmission services 
because the Commission also stated that “‘it continues to be just and reasonable for an 
Eligible Customer taking transmission service on behalf of Co-Located Load to elect, as 
one of the required transmission services from which the Eligible Customer must choose, 
to take NITS.’”154  The Commission did not find that current set of transmission service 
options is just and reasonable.  Instead, the Commission stated, it continues to be just and 
reasonable for such an Eligible Customer “to elect” NITS “as one of the required 
 
150 Exelon and FirstEnergy Request for Rehearing at 20. 
151 Id. at 19-20.  Exelon and FirstEnergy likewise claim that Co-Location 
Arrangements “will have the same potential benefit regardless of whether there is a 
contractual supply arrangement with a nearby generator and regardless of whether it pays 
for transmission service based on net or gross load.”  Id. at 21.  This assertion again 
misses the key distinction.  Under a new alternative transmission service reflecting 
willingness and ability to limit energy withdrawals, there could be fewer or less costly 
Network Upgrades if the Eligible Customer can select a lower (but otherwise 
satisfactory) level of demand. 
152 Id. at 20. 
153 Exelon and FirstEnergy state that “[t]here is simply no evidence” for an 
argument that a new transmission service could speed access to service.  Id.  But the 
Commission’s findings are not based on speeding access to service or creating “fast-track 
interconnection.”  Id. at 20-21. 
154 Id. at 21-22 (quoting December Order, 193 FERC ¶ 61,217 at P 195).

Docket No. EL25-49-002, et al. 
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transmission services.”155  But it is unjust and unreasonable for that set of options to lack 
the alternatives the Commission discussed.156  
 
Fourth, Exelon and FirstEnergy argue that the Commission’s finding that the 
Tariff is unjust and unreasonable because it lacks alternative transmission service options 
misunderstands the benefits and burdens “to co-located projects of being interconnected 
to the grid.”157  The Commission did not find, however, that Co-Located Loads could 
receive no benefits from or place no burdens on the transmission system.  Instead, the 
Commission found that the Tariff was unjust and unreasonable because it did not reflect 
the features of Co-Location Arrangements that make the existing transmission service 
options unacceptable.158  An Eligible Customer taking transmission service on behalf of 
Co-Located Load must be charged for the benefits received from and the burdens placed 
on the transmission system—but that does not mean the status quo is not unjust and 
unreasonable.  Co-Located Load may be able to reduce the benefits received from and the 
burdens placed on the transmission system if it is willing and able to limit energy 
withdrawals.  We do not dispute, and indeed continue to find, that Co-Located Loads do 
receive benefits even if they have zero net energy withdrawals, specifically from 
regulation and black start services.159  The Commission’s finding that the Tariff is unjust 
and unreasonable does not preclude the recognition of those benefits. 
 
Finally, Exelon and FirstEnergy maintain that the Commission’s “finding that the 
existing PJM Tariff is [unjust and unreasonable] is arbitrary and capricious because the 
Commission failed to consider the unique issues that attend co-location with nuclear 
plants.”160  This argument is misplaced.  The Commission found that the Tariff is unjust 
and unreasonable for, in part, the two reasons discussed above.161  In particular, the 
Commission found the Tariff unjust and unreasonable because it does not include an 
option for Eligible Customers on behalf of Co-Located Loads to take transmission 
services that reflect their willingness and ability to limit their energy withdrawals from 
 
155 December Order, 193 FERC ¶ 61,217 at P 195 (emphasis added). 
156 Id. P 177.  
157 Exelon and FirstEnergy Request for Rehearing at 30-32; see also id. 
(discussing various benefits and burdens).  
158 December Order, 193 FERC ¶ 61,217 at P 177.  
159 Id. P 185. 
160 Exelon and FirstEnergy Request for Rehearing at 32-33.  
161 December Order, 193 FERC ¶ 61,217 at PP 176, 177.

Docket No. EL25-49-002, et al. 
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the transmission system.  The fact that a nuclear generator in a Co-Location Arrangement 
might be dependent on the transmission system because that nuclear generator cannot 
operate without a robust interconnection to the transmission system, or cannot load 
follow, does not undermine these core findings.  Exelon and FirstEnergy attempt to use 
these facts to conclude that the Co-Located Load is effectively using the transmission 
system in a similar manner to a load served by remote resources.  We disagree because, 
regardless of load following, the energy used by the Co-Located Load is provided (at 
least in part) by its Co-Located Generator, not via the transmission system.  Eligible 
Customers on behalf of Co-Located Loads that are served by a Co-Located Generator 
that is a nuclear generator should be permitted to take transmission services that reflect 
that they are willing and able to limit their withdrawals from the transmission system 
under certain conditions.  To the extent a nuclear generator that is part of a Co-Location 
Arrangement operates differently than other Co-Located Generators, that is an issue that 
may be assessed in subsequent study processes, or simply by the nuclear generator itself, 
as the Interconnection Customer (not the Eligible Customer) in determining whether and 
how to enter into a Co-Location Arrangement.  
2. 
Retail BTMG Netting Rules 
a. 
Scope and Adequate Notice 
i. 
December Order 
 
The Commission found that PJM’s retail BTMG netting rules are no longer just 
and reasonable and clarified that this finding applies to all Network Load.162 
ii. 
Request for Clarification and/or Rehearing 
 
Citing the Administrative Procedure Act (APA) and Commission Rule 209, 
Industrials argue that changes to retail BTMG netting rules are outside the scope of the 
February Order.163  Industrials assert that the February Order set the scope of the 
proceeding and limited it to Co-Located Load and Co-Location Arrangements, thus 
excluding BTMG.  Industrials argue that no part of the February Order included the 
possibility of the Commission’s BTMG netting findings in the December Order.  
Industrials allege there are important distinctions between Co-Location Arrangements 
and BTMG, particularly that a BTMG arrangement is a retail load-modification 
 
162 Id. P 186. 
163 Industrials Request for Clarification or Rehearing at 22 (citing 5 U.S.C. § 706; 
18 C.F.R. § 385.209 (2025)); see also 5 U.S.C. § 554.

Docket No. EL25-49-002, et al. 
- 42 - 
construct, whereas a Co-Location Arrangement is a wholesale-system-impacting load 
integration construct.164  
iii. 
Determination 
 
We disagree with Industrials that changes to retail BTMG netting rules are beyond 
the scope of this proceeding because the Commission provided adequate notice as to 
those changes.   
 
Under the APA, an agency setting a matter for hearing must provide parties with 
adequate notice of the issues that would be considered, and ultimately resolved, at that 
hearing.165  Under Commission Rule 209(b), “an order to show cause will contain a 
statement of the matters about which the Commission is inquiring, and a statement of the 
authority under which the Commission is acting.  The statement is tentative and sets forth 
issues to be considered by the Commission.”166   
 
While Industrials allege that the Commission in the February Order “set the scope 
of the proceeding to Co-Located Load,”167 the Commission did no such thing.  The 
February Order contains no finding limiting the proceeding’s scope to “Co-Located 
Load.”  Instead, the February Order also expressly raises, among many other topics, 
relevant generation configurations168 and overall addresses issues that attend to load with 
on-site or otherwise nearby generation, which logically includes BTMG.169   
 
164 Industrials Request for Clarification or Rehearing at 22-26.  
165 N. Va. Elec. Coop., Inc. v. FERC, 945 F.3d 1201, 1205 (D.C. Cir. 2019); 
5 U.S.C. § 554(b)(3) (establishing notice requirement for adjudications). 
166 18 C.F.R. § 385.209(b). 
167 Industrials Request for Clarification or Rehearing at 22.  
168 February Order, 190 FERC ¶ 61,115 at P 79.  
169 Id. P 76 (discussing concerns related to generation and load being “likely to use 
or benefit from the transmission system in different ways depending on how they are 
configured” and giving examples such as “Network Load may co-locate with a generator 
that is not a grid resource and that either serves the load as an off-grid backup or that 
reduces the Network Load’s consumption during peak hours” (emphasis added)).

Docket No. EL25-49-002, et al. 
- 43 - 
 
In any event, Industrials themselves acknowledge that the Commission’s briefing 
questions in fact specifically included BTMG.170  In particular, the Commission asked 
parties to address “how co-located loads are similar to or disparate from other types of 
arrangements where load and generation share the same point of interconnection (such as 
Behind the Meter Generation[)].”171  This question reflects that the Commission would 
consider BTMG configurations in determining a just and reasonable replacement rate.  
Industrials contend that the Commission’s reference to “other arrangements” in this 
question shows that retail BTMG and Co-Located Load are distinct concepts, but 
Industrials’ claims are belied by their assertions in their reply comments to the February 
Order that BTMG configurations and Co-Location Arrangements identically impact the 
transmission system.172  And regardless of their similarity, the Commission’s briefing 
question raises the subject of the treatment of BTMG.  Additional briefing questions in 
the February Order also sufficiently raise the subject of BTMG.  The Commission 
directed parties to submit briefing on transmission services, including potential changes 
to the rates, terms, and conditions of NITS to accommodate Co-Location 
Arrangements.173  PJM’s retail BTMG netting rules are part of PJM’s rates, terms, and 
conditions for NITS.174  Finally, the Commission also asked “whether portions of the 
Guidance Document may serve as a just and reasonable and not unduly discriminatory or 
preferential replacement rate,”175 and that document states, “[i]f the co-located Customer 
Facility elects to be designated as [BTMG], it will be allowed to net the co-located load 
directly against the output of the co-located Customer Facility.”176  We thus find that the 
February Order provided adequate notice that the Commission would consider PJM’s 
BTMG netting rules as part of this proceeding. 
 
The record developed in response to the February Order further reflects that 
Industrials had notice and an opportunity to address changing PJM’s retail BTMG netting 
 
170 Industrials Request for Clarification or Rehearing at 25. 
171 February Order, 190 FERC ¶ 61,115 at P 88 (briefing question a.iv). 
172 PJM ICC and IECA April 23, 2025 Reply Comments at 9. 
173 February Order, 190 FERC ¶ 61,115 at P 88 (briefing question b.iv). 
174 PJM, Intra-PJM Tariffs, OATT, § III, § 34.2 (Netting of Behind the Meter 
Generation) (0.0.0). 
175 February Order, 190 FERC ¶ 61,115 at P 88 (briefing question a.iii). 
176 PJM, PJM Guidance on Co-Located Load (Mar. 22, 2024) (updated Apr. 17, 
2024), https://www.pjm.com/-/media/DotCom/markets-ops/rpm/rpm-auction-info/pjm-
guidance-on-co-located-load.pdf.

Docket No. EL25-49-002, et al. 
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rules.  While Industrials attempt to minimize the briefing questions as “scarcely 
mention[ing]” BTMG among a large number of topics in the February Order, PJM 
submitted detailed concerns that the retail BTMG netting rules were no longer just and 
reasonable in direct response to the February Order.177  And parties debated the merits of 
PJM’s concerns in reply comments.178  All parties, including Industrials, had an 
opportunity to rebut PJM’s claims before the Commission could weigh the evidence on 
this matter.  As courts have explained, subsequent briefing on a topic serves as evidence 
of adequate notice as to that topic.179  
b. 
Whether PJM’s Retail BTMG Rules Are Unjust and 
Unreasonable 
i. 
December Order 
 
In finding that PJM’s retail BTMG netting rules are no longer just and reasonable, 
the Commission explained that circumstances had changed since the Commission 
approved PJM’s rules in 2004.180  The Commission stated that PJM explains that the 
BTMG netting rules were “conceived for, and [have] been implemented for, substantially 
smaller loads (like a warehouse with solar panels) and not on the scale of large data 
 
177 PJM March 24, 2025 Response at 34 (“The co-located load arrangements at 
issue here, large data centers, could be viewed as similar to BTM Generation that 
currently exists under PJM’s Tariff (as reflected in Ex. A, Option 3).  But as explained 
herein, the BTM Generation paradigm does not fit co-location arrangements particularly 
well because it was not designed with large load co-location in mind.”); id. at 36-37 (“In 
sum, discussions in the record regarding PJM’s BTM Generation rules raise questions 
about the status of those rules.  PJM is open to exploring . . . whether the 20-year-old 
method of allocating costs pursuant to the BTM Generation netting rules remains 
consistent with cost causation principles.”). 
178 Compare AMP April 23, 2025 Reply Comments at 10 (“The record provides 
no basis to revisit the current PJM Tariff provisions addressing BTMG.”), with 
Northeastern Rural Electric Membership Corporation (NREMC) April 23, 2025 Reply 
Comments at 5 (“Additionally, simple netting of generation against load could allow 
these facilities [i.e., data centers] to avoid most, if not all, costs by netting out to zero as 
the entire load is supplied by the co-located generator, despite the co-located loads 
reliance and benefit from the grid.  This would shift costs and burdens unfairly to other 
users, violating core principles of just and reasonable ratemaking.”). 
179 N. Va. Elec. Coop., Inc., 945 F.3d at 1206. 
180 December Order, 193 FERC ¶ 61,217 at P 186 (citing PJM, 107 FERC 
¶ 61,113 (2004) (2004 BTMG Order)).

Docket No. EL25-49-002, et al. 
- 45 - 
centers.”181  However, the Commission stated that large loads, both existing and in the 
planning stages with PJM, have proliferated in recent years, and PJM has persuasively 
explained the problems that could occur if Network Customers with large loads were 
allowed to use the existing BTMG netting rules in the Tariff.182  The Commission stated 
that, for example, PJM explains that “[a]llowing very large loads like data centers to net 
is problematic because loads in this configuration do not carry reserves.”183  The 
Commission stated that such loads must nevertheless be served, however, allowing them 
to “lean on the PJM system when the [BTMG] is on a full or partial outage or if the load 
exceeds the rating of the [BTMG].”184  The Commission emphasized that PJM’s existing 
BTMG netting rules do not limit the amount of qualifying load that a Network Customer 
may net by using BTMG and do not provide any protections against this potential 
transmission and resource adequacy planning problem or against the costs of maintaining 
sufficient resources to serve these loads being shifted onto other customers.185  The 
Commission found that PJM’s BTMG netting rules are no longer consistent with cost 
causation principles, because large loads configured in a BTMG arrangement with 
significant generation will raise cost-shifting concerns compared to loads pursuing 
smaller amounts of netting.  The Commission found that PJM’s existing BTMG netting 
rules may lead to both reliability and resource adequacy risks because PJM, per its Tariff, 
is obligated to serve transmission customers using BTMG but does not consider such 
customers in transmission and resource adequacy planning. 
ii. 
Request for Clarification and/or Rehearing 
 
Industrials argue that the Commission erred by failing to address prior precedent 
on cost causation and failing to demonstrate that the existing BTMG netting rules were 
 
181 Id. (quoting PJM March 24, 2025 Response at 13). 
182 Id. (citing Docket No. AD24-11-000, Large Loads Co-Located at Generating 
Facilities Tr. at 9:2-3 (noting that “large data centers [] need these significant new 
amounts of energy for their business”); PJM Interconnection, L.L.C., 188 FERC                        
¶ 61,200, at P 5 (2024) (“PJM explains that the [tariff] proposal [to allocate load 
adjustments] was spurred by the recent proliferation of data centers that are contributing 
to large additions of forecasted load concentrated within a specific wholesale metering 
area.”)). 
183 December Order, 193 FERC ¶ 61,217 at P 186 (quoting PJM March 24, 2025 
Response at 36). 
184 Id. (quoting PJM March 24, 2025 Response at 13 n.5). 
185 Id. (citing PJM, Intra-PJM Tariffs, OATT, § III, § 34.2 (Netting of Behind the 
Meter Generation) (0.0.0)).

Docket No. EL25-49-002, et al. 
- 46 - 
unjust and unreasonable.186  Industrials contend that Commission precedent established 
the “actual use” principle, which holds that “actual use” of the transmission system is a 
just and reasonable approach for assessing transmission charges that comports with cost 
causation.187  Industrials argue that the Commission here abandons the “actual use” 
principle by finding BTMG netting unjust and unreasonable.188  According to Industrials, 
the December Order also “creates an unreasonable split between those who manage costs 
by managing load and those who manage costs by investing in generation.”189  “In other 
words,” Industrials contend, “the effect of the ‘gross load’ approach is unduly 
discriminatory, because it allows ‘actual use’ to govern NITS costs for some (i.e.,                 
load-only customers), but not for others (i.e., those who have invested in retail                  
behind-the-meter generation).”190  Industrials acknowledge that “[i]f standby fees or other 
charges need to be considered in accordance with cost-causation principles, the 
Commission may explore those,” but argue that “eliminating altogether the assessment of 
charges based on ‘actual use’ is unduly discriminatory and fails to reckon with                    
well-established Commission precedent.”191  
 
186 Industrials Request for Clarification or Rehearing at 34; see also id. at 5, 19-20. 
187 Id. at 35-36 (citing 2004 BTMG Order, 107 FERC ¶ 61,113, at P 4 (finding “no 
transmission or distribution facilities are used to deliver energy from the generating unit 
to the load”); Occidental Chem. Corp. v. PJM Interconnection, 102 FERC ¶ 61,275,                    
at P 14 (2003) (Occidental) (“Access charges for use of PJM’s transmission system 
should be allocated to network customers based on a network customer’s actual use of 
PJM’s system, consistent with the principle of cost causation.”); PJM Interconnection, 
L.L.C., 167 FERC ¶ 61,268, at P 23 (2019) (PJM) (affirming Commission’s conclusion in 
Occidental that Network Customers’ charges for use of PJM’s transmission system 
should be allocated based on a Network Customer’s actual use of PJM’s system); ISO 
New Eng., Inc., 178 FERC ¶ 61,086, at P 51 (2022) (ISO-NE) (finding just and 
reasonable ISO New England Inc.’s proposal to exclude from the Monthly Regional 
Network Load served by unregistered BTMG and the portion of the output of a Generator 
Asset that serves load located behind the same retail customer meter and assign Regional 
Network Service charges to Network Customers based on each Network Customer’s 
actual use of the system)). 
188 Industrials Request for Clarification or Rehearing at 35-37.  
189 Id. at 37.  
190 Id. at 37-38. 
191 Id. at 38.

Docket No. EL25-49-002, et al. 
- 47 - 
 
Industrials argue that the Commission did not develop a sufficient record on which 
to base its determinations on BTMG netting rules in the Tariff.192  Industrials give several 
examples of “real-life facility configurations” that will face substantial harms or be 
undercompensated under a “gross load” approach.193  Industrials argue that, without a 
well-developed record, the Commission may not be able to fully recognize the cost 
causation implications of the removal of all netting rules. 
iii. 
Determination 
 
We disagree with Industrials that the Commission failed to address prior precedent 
in the December Order or show that PJM’s retail BTMG netting rules were unjust and 
unreasonable.194  The Commission in the December Order summarized its decision 
approving PJM’s retail BTMG netting rules, including the finding in the 2004 BTMG 
Order accepting the BTMG netting rules that “charges for use of PJM’s transmission 
system should be allocated to network customers based on a network customer’s actual 
use of PJM’s system, consistent with the principle of cost causation.”195  We recognize 
that the Commission’s 2004 BTMG Order relied upon Occidental for the proposition that 
NITS charges should be based on actual use,196 and that, after 2004, the Commission has 
relied upon Occidental and/or the 2004 BTMG Order to support similar findings.197  But 
the Commission in the December Order did not find that it is no longer just and 
unreasonable to ever allocate transmission charges based on actual use.  Rather, the 
Commission found that PJM’s retail BTMG netting rules are no longer consistent with 
cost causation principles for a specific reason, that is, because large loads configured in a 
BTMG arrangement with significant generation will raise cost-shifting concerns 
 
192 Id. at 26; see also id. at 6. 
193 Id. at 27-31; see also id. at 4-5. 
194 Id. at 34-38. 
195 December Order, 193 FERC ¶ 61,217 at P 7 (quoting 2004 BTMG Order,                   
107 FERC ¶ 61,113 at P 28); Id. P 186 (citing 2004 BTMG Order, 107 FERC ¶ 61,113). 
196 2004 BTMG Order, 107 FERC ¶ 61,113 at P 28 (citing Occidental, 102 FERC 
¶ 61,275). 
197 See PJM, 167 FERC ¶ 61,268 at P 23 (discussing Occidental for the 
proposition that the Commission has found that RTOs and transmission owners must 
recognize load reductions from interruptible load programs in computing billing 
determinants); ISO-NE, 178 FERC ¶ 61,086 at P 51 (finding just and reasonable ISO 
New England’s proposal to charge Network Customers based on actual use of the 
system).

Docket No. EL25-49-002, et al. 
- 48 - 
compared to loads pursuing smaller amounts of netting.198  The Commission thus 
explained that these PJM retail BTMG netting rules, while previously consistent with 
cost causation principles at the time the Commission approved them, were rendered 
unjust and unreasonable by a change in circumstances.  In further support of its finding 
that these rules are no longer just and reasonable, the Commission found that PJM’s 
existing retail BTMG netting rules may lead to both reliability and resource adequacy 
risks because PJM, per its Tariff, is obligated to serve transmission customers using 
BTMG but does not consider such customers in transmission and resource adequacy 
planning.199  The Commission orders relying on actual use principles that Industrials cite 
do not reflect the problems currently posed in PJM by large loads configured in a BTMG 
arrangement.200   
 
We also disagree with Industrials that the Commission did not develop a sufficient 
record on which to base its determination in the December Order on PJM’s retail BTMG 
netting rules.201  As discussed above, the Commission adequately supported its findings 
that PJM’s retail BTMG netting rules are no longer just and reasonable.  Importantly, the 
Commission relied on evidence submitted by PJM detailing problems that could occur if 
Network Customers with large loads were allowed to use the existing retail BTMG 
netting rules in the Tariff.202  Other parties raised similar concerns in the record.203 
 
Industrials instead raise concerns that the Commission’s decision results in 
significant economic harm to entities who have used PJM’s retail BTMG netting rules 
 
198 December Order, 193 FERC ¶ 61,217 at P 186. 
199 Id.; see PJM, Intra-PJM Tariffs, OATT, § III, § 34.2 (Netting of Behind the 
Meter Generation) (0.0.0). 
200 See, e.g., ISO-NE, 178 FERC ¶ 61,086 at P 8 (explaining that, decades ago, 
behind-the-meter generation was typically larger on-site generation connected to 
industrial load, but since then, behind-the-meter generation has evolved with increasing 
amounts of widely distributed behind-the-meter generation that is below 5 MW, such as 
solar photovoltaic generation). 
201 Industrials Request for Clarification or Rehearing at 26-27. 
202 December Order, 193 FERC ¶ 61,217 at P 186 (“For example, PJM explains 
that “[a]llowing very large loads like data centers to net is problematic because loads in 
this configuration do not carry reserves.”) (quoting PJM March 24, 2025 Response at 36). 
203 Id. P 73 (“NREMC argues that large Co-Located Loads paired with BTMG 
present significantly greater operational risks than traditional BTMG arrangements 
because they lack adequate reserves.”) (citing NREMC April 23 Reply Comments at 5).

Docket No. EL25-49-002, et al. 
- 49 - 
and the Commission may not have fully recognized the cost causation implications of the 
removal of all netting rules.204  We find these concerns unpersuasive for several reasons.  
First, we believe Industrials’ argument concerns how the Commission fashions a 
replacement rate that determines the extent to which entities may be able to continue to 
rely on netting,205 not to the Commission’s finding that the existing rate in PJM is no 
longer just and reasonable.   
 
Second, as the Commission explained in the December Order in its determination 
on transmission services, NITS charges based on gross load for Network Load are 
roughly commensurate with the benefits received because Network Load has the right to 
be served from the transmission system at any time.206  The Commission’s decision to 
revise PJM’s retail BTMG netting rules may increase transmission charges for Network 
Customers who have used PJM’s retail BTMG netting rules, but this change better aligns 
the benefits and costs for these customers and addresses cost-shifting concerns because it 
reflects the fact that they must be served even when their retail BTMG is on outage.207  
 
Third, as discussed elsewhere in this order, we set aside the December Order in 
part and permit Eligible Customers taking transmission service on behalf of load served 
by BTMG to have the option to take the new transmission services set forth in the 
December Order.  Therefore, Eligible Customers taking transmission service on behalf of 
load served by BTMG will, at minimum, not be required to take NITS on a gross load 
basis but will have the option to take and be charged for different transmission services.   
 
Fourth, we note that Industrials offer six examples involving specific BTMG 
arrangements that could be financially harmed by the removal of PJM’s retail BTMG 
netting rules.  As discussed above, to the extent these BTMG arrangements are 
financially harmed, that implicates the Commission’s decision to set a replacement rate 
as to the extent to which such entities may continue to net going forward.  Also, as 
discussed below, we set aside the December Order in part and direct PJM to exempt 
certain cogeneration facilities from revised retail BTMG netting rules where the facilities 
may be integrated with load such that, when their generator trips offline, the load follows 
(rather than withdrawing energy from the transmission system), as such facilities would 
not present the cost shift, reliability, or resource adequacy concerns discussed in the 
 
204 Industrials Request for Clarification or Rehearing at 27. 
205 See supra Part IV.C.1.c. 
206 December Order, 193 FERC ¶ 61,217 at P 198. 
207 See id. P 186 (finding that PJM’s retail BTMG netting rules raise cost-shifting 
concerns due to large loads configured in BTMG arrangements).

Docket No. EL25-49-002, et al. 
- 50 - 
December Order.208  To the extent that any of the facilities discussed in Industrials’ six 
examples could demonstrate that they do not present such concerns, they may fall within 
the exemption that we direct PJM to submit as part of the compliance filing discussed 
below.209   
 
We also disagree with Industrials that the December Order unduly discriminates 
against Network Customers who manage costs by investing in generation as compared to 
Network Customers who manage costs by managing load.  Undue discrimination 
prohibited by the FPA can occur when similarly situated customers are treated 
differently.210  Here, Industrials fail to show that the December Order results in 
differential treatment because Network Customers are subject to charges for NITS based 
on gross load whether or not they have associated generation, with the exception of the 
materiality threshold for retail BTMG discussed below.  In addition, the December Order 
neither addresses nor limits Network Customers’ ability to manage load, whether or not 
they have associated generation. 
3. 
Transmission Service Options for BTMG 
a. 
December Order 
 
As explained above, the Commission found that the Tariff is unjust and 
unreasonable because it does not include transmission services that reflect Eligible 
Customers taking service on behalf of Co-Located Loads that are willing and able to limit 
their energy withdrawals from the transmission system under certain conditions.211   
 
The Commission found that PJM’s retail BTMG netting rules were no longer just 
and reasonable, explaining that these rules may lead to both reliability and resource 
adequacy risks because PJM, per its Tariff, is obligated to serve transmission customers 
 
208 Id. 
209 See, e.g., Industrials Request for Clarification or Rehearing at 27 (“Because the 
manufacturing process requires steam produced for generation, the bulk of the load can 
remain online only if generation is operational.  If the generation goes down, the load will 
largely cease as well.”). 
210 Cal. Indep. Sys. Operator Corp., 193 FERC ¶ 61,117, at P 33 (2025). 
211 December Order, 193 FERC ¶ 61,217 at P 193.

Docket No. EL25-49-002, et al. 
- 51 - 
using BTMG but does not consider such customers in transmission and resource 
adequacy planning.212   
b. 
Request for Clarification and/or Rehearing 
 
Industrials request clarification that the new transmission services must be made 
available to Eligible Customers taking transmission service on behalf of load-only 
customers with BTMG.213  Industrials argue that Eligible Customers taking transmission 
service on behalf of load-only customers with BTMG should also be allowed to benefit 
from the new transmission services.214 
c. 
Determination 
 
We set aside, in part, the December Order.  In addition to the finding in the 
December Order that the Tariff is unjust and unreasonable as to Eligible Customers 
taking transmission service on behalf of Co-Located Load, we also find that the Tariff is 
unjust and unreasonable because it does not include transmission services that reflect that 
Eligible Customers taking transmission service on behalf of load with BTMG are willing 
and able to limit their energy withdrawals from the transmission system under certain 
conditions.  Requiring Eligible Customers taking transmission service on behalf of load 
with BTMG to take NITS, without the option to instead take such alternative 
transmission services that reflect their willingness and ability to limit their energy 
withdrawals, would be unjust and unreasonable for the same reasons we made the same 
finding with respect to Eligible Customers taking transmission service on behalf of                
Co-Located Load.215  For purposes of this order, then, we use the term Eligible Load to 
refer to Co-Located Load216 and/or load with BTMG.217  We also direct PJM to file, 
within 60 days of the date of issuance of this order, a definition for Eligible Load, or 
other comparable Tariff revisions to implement these directives, and to revise its 
definition of BTMG to allow Eligible Customers taking transmission service on behalf of 
 
212 Id. P 186. 
213 Industrials Request for Clarification or Rehearing at 13-14.  
214 Id.  
215 See supra Part IV.B.1.c (discussing further the Commission’s finding in the 
December Order that the Tariff is unjust and unreasonable as to Eligible Customers 
taking transmission service on behalf of Co-Located Load). 
216 See supra P 10. 
217 See supra note 4.

Docket No. EL25-49-002, et al. 
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load with BTMG that are willing and able to limit their energy withdrawals from the 
transmission system under certain conditions to take the new transmission services, 
consistent with this order.  All Eligible Customers taking one of the new transmission 
services on behalf of Eligible Load will be subject to the requirements discussed below, 
including, but not limited to, operational requirements such as necessary control 
technologies and/or protection systems as discussed in part VI.C and penalty charges and 
other remedial actions as discussed in part VI.D. 
C. 
Replacement Rate 
1. 
Transmission Services 
a. 
NITS 
i. 
December Order 
 
As relevant here, the Commission found that NITS must be taken on a gross 
basis.218   
ii. 
Request for Clarification 
 
PIOs request clarification of the December Order regarding cost allocation issues.  
PIOs argue that, given the unprecedented volume and scale of large load requests, the 
Commission should evaluate whether existing transmission rate designs remain just and 
reasonable.  PIOs state that the Commission held in the December Order that Co-Located 
Load taking NITS would be responsible for costs that are “roughly commensurate” with 
benefits because zonal NITS rates include upgrades and operations and maintenance 
costs.  PIOs argue that this rate design relies on a standard assuming that load growth is 
incremental and widely distributed, however, whereas discrete large-load pockets trigger 
multi-million dollar reliability solutions.219   
 
PIOs contend that a significant “payer gap” can emerge because customers pay 
only in proportion to billing determinants rather than by the incremental costs that they 
trigger.  PIOs provide the example of a transmission project portfolio approved in the 
2024 Regional Transmission Expansion Plan (RTEP) Window 1 that will cost           
$5.08 billion and state that if a 1,000 MW data center represents 7% of the zone’s peak 
determinants, it would contribute only $203 million and leave a $4.877 billion gap for 
unrelated regional and zonal customers to pay.  PIOs therefore request that the 
Commission clarify how “roughly commensurate” cost allocation is evaluated when a 
 
218 December Order, 193 FERC ¶ 61,217 at P 195.  
219 PIOs Request for Clarification at 7.

Docket No. EL25-49-002, et al. 
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discrete driver’s pro-rata contribution is minimal compared to the infrastructure it 
necessitates.  PIOs also argue that the Commission should require PJM and the PJM 
transmission owners to provide transparent reporting for major projects that compares 
incremental cost causation against pro-rata billing determinant recovery.220 
iii. 
Determination 
 
We deny the request for clarification.221  In the December Order, the Commission 
found that NITS must be taken on a gross basis.222  The Commission did not address cost 
allocation for Network Upgrades needed to accommodate NITS (or related reporting 
requirements) and we decline to do so here, finding those issues to be sufficiently distinct 
from the immediate issues in this proceeding and outside the scope of this proceeding.  In 
any event, we note that these issues would be better addressed in a separate proceeding in 
which a record could be developed on these technical topics.223 
b. 
New Transmission Services 
 
In the December Order, the Commission—having found the Tariff unjust and 
unreasonable because it lacked relevant provisions with sufficient clarity and 
transmission services that reflect Eligible Customers taking service on behalf of                  
Co-Located Loads that are willing and able to limit their energy withdrawals—addressed 
a just and reasonable replacement rate.224 
 
220 Id. at 7-8. 
221 PIOs’ request for clarification is titled and presented as a request for 
clarification, id. at 1, and we treat it as such, noting that it does not meet the 
Commission’s requirements for requests for rehearing.  18 C.F.R. § 385.713(c)(2); Pub. 
Serv. Co. of Colo., 190 FERC ¶ 61,128, at P 24 (2025).   
222 December Order, 193 FERC ¶ 61,217 at P 195.  
223 See Mobil Oil Expl. & Prod. Serv. v. United Distrib. Cos., 498 U.S. 211,               
230-31 (1991) (“An agency enjoys broad discretion in determining how best to handle 
related, yet discrete, issues in terms of procedures.”); Tenn. Valley Mun. Gas Ass’n v. 
FERC, 140 F.3d 1085, 1088 (D.C. Cir. 1998) (the Commission has “broad discretion to 
determine when and how to hear and decide the matters that come before it”); Stowers 
Oil & Gas Co., 27 FERC ¶ 61,001, at 61,001 (1984) (“The Commission, like other 
agencies, is generally master of its own calendar and procedures.”). 
224 December Order, 193 FERC ¶ 61,217 at P 193.

Docket No. EL25-49-002, et al. 
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The Commission directed PJM to submit a compliance filing to modify its Tariff 
to require that the Eligible Customer taking transmission service on behalf of a                       
Co-Located Load takes one of three transmission services:  (1) NITS or Interim NITS,  
(2) a new FCD transmission service, or (3) a new NFCD transmission service.225  The 
Commission also established paper hearing procedures to determine the appropriate rates, 
terms, and conditions of the new transmission services.226  The Commission stated that 
Interim NITS is a new interim, non-firm transmission service, which allows an Eligible 
Customer that has requested NITS on behalf of a Co-Located Load to take non-firm 
transmission service that can be interrupted until the Network Upgrades necessary to 
provide NITS are complete and the Co-Located Load can be designated as Network 
Load.227   
 
The Commission stated that, under the FCD transmission service, Eligible 
Customers will have the right to request transmission service on behalf of a Co-Located 
Load up to a specified MW quantity, i.e., the contract demand.  The Commission stated 
that the FCD transmission service will have the same reservation and curtailment priority 
as existing firm transmission services, at the level of the contract demand.  However, the 
Commission stated that, unlike Network Customers, the Eligible Customer taking the 
FCD transmission service on behalf of the Co-Located Load is not permitted to withdraw 
energy from the PJM transmission system beyond the contract demand level.228   
 
The Commission stated that the new NFCD transmission service will be provided 
during normal operations, on an as-available basis, and curtailed during emergency 
operations (i.e., it will be curtailed before existing firm transmission services and the new 
FCD transmission service).  The Commission stated that, under this service, Eligible 
Customers may reserve transmission service on behalf of a Co-Located Load as needed 
during normal, non-emergency system operating conditions.  The Commission stated that 
reservations under this service would be available only when there is available 
transmission capacity, similar to existing non-firm transmission service options in the 
Tariff.229 
 
225 Id. 
226 Id. P 194. 
227 Id. P 200. 
228 Id. P 208. 
229 Id. P 215.

Docket No. EL25-49-002, et al. 
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i. 
BTMG 
(a) 
Requests for Clarification and/or Rehearing 
 As to a replacement rate covering Eligible Customers taking transmission service 
on behalf of load-only customers with BTMG, Industrials request clarification that the 
new transmission services must be made available to those customers.230  Industrials 
argue that Eligible Customers taking transmission service on behalf of load-only 
customers with BTMG should also be allowed to benefit from the new transmission 
services.231   
(b) 
Determination 
 As explained above, we set aside, in part, the December Order and find that the 
Tariff is unjust and unreasonable because it does not include transmission services that 
reflect Eligible Customers taking transmission service on behalf of loads with BTMG that 
are willing and able to limit their energy withdrawals from the transmission system under 
certain conditions.  Consistent with this new determination, we now direct PJM to revise 
its Tariff to extend the three new transmission services set forth in the December Order to 
Eligible Customers taking service on behalf of load with BTMG that are willing and able 
to limit their energy withdrawals from the transmission system under certain conditions. 
 Specifically, we direct PJM to submit a compliance filing, within 60 days of the 
date of this order, to modify its Tariff to require that the Eligible Customer taking 
transmission service on behalf of Eligible Load takes one of three transmission services:  
(1) NITS or Interim NITS, (2) FCD transmission service, or (3) NFCD transmission 
service.232  We find that it is just and reasonable for an Eligible Customer taking 
transmission service on behalf of Eligible Load to elect, as one of the required 
transmission services from which the Eligible Customer must choose, to take NITS for 
the same reasons we made that finding with respect to Eligible Customers taking 
transmission service on behalf of Co-Located Loads.233 
 Eligible Customers, on behalf of the Eligible Loads that they represent, may 
choose the transmission services that match their preferred use of the transmission 
 
230 Industrials Request for Clarification or Rehearing at 13-14.  
231 Id.  
232 They must choose at least one of the required transmission services and may 
take a combination of the FCD and NFCD transmission services. 
233 December Order, 193 FERC ¶ 61,217 at PP 195, 198.

Docket No. EL25-49-002, et al. 
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system; however, they must choose at least one of the required transmission services, and 
may take a combination of the FCD and NFCD transmission services.  In addition, in 
instances where load with BTMG includes necessary control technologies and/or 
protection systems that limit its energy withdrawals, we find that it is a just and 
reasonable replacement rate to allow an Eligible Customer taking transmission service on 
behalf of Eligible Load to take and be charged for new types of transmission service that 
are alternatives, and not equivalent, to NITS:  FCD and NFCD transmission services.234   
ii. 
Undue Discrimination 
(a) 
Requests for Clarification and/or Rehearing 
 Exelon and FirstEnergy argue that the Commission granted an undue preference to 
Co-Located Loads in requiring new forms for transmission services.235  Exelon and 
FirstEnergy charge that the Commission failed “to explain why system protection 
schemes installed in [non-Co-Located Load] configurations would not provide similar 
benefits and be deserving of preferential rates.”236  Exelon and FirstEnergy contend that 
the totality of the burdens and benefits of grid interconnection justify charging                       
Co-Located Load the same rate as all other transmission customers.  Exelon and 
FirstEnergy assert that the Commission’s new transmission service reduces the share of 
embedded costs for Co-Located Loads compared to all other users who receive the same 
benefits.   
 Industrials request clarification that the new transmission services must be made 
available to load-only customers with load flexibility, minimal retail BTMG, or no retail 
BTMG.237  Industrials contend that this clarification would reduce the risk of undue 
discrimination because “[m]any large load customers can curtail their load at key times 
and control the amount of transmission service they use and when they use it.”238  
Industrials also argue that this clarification would avoid potential cost shifts that would 
occur if similarly situated customers were given different options depending only on 
whether they have small generators on site.  Industrials assert that this clarification would 
 
234 See id. P 205. 
235 Exelon and FirstEnergy Request for Rehearing at 36-39. 
236 Id. at 38. 
237 Industrials Request for Clarification or Rehearing at 13 (“Such an approach 
would align with the natural gas industry’s long history of large gas consumers electing 
how much service they purchase.”); see also id. at 6-7.  
238 Id. at 14.

Docket No. EL25-49-002, et al. 
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extend the optionality of the new transmission services to retail BTMG and load-only 
customers.239  Lastly, Industrials argue that this clarification could make the PJM 
transmission planning process more efficient.240   
(b) 
Determination 
 As an initial matter, we dismiss the argument that the new transmission services 
would be unduly discriminatory or preferential.241  First, we dismiss this argument for 
lack of finality.  Rule 713(b) of the Commission’s Rules of Practice and Procedure 
permits requests for rehearing “of any final decision or other final order in a 
proceeding.”242  A final decision is one that imposes an obligation, denies a right, or fixes 
some legal relationship as a consummation of the administrative process.243  The 
December Order did not make a final decision on the rates, terms, and conditions for the 
new transmission services.244  Instead, the Commission found that “additional record 
evidence is needed” and set these issues for paper hearing procedures.245  Setting a matter 
 
239 Id. at 14-15. 
240 Id. at 15.  
241 Exelon and FirstEnergy Rehearing Request at 19-20, 30-31, 36-39, 52-53; 
Industrials Request for Clarification or Rehearing at 13-14.  Further, as discussed above, 
we set aside the December Order, in part, and find in this order that it is just and 
reasonable for Eligible Customers taking transmission service on behalf of load with 
BTMG to take one of three transmission services:  (1) NITS or Interim NITS, (2) FCD 
transmission service, or (3) NFCD transmission service.  We therefore do not address 
whether it would be unduly discriminatory or preferential if the replacement rate were to 
not allow Eligible Customers taking transmission service on behalf of load with BTMG 
to take those services. 
242 18 C.F.R. § 385.713(b); see also 16 U.S.C. § 825l(a) (stating that parties 
“aggrieved by an order issued by the Commission in a proceeding . . . may apply for a 
rehearing within thirty days after the issuance of such order”). 
243 Reliable Automatic Sprinkler Co., Inc. v. Consumer Prod. Safety Comm’n,           
324 F.3d 726, 731 (D.C. Cir. 2003) (“Final agency action ‘mark[s] the consummation of 
the agency’s decision making process’ and is ‘one by which rights or obligations have 
been determined, or from which legal consequences will flow’”) (quoting Bennett v. 
Spear, 520 U.S. 154, 178 (1997)). 
244 December Order, 193 FERC ¶ 61,217 at P 219. 
245 Id.

Docket No. EL25-49-002, et al. 
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for paper briefing “is interlocutory:  it constitutes a procedural step that does not impose 
an obligation, deny a right, or fix some legal relationship as a consummation of the 
administrative process.”246  Without a final decision on the rates, terms, and conditions 
for the new transmission services, it is “premature” to argue or evaluate on rehearing 
whether those as-yet-undeveloped services would be unduly discriminatory.247  At 
bottom, “the claimed harms are based on speculation regarding potential action that the 
Commission could take, rather than any action the Commission has actually taken.”248  
Accordingly, because Commission action is not final and is to be succeeded by further 
Commission action, we dismiss the undue discrimination argument.249 
 In any event, we also dismiss the undue discrimination argument for the 
independent reason that it is outside the scope of this proceeding.  This proceeding 
addresses Eligible Customers taking transmission service on behalf of Eligible Load with 
associated generation, such as through Co-Location Arrangements and BTMG 
 
246 Algonquin Gas Transmission, LLC, 175 FERC ¶ 61,150, at PP 1, 5-8 (2021); 
see also Kan. Elec. Power Coop., Inc., 181 FERC ¶ 61,017, at P 10 (2022) (finding that, 
because “the Commission found that its preliminary analysis indicated that the Formal 
Challenge and Complaint raised issues of material fact that could not be resolved on the 
record before the Commission and are more appropriately addressed in hearing and 
settlement judge procedures,” “here, Commission action is not final and is to be 
succeeded by further Commission action,” thus “a request for rehearing may be 
dismissed”); City of Hamilton, Ohio, 82 FERC ¶ 61,349, at 62,359 (1998) (“Setting this 
matter for a trial-type hearing does not impose an obligation, deny a right, or fix some 
legal relationship as a consummation of the administrative process.”). 
247 Algonquin Gas Transmission, 175 FERC ¶ 61,150 at P 8; see also, e.g., F.T.C. 
v. Standard Oil Co. of Cal., 449 U.S. 232, 244 n.11 (1980) (Standard Oil) (explaining the 
fact that a “challenge may be mooted in adjudication warrants the requirement that 
[party] pursue adjudication, not shortcut it”); MediNatura, Inc. v. Food & Drug Admin., 
998 F.3d 931, 939 (D.C. Cir. 2021); CSX Transp., Inc. v. Surface Transp. Bd., 774 F.3d 
25, 30 (D.C. Cir. 2014) (explaining that it is a “good sign” that action is non-final when 
further agency processes may eliminate need for review).  
248 Algonquin Gas Transmission, 175 FERC ¶ 61,150 at P 8. 
249 See, e.g., Cove Mountain Solar, LLC, 179 FERC ¶ 61,179, at P 7 (2022) 
(dismissing, in part, rehearing request on finality grounds because the Commission had 
established hearing and settlement judge procedures); Westlands Transmission, LLC,              
177 FERC ¶ 61,175, at P 4 (2021); BridgeTex Pipeline Co., LLC, 164 FERC ¶ 61,111,            
at PP 10-12 (2018); Pac. Gas & Elec. Co., 162 FERC ¶ 61,246, at PP 6-7 (2018); Talen 
Energy Mktg., LLC, 158 FERC ¶ 61,077, at PP 3-4 (2017).

Docket No. EL25-49-002, et al. 
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arrangements.250  In an order issued concurrently, the Commission is initiating a separate 
show cause proceeding in Docket No. EL26-67-000 to address, among other things, 
whether the Tariff remains just and reasonable and not unduly discriminatory or 
preferential without provisions addressing transmission services that reflect flexible large 
loads251 that are willing and able to limit their energy withdrawals from the transmission 
system under certain conditions.  Accordingly, it is beyond the scope of this 
proceeding—and within the scope of the separate proceeding—to argue that the new 
transmission services should be extended to Eligible Customers taking transmission 
service on behalf of flexible large loads.  We thus dismiss this argument as outside the 
scope of this proceeding.252  The Supreme Court has made clear that the Commission 
“enjoys broad discretion in determining how best to handle related, yet discrete, issues in 
terms of procedures.”253  The Supreme Court has “expressly approved a[] . . . 
Commission decision to treat [an] issue separately where a different proceeding would 
generate more appropriate information and where the agency was addressing the 
question”254—as is true as to the other proceeding.  As courts have further recognized, 
“[w]hile the statute requires the Commission to act upon a finding that rates . . . are unjust 
or unreasonable, it nowhere mandates that having made such a finding with respect to a 
discrete issue, the Commission must reopen and reevaluate all other aspects of the filed 
rate.”255  Here, while the Commission addresses Co-Location Arrangements and BTMG, 
those findings do not necessitate that the Commission reevaluate transmission services 
that Eligible Customers take on behalf of other types of load.256 
 
250 See, e.g., December Order, 193 FERC ¶ 61,217 at P 2. 
251 Flexible large loads are a subset of large loads that are not co-located with 
generation but that are willing and able to limit their use of the transmission system under 
certain conditions.  
252 See PJM Interconnection, L.L.C., 126 FERC ¶ 61,030, at P 16 (2009); see also 
La. Pub. Serv. Comm’n v. Entergy Corp., 169 FERC ¶ 61,179, at P 9 (2019); N.Y. Indep. 
Sys. Operator, Inc., 127 FERC ¶ 61,042, at P 26 (2009); Union Elec. Co., 113 FERC 
¶ 61,320, at P 8 (2005); Cal. Indep. Sys. Operator Corp., 113 FERC ¶ 61,133, at P 24 
(2005). 
253 Mobil Oil, 498 U.S. at 230-31; see supra note 226. 
254 Mobil Oil, 498 U.S. at 230-31.  
255 Colo. Off. of Consumer Couns. v. FERC, 490 F.3d 954, 956 (D.C. Cir. 2007). 
256 Industrials Request for Clarification or Rehearing at 6-7, 13-14.

Docket No. EL25-49-002, et al. 
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 In any event, while we dismiss the undue discrimination argument for the reasons 
explained above, we address the argument below to provide clarification to the parties.  
As relevant here, Industrials argue that it is unduly discriminatory for “load-only 
customers with load flexibility” to not be eligible for the new transmission services.257  
Industrials contend this creates undue discrimination “between customers with generation 
and customers without generation,” who Industrials state “can curtail their load at key 
times and control the amount of transmission service they use and when they use it.”258  
We refer in this subsection to these “load-only customers with load flexibility,” as 
described by Industrials, as “flexible loads.” 
 The Commission “has wide discretion to determine what constitutes undue 
discrimination.”259  Discrimination is undue when there is a difference in rates or terms 
between similarly situated entities that is not justified by some legitimate factor.260  
“[D]istinct operating characteristics” can render entities not similarly situated.261  Here, a 
relevant distinct operating characteristic is that Eligible Load has an associated generator 
(Co-Located Generator or BTMG) as part of the Co-Location Arrangement or load 
configured with BTMG, and flexible load does not.  The presence of these associated 
generators is a material factor in analyzing eligibility for the new transmission services.  
We anticipate, based on the record here, that Eligible Customers taking transmission 
 
257 Id. at 13-14. 
258 Id.  More generally, Industrials argue that the new transmission services should 
be extended to all transmission customers.  Id.  Because we dismiss the undue 
discrimination argument as nonfinal and outside of scope, we need not address the 
argument that the new transmission services should be extended to all transmission 
customers (an even broader, and thus less similar, category).  Moreover, we have, in the 
December Order and in this order, sufficiently discussed eligibility for the new 
transmission services, including by explaining that it is not unduly discriminatory to limit 
the new transmission services to Eligible Customers taking transmission service on 
behalf of Eligible Load, such that we need not further address extending the services to 
all transmission customers. 
259 Mo. River Energy Servs. v. FERC, 918 F.3d 954, 958 (D.C. Cir. 2019) (citation 
modified).  For purposes of the undue discrimination analysis in this order, when we refer 
to Eligible Customers taking transmission service on behalf of Eligible Load as not 
similarly situated to Eligible Customers taking transmission service on behalf of flexible 
load, we are referring to Eligible Customers only insofar as they take transmission 
service on behalf of specific Eligible Loads or flexible loads. 
260 Sw. Power Pool, Inc., 192 FERC ¶ 61,058, at P 175 (2025). 
261 Sw. Power Pool, Inc., 193 FERC ¶ 61,198, at P 82 (2025).

Docket No. EL25-49-002, et al. 
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services on behalf of Eligible Loads would rely regularly in whole or in part on their 
associated generators, not on the transmission system, while Eligible Customers taking 
transmission services on behalf of flexible loads generally would rely entirely on the 
transmission system, even as they sometimes shift the amount of energy they take.  This 
dynamic creates different transmission system usage, which is relevant to transmission 
services, charges, and planning.262 
iii. 
Contract Demand  
(a) 
Request for Rehearing 
 Exelon and FirstEnergy argue that the Commission has departed from decades of 
precedent that NITS is based on the entire gross load of the Network Customer, and the 
Commission failed to adequately explain its departure.263  Exelon and FirstEnergy 
highlight, for example, the Commission’s statement that it would be inconsistent with 
cost causation principles to require Eligible Customers taking transmission service on 
behalf of Co-Located Loads that limit their energy withdrawals to take NITS on a gross 
demand basis.264  Exelon and FirstEnergy allege that the Commission recognized that 
 
262 For the reasons in this Part, we also reject Industrials’ request for clarification 
on this issue.  Industrials Request for Clarification or Rehearing at 13-14.   
263 Exelon and FirstEnergy Request for Rehearing at 22-26 (citing Nat’l R.R. 
Passenger Corp. v. PPL Elec. Utils. Corp., 173 FERC ¶ 61,043 (2020) (Amtrak); Fla. 
Power & Light, 113 FERC ¶ 61,290 (2005), order on reh’g, 116 FERC ¶ 61,012 (2006), 
aff’d, 264 F. App’x 4 (D.C. Cir. 2008) (Florida Power & Light); Idaho Power Co.,      
106 FERC ¶ 61,329 (2004) (Idaho Power); Ameren Servs. Co. v. Prairieland Energy Inc., 
131 FERC ¶ 61,125 (2010) (Ameren); Ariz. Pub. Serv. Co., 151 FERC ¶ 61,191 (2015) 
(APS); Preventing Undue Discrimination & Preference in Transmission Serv., Order            
No. 890, 118 FERC ¶ 61,119, order on reh’g, Order No. 890-A, 121 FERC ¶ 61,297 
(2007), order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh’g, 
Order No. 890-C, 126 FERC ¶ 61,228, order on clarification, Order No. 890-D,                  
129 FERC ¶ 61,126 (2009); Promoting Wholesale Competition Through Open Access                           
Non-Discriminatory Transmission Servs. by Pub. Utils.; Recovery of Stranded Costs by 
Pub. Utils. & Transmitting Utils., Order No. 888, FERC Stats. & Regs. ¶ 31,036 (1996) 
(cross-referenced at 75 FERC ¶ 61,080), order on reh’g, Order No. 888-A, FERC Stats. 
& Regs. ¶ 31,048 (cross-referenced at 78 FERC ¶ 61,220), order on reh’g, Order                
No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC           
¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Pol’y Study Grp. v. 
FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. N.Y. v. FERC, 535 U.S. 1 (2002). 
264 Exelon and FirstEnergy Request for Rehearing at 28 (citing December Order, 
193 FERC ¶ 61,217 at P 199).

Docket No. EL25-49-002, et al. 
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these customers use the transmission system for some services, such as regulation and 
black start, but for the customer not to use the system for other services makes the 
customer partially integrated, contrary to Order No. 888-A.265  Exelon and FirstEnergy 
contend that the Commission has consistently rejected attempts to create a new third type 
of transmission service by parties whose reasons are exactly the same as the reasons the 
Commission used to justify its decision to establish Contract Demand transmission 
service based on net load, such as the notion that Co-Located Loads impose less burden 
on the grid.  Exelon and FirstEnergy argue that the assessment of NITS is not based on 
actual use, that Network Customers pay the full rate but NITS charges are allocated based 
on contribution to system peak.266  Exelon and FirstEnergy contend that Network Load 
needs to be able to call on service regardless of actual usage and utilities have an 
obligation to serve that load. 
(b) 
Determination 
 We continue to find that it is just and reasonable to charge for FCD and NFCD 
transmission services based on the contract demand.267  We disagree with Exelon and 
FirstEnergy’s arguments that the Commission erred in not requiring the new FCD and 
NFCD transmission services be charged on a gross load basis and that this decision 
violates precedent.268  As an initial matter, Exelon and FirstEnergy appear to suggest that 
the charges for these services would be based “on actual use” or “on net . . . load.”269  As 
explained in the December Order, however, transmission customers taking the new FCD 
or NFCD transmission service would “be charged based on their contract demand 
irrespective of usage.”270  We continue to find that this is a just and reasonable alignment 
of costs and benefits.271  In particular, for the new FCD transmission service, because 
transmission customers taking this service would agree to limit withdrawals to the 
 
265 Id. at 24. 
266 Id. at 26-29 (citing Indicated TOs June 3, 2025 Answer, Powers Decl.). 
267 December Order, 193 FERC ¶ 61,217 at P 2. 
268 Exelon and FirstEnergy Request for Rehearing at 22-30. 
269 Id. 
270 December Order, 193 FERC ¶ 61,217 at PP 211, 216 (“Eligible Customers 
taking the [NFCD] transmission service on behalf of Co-Located Loads will be charged 
for transmission and ancillary services on an as-reserved contract demand basis, based on 
the reserved contract demand amount of transmission service (except as noted[)].”).   
271 Id.

Docket No. EL25-49-002, et al. 
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contract demand through the mandatory implementation of necessary control 
technologies and/or protection systems, PJM would only plan the transmission system, 
procure generation capacity, and be obligated to provide transmission service up to that 
contract demand.272  Similarly, for the new NFCD transmission service, PJM would only 
be obligated to provide transmission service up to the reserved contract demand when 
there is sufficient available transmission capacity to provide the requested service.273  If 
the transmission customers taking the new FCD and NFCD transmission services were 
charged for that service on a gross load basis, they could be charged for more load than 
PJM is obligated to plan for, procure generation capacity for, or otherwise serve when 
transmission capacity is available.  And—because these customers would be charged 
based on their contract demand irrespective of usage—they would be unable to avoid 
load-ratio cost responsibility by modifying their load at a particular time.274  
 Exelon and FirstEnergy argue that the new contract demand transmission services 
are inconsistent with Commission precedent.275  Exelon and FirstEnergy contend that the 
Commission in the December Order contravened Order No. 888-A, in which the 
Commission rejected the notion of Network Customers “partially integrat[ing]” or 
“splitting a discrete load” because “such a split system creates the potential for a 
customer to game the system thereby evading some or all of its load-ratio cost 
responsibility for network services.”276  We continue to find that the new contract 
demand transmission services do not violate Order No. 888-A.277  Most simply, Order 
No. 888-A rejected splitting load between NITS and PTPS at the same point of 
delivery.278  That kind of splitting between transmission services at the same point of 
delivery remains barred under the December Order:  Eligible Customers also cannot split 
 
272 Id.; see also id. PP 215-216 (explaining that an Eligible Customer taking NFCD 
transmission service may reserve service as needed when the service is available, and the 
Eligible Customer will be charged on an as-reserved contract demand basis). 
273 Id.; see also id. PP 215-216 (explaining that an Eligible Customer taking NFCD 
transmission service may reserve service as needed when the service is available, and the 
Eligible Customer will be charged on an as-reserved contract demand basis). 
274 Id. P 211. 
275 Exelon and FirstEnergy Request for Rehearing at 22-30. 
276 Id. at 23-24 (quoting Order No. 888-A, FERC Stats. & Regs. ¶ 31,048                    
at 30,259) (internal quotation marks omitted). 
277 December Order, 193 FERC ¶ 61,217 at P 211. 
278 Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,260.

Docket No. EL25-49-002, et al. 
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load between NITS and FCD or NFCD transmission service at the same point of delivery.  
Further, under the new contract demand services, load is neither split nor partially 
integrated.  Instead, load is capped at contract demand and Eligible Customers taking 
transmission service on behalf of Co-Located Loads are charged for that contract 
demand, irrespective of usage.  Moreover, the rationale underlying Order No. 888-A—
gaming—is also not present here.279  The new contract demand transmission services will 
help avoid a cost shift to other transmission customers because Eligible Customers will 
not be able to reduce their load-ratio share to avoid paying transmission costs or capacity 
costs because their amount of FCD transmission service is fixed.280   
 Exelon and FirstEnergy further argue that the Commission contravened Order              
No. 888-A “[b]ecause the Commission has recognized that the [contract demand 
transmission service] customers use the transmission system for some services (such as 
load following and black start),” which would render those customers “partially 
integrated.”281  We disagree.  Receiving ancillary services, such as regulation and black 
start, does not “integrate” a transmission customer into the transmission network—and 
particularly not in the manner that NITS does.  Specifically, Order No. 888-A clarified 
that a “request for network service is a request for the integration of a customer’s 
resources and loads,”282 and a PTPS customer is not integrated, as recognized by Order 
 
279 Id.  
280 December Order, 193 FERC ¶ 61,217 at P 211.  We also note that the 
Commission justified its findings in Order No. 888-A by discussing “several fundamental 
operational problems associated with allowing partial network service.”  Order               
No. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,260.  Those operational problems are not 
raised or present here because neither FCD nor NFCD transmission service are based on 
the Eligible Customer’s load ratio.  Further, Exelon and FirstEnergy suggest that the 
December Order is inconsistent with Order No. 890.  Exelon and FirstEnergy Request for 
Rehearing at 25-26 (citing Order No. 890, 118 FERC ¶ 61,119, order on reh’g, Order                          
No. 890-A, 121 FERC ¶ 61,297, order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299 
(2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228, order on clarification, 
Order No. 890-D, 129 FERC ¶ 61,126).  While they do not cite a particular portion, they 
appear to be referring to a section that reiterates the already discussed portion of Order 
No. 888-A.  Order No. 890, 118 FERC ¶ 61,119 at P 1619 (citing Order No. 888-A, 
FERC Stats. & Regs. ¶ 31,048 at 30,260-61).  Our findings as to Order No. 888-A thus 
apply to Exelon and FirstEnergy’s citation to Order No. 890. 
281 Exelon and FirstEnergy Request for Rehearing at 24. 
282 Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,260.

Docket No. EL25-49-002, et al. 
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No. 888-A.283  Nonetheless, PTPS customers pay for and use ancillary services, including 
regulation service.  Therefore, whether an Eligible Customer taking transmission service 
on behalf of Co-Located Load could receive ancillary services and/or black start service 
has no bearing on whether it is “integrated” as a Network Customer.   
 Exelon and FirstEnergy also argue that the December Order is inconsistent with 
other Commission precedent.284  These cases do not undermine the December Order.  In 
several cited cases, Network Customers chose to take NITS and sought to receive the 
benefits of NITS, specifically the right to withdraw energy from the transmission system 
when their own resources were not available, while arguing that they should be charged a 
lower rate based on their usage.285  For example, Amtrak relied on the transmission 
system when the nearby generator was not available, and sought to maintain that 
arrangement and ability to withdraw energy to meet its gross load at any time, while 
paying NITS.286  Here, the new FCD and NFCD transmission services set up new 
obligations and benefits—as well as charges on that new basis.287  For example, under 
 
283 Id. at 30,259-60 (presenting binary of “fully integrated or not integrated”—with 
full NITS or no NITS, respectively—in opposition to “partially integrated,” which would 
include NITS and PTPS). 
284 Exelon and FirstEnergy Request for Rehearing at 23-30 (citing Amtrak,                 
171 FERC ¶ 61,237, order on reh’g, 173 FERC ¶ 61,043 (2020); Florida Power & Light, 
113 FERC ¶ 61,290, order on reh’g, 116 FERC ¶ 61,012, aff’d, 264 F. App’x 4; Idaho 
Power, 106 FERC ¶ 61,329; Ameren, 131 FERC ¶ 61,125; APS, 151 FERC ¶ 61,191). 
285 E.g., Amtrak, 173 FERC ¶ 61,043 at P 12 (“What Amtrak seeks to do is carve 
out from network service charges the power supplied by Safe Harbor.  Such an outcome 
is impermissible under the PJM Tariff and inconsistent with the nature of NITS.”). 
286 See id. P 13 (rejecting Amtrak’s rehearing request and explaining that “Amtrak 
seeks the ability to select when it will use and pay for NITS (i.e., only when inflows 
occur through PPL’s Manor Substation”)). 
287 December Order, 193 FERC ¶ 61,217 at PP 208, 210, 211, 212.  Indeed, the 
December Order also responds to new circumstances not present in the cited cases—
namely, the proliferation of potential Co-Location Arrangements.  Even if the cited cases 
were controlling here, we find these new circumstances would warrant the Commission’s 
decision to charge for FCD and NFCD transmission services based on the contract 
demand.

Docket No. EL25-49-002, et al. 
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FCD transmission service, the Eligible Customer can rely on the service only up to the 
level of its contract demand.288 
 In particular, Exelon and FirstEnergy maintain that the December Order is 
inconsistent with Florida Power & Light, which they characterize as standing for the 
proposition that “the gross load construct [i]s most appropriate,” “even in the case of 
physical impossibility of serving the entire load.”289  As an initial matter, there is no 
“physical impossibility exception”290 in the December Order because the new FCD and 
NFCD transmission services are based on legally capped demand, not “physical 
impossibility.”291  Specifically, while in Florida Power & Light the “physical 
impossibility” was a constraint on the transmission system, which prevented the entire 
load from being served by the transmission system,292 no such physical constraint on the 
transmission system exists for an Eligible Customer taking FCD and/or NFCD 
transmission service on behalf of a Co-Located Load.  Rather, such Eligible Customers 
may elect to take transmission service at a contract demand level less than the amount of 
the entire load and commit to limiting their withdrawals from the transmission system to 
the contract demand level.  Regardless, in Florida Power & Light, the Commission only 
discussed “physical impossibility” in dicta.293  In that discussion, the Commission 
 
288 Id.  We further reiterate that the absence of this type of option is unjust and 
unreasonable.  Id. P 177.  
289 E.g., Exelon and FirstEnergy Request for Rehearing at 24-25. 
290 Florida Power & Light, 113 FERC ¶ 61,290 at P 7.   
291 December Order, 193 FERC ¶ 61,217 at PP 208, 210, 211, 212.  To the extent 
Exelon and FirstEnergy characterize their argument addressed in this Part as directed 
toward our “unjust and unreasonable” findings and not the replacement rate, Exelon and 
FirstEnergy Request for Rehearing at 22-23, we reject this argument based on the same 
substantive reasons included in this Part.   
292 Florida Power & Light, 113 FERC ¶ 61,290 at PP 7-8.   
293 Id.  The Commission began by generally rejecting the prospect of alternative 
proposals from individual customers because of the potential administrative and undue 
discrimination concerns with setting individual-customer-specific rates (but the 
Commission did approve the prospect of alternative proposals from utilities).  Id. P 6.  In 
other words, the cited adjudications, see, e.g., Exelon and FirstEnergy Request for 
Rehearing at 23-25; see also id. at 27, are additionally inapposite here to the extent they 
involved proceedings where only individual customers that claimed to limit their use of 
the transmission system sought to alter the rates, terms, and conditions of its transmission 
service and obtain rates and terms for themselves.

Docket No. EL25-49-002, et al. 
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nonetheless did not even rule out the prospect of considering “physical impossibility” in a 
more generally applicable setting where the impossibility could be administered, verified, 
and backed by technological and legal constructs—rather than on an ad hoc basis due to a 
transmission customer’s mere assertions that it was particularly deserving of a              
specially-designed and administered service.294   
iv. 
Alleged Alternatives to FCD and NFCD 
Transmission Services 
(a) 
Request for Rehearing 
 Exelon and FirstEnergy contend that the Commission “fail[ed] to demonstrate that 
[the new transmission services] are just and reasonable” because there are already 
existing mechanisms for customers to reduce load or use other generation in order to 
reduce withdrawals.295  Exelon and FirstEnergy maintain that PJM’s demand response 
rules are available to Co-Located Loads and the Commission fails to explain why such 
rules are inadequate here.  Indeed, Exelon and FirstEnergy assert, the Commission stated 
that those rules are just and reasonable for Co-Located Loads taking NITS.  
(b) 
Determination 
 We do not find Exelon and FirstEnergy’s argument availing.  The mere fact that 
there may be preexisting mechanisms in the Tariff to accomplish something (even 
assuming that they are equivalent, which we do not) does not mean that adding an 
additional mechanism is not just and reasonable.  Exelon and FirstEnergy offer no 
justification or citation to support the proposition that having multiple provisions targeted 
at similar objectives is not just and reasonable.  
 Further, demand response operates differently from the contract demand 
transmission services.  In the first place, demand response is not a transmission service.  
And demand response presents a different set of benefits and burdens—NFCD 
transmission service would be curtailed earlier than demand response resources would be 
called on and can be instructed to curtail without any notification (unlike most demand 
response resources).296  FCD transmission service, on the other hand, is a firm 
transmission service with the same curtailment priority as existing firm transmission 
 
294 Florida Power & Light, 113 FERC ¶ 61,290 at PP 7-8.  
295 Exelon and FirstEnergy Request for Rehearing at 36-37. 
296 December Order, 193 FERC ¶ 61,217 at P 215; see also infra Part VI.G.4.

Docket No. EL25-49-002, et al. 
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services, at the level of contract demand.297  In addition, PJM would not plan for any 
future load growth for either FCD or NFCD transmission service once the contract 
demand level of each transmission service is established.  As to Interim NITS, that 
transmission service serves a different function than demand response because it allows 
Eligible Customers to begin taking a limited, non-firm transmission service on behalf of 
Co-Located Load before the transmission system is capable of reliably providing NITS at 
their requested level.  
v. 
Protection Systems 
(a) 
Request for Rehearing 
 Exelon and FirstEnergy argue that the Commission’s emphasis on protection 
systems is arbitrary and capricious because it is in tension with the Commission’s open 
access policies.  Exelon and FirstEnergy assert that generators have an interest in 
designing captive arrangements where customers cannot access alternative supply, which 
is contrary to the Commission’s open access policies in Order No. 888.298  Exelon and 
FirstEnergy argue that generators will convert their interconnection facilities into 
transmission assets and then install relay systems that make load captive to its 
generation.299  Exelon and FirstEnergy view this arrangement as akin to the problem of 
transmission owners using their control of transmission facilities to refuse to deliver 
energy produced by competitors or to deliver competitors’ power on less favorable 
terms.300 
 Exelon and FirstEnergy argue that the Commission erred in minimizing the fact 
that protection systems can and have failed.301  Exelon and FirstEnergy point out that the 
Commission recognizes that protection systems fail, and to address this risk, directed 
PJM to apply a penalty rate for the new transmission services.  But Exelon and 
FirstEnergy allege that assessing penalties after the fact does not remediate the reliability 
implications of faulty protection systems.  Exelon and FirstEnergy also argue that 
protection systems “do not protect the grid from real impacts that occur even when there 
 
297 December Order, 193 FERC ¶ 61,217 at P 208. 
298 Exelon and FirstEnergy Request for Rehearing at 39-40. 
299 Id. at 40. 
300 Id. (citing N.Y. v. FERC, 535 U.S. at 8-9). 
301 Id. at 39-41.

Docket No. EL25-49-002, et al. 
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is consumption by a co-located customer but no net withdrawal, such as the impacts of 
load and voltage spikes and oscillations.”302 
(b) 
Determination 
 We address both arguments in turn.  First, the contemplated use of necessary 
control technologies and/or protection systems is not inconsistent with the Commission’s 
open access policies.  Co-Location Arrangements are voluntary.  The December Order 
does not mandate that any Co-Located Load or Co-Located Generator enter into a                 
Co-Location Arrangement.  In other words, contrary to Exelon and FirstEnergy’s 
assertions, the Commission is not forcing any entity into being a captive customer, as 
they would have the option to connect to the transmission system and take NITS like any 
other Network Customer.  
 Second, we dismiss the argument regarding protection system failure and the risks 
they address for lack of finality.303  The December Order did not make a final decision on 
required technology and what appropriate remedies would be for failure of that 
technology.304  Instead, the December Order set those issues for paper hearing 
procedures.305  In any event, the Commission recognized that protection systems, like 
many technologies, in rare instances can fail; accordingly, the Commission ordered paper 
briefing on technical requirements to address reliability risks and remedial actions.306  We 
also note that it is possible that the remedial actions could remediate the reliability 
implications of such a failure.  Further, whatever risks are not avoided by a facility’s 
necessary control technologies and/or protection systems will be studied in the relevant 
study processes.  
 
302 Id. at 39. 
303 See supra P 106.  
304 December Order, 193 FERC ¶ 61,217 at P 177.  
305 Id. P 178.  
306 Id. P 212.

Docket No. EL25-49-002, et al. 
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vi. 
Benefits of FCD and NFCD Transmission Services 
(a) 
Request for Rehearing 
 Exelon and FirstEnergy allege that the Commission is wrong to suggest that FCD 
and NFCD transmission services will promote efficiency or change siting.307  Exelon and 
FirstEnergy argue that planning and siting depend on physics and engineering of the grid, 
not whether transmission service is charged on a gross or net load basis.  Exelon and 
FirstEnergy argue that the Commission’s decision to require FCD and NFCD 
transmission services does not change how the study process should work.  Exelon and 
FirstEnergy warn that, “[i]f transmission providers are forced to pretend a 500 MW load 
is only 50 MW, or even that it is zero . . . it will threaten reliability and resource 
adequacy.”308  Exelon and FirstEnergy maintain that no loads should be taken out of the 
broader planning process, and there is no support for the suggestion that regional 
planning needs are reduced because of FCD and NFCD transmission services.  Exelon 
and FirstEnergy argue that the Commission’s decision on PJM’s retail BTMG netting 
rules and the Commission’s concerns about resource adequacy and cost shifting cannot 
be reconciled with the Commission’s proposed structure for the new transmission 
services.309 
 Exelon and FirstEnergy state that the Commission failed to point to any other 
tariff where these new transmission services have been required by the Commission.310 
(b) 
Determination 
 As an initial matter, we dismiss this argument for lack of finality.311  The 
December Order did not make a final decision on the rates, terms, and conditions for the 
new FCD and NFCD transmission services.312  Instead, the Commission found that 
“additional record evidence is needed” and set these issues for paper hearing 
 
307 Exelon and FirstEnergy Request for Rehearing at 47-48. 
308 Id. at 48. 
309 Id. at 48-49. 
310 Id. at 36. 
311 See supra P 106. 
312 December Order, 193 FERC ¶ 61,217 at P 219.

Docket No. EL25-49-002, et al. 
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procedures.313  Without a final decision on the rates, terms, and conditions for the new 
FCD and NFCD transmission services, it is “premature” to argue or evaluate on rehearing 
whether those as-yet-undeveloped services would affect efficiency or siting.314 
 In any event, while Exelon and FirstEnergy appear to direct this argument toward 
the replacement rate, we addressed these topics in our discussion of the Commission’s 
FPA section 206 step one finding above.  In short, we continue to find that the Tariff is 
unjust and unreasonable because it does not include transmission services that reflect 
Eligible Customers taking service on behalf of Co-Located Loads that are willing and 
able to limit their energy withdrawals from the transmission system under certain 
conditions—and that this lack of such transmission services is economically 
inefficient.315  We direct the new FCD and NFCD transmission services as a just and 
reasonable way to address this issue (among others).  And, while siting choices can 
reduce the need for Network Upgrades, that fact does not undermine our finding that 
requiring Eligible Customers taking service on behalf of Co-Located Loads to take NITS 
for these loads leads to an unacceptable probability of inefficient outcomes by requiring 
more or more costly Network Upgrades than would potential new FCD and NFCD 
transmission services.316  We similarly reiterate that the need for many Network 
Upgrades are caused by the amount of MW flow on the transmission system even though 
the need for certain Network Upgrades are not (e.g., they may be caused by stability or 
voltage-related issues).317  Therefore, as Exelon and FirstEnergy concede, under a 
transmission service that reflects willingness and ability to limit energy withdrawals, “if 
the load installs systems aimed at limiting its use of the grid, those might change the 
system impacts and need for upgrades.”318  Likewise, while PJM will only plan the 
transmission system for FCD transmission service based on the level of contract demand 
as a matter of transmission capacity, PJM will still be able to consider the gross load for 
analyzing certain issues such as stability and short circuit.319  
 
313 Id. 
314 Algonquin Gas Transmission, 175 FERC ¶ 61,150 at P 8. 
315 December Order, 193 FERC ¶ 61,217 at P 177. 
316 Id. PP 177, 199, 205. 
317 See Exelon and FirstEnergy Request for Rehearing at 47-48. 
318 Id. at 19-20; see also id. at 48. 
319 December Order, 193 FERC ¶ 61,217 at P 210.

Docket No. EL25-49-002, et al. 
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 The Commission’s findings related to retail BTMG netting are not inconsistent 
with the findings related to the new FCD and NFCD transmission services.320  The 
Commission stated that “the existing BTMG netting rules in the PJM Tariff [are] unjust 
and unreasonable” because, “under the existing Tariff, loads with BTMG are not fully 
accounted for in resource adequacy planning.”321  The Commission explained that 
“[s]uch loads must nevertheless be served, however, allowing them to lean on the PJM 
system when the [BTMG] is on a full or partial outage or if the load exceeds the rating of 
the [BTMG].”322  Eligible Customers taking service on behalf of Co-Located Load will 
be treated differently under FCD and NFCD transmission services—“PJM will have no 
obligation to serve the Eligible Customer beyond the contract demand.”323 
 Exelon and FirstEnergy argue that the Commission failed to point to any other 
tariff where these new transmission services have been required by the Commission.324  
This argument is irrelevant because the Commission need not point to another FPA 
section 206 proceeding where the Commission set an identical replacement rate in order 
to set a replacement rate.   
vii. 
Reliability and New Transmission Services  
(a) 
Request for Rehearing 
 Exelon and FirstEnergy argue that the Commission overlooked important 
reliability concerns in establishing new transmission services, including that loads impact 
the system even when there is no net power draw on the system.325  Exelon and 
FirstEnergy assert that gross load is being followed by resources on the grid at all times, 
thus impacting the system.  Exelon and FirstEnergy assert that the Commission has not 
explained how reliability planning should proceed when large loads may be incentivized 
to exceed their contract demand limit for transmission service.  Exelon and FirstEnergy 
contend that the Commission overlooked resource adequacy risks in establishing Interim 
NITS.  Exelon and FirstEnergy allege that it is unclear how it will be determined that 
load may be served reliably and the Commission failed to give PJM guideposts to make 
 
320 See Exelon and FirstEnergy Request for Rehearing at 48-49.  
321 December Order, 193 FERC ¶ 61,217 at P 179. 
322 Id. P 186. 
323 Id. P 211.  
324 Exelon and FirstEnergy Request for Rehearing at 36; see also id at 27, 29, 35. 
325 Id. at 49-51.

Docket No. EL25-49-002, et al. 
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such a determination.  Exelon and FirstEnergy state that it is unknown how and by what 
standards load would be curtailed and whether curtailment is an adequate response to the 
need to follow gross load moment-by-moment, and thus the transmission service options 
cannot be just and reasonable.  
 Exelon and FirstEnergy argue that, as to Interim NITS, the Commission has not 
accounted for reliability risks, not knowing when or how curtailments would be 
implemented, as the Commission has asked for briefing on when Eligible Customers 
taking this service would be curtailed.326  Exelon and FirstEnergy express concern that 
future state legislation may create inconsistencies among Co-Located Load in different 
states.  
(b) 
Determination 
 We dismiss these arguments for lack of finality.327  The December Order did not 
make a final decision on several issues relevant to this argument.328  Instead, the 
Commission found that “additional record evidence is needed” and established paper 
hearing procedures on:  the rates, terms, and conditions for the new transmission services; 
interconnection requirements and operational practices for special protection schemes; 
the communications, alarm, SCADA,329 or other requirements necessary for PJM to 
monitor Co-Located Load transmission system demand status, ensure that relay settings 
are consistent with special protection scheme design, and inform system operator action 
in order to limit withdrawals that exceed the amount of contract demand; and the 
procedures to govern circumstances under which PJM curtails an Eligible Customer 
taking the three new transmission services.330  Without a final decision on these issues, it 
is premature to argue or evaluate on rehearing whether the Commission overlooked 
important reliability concerns in establishing the new transmission services.331  In any 
event, as to the new FCD and NFCD transmission services, the December Order did not 
 
326 Id. at 37. 
327 See supra P 106. 
328 December Order, 193 FERC ¶ 61,217 at P 219. 
329 Supervisory Control and Data Acquisition (SCADA) is a system of remote 
control and telemetry used to monitor and control the transmission system.  See NERC 
Glossary of Terms 42, https://www.nerc.com/globalassets/standards/reliability-
standards/glossary_of_terms.pdf. 
330 December Order, 193 FERC ¶ 61,217 at P 219. 
331 See Algonquin Gas Transmission, 175 FERC ¶ 61,150 at P 8.

Docket No. EL25-49-002, et al. 
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prohibit PJM or the transmission owners from performing any particular studies that may 
be necessary or mandate that the level of contract demand would be the only impact 
studied.  For example, when PJM or the transmission owners consider factors unrelated 
to the contract demand of the Co-Located Load, the December Order did not preclude use 
of the complete dynamic or EMT model of the Co-Located Load, regardless of what level 
or type of transmission service the Eligible Customer has requested. 
 On Interim NITS, specifically, the Commission established paper hearing 
procedures on “What are the appropriate procedures to govern the circumstances under 
which PJM curtails an Eligible Customer taking the interim, non-firm transmission 
service . . . on behalf of a Co-Located Load during emergency procedures?”332  The 
Commission thus did not make a final decision on this issue either.  In any event, the 
Commission stated that said Interim NITS “would only be available to the extent PJM 
determines that it can provide some level of interim service reliably.”333  
viii. 
Major Questions Doctrine 
(a) 
Request for Rehearing 
 Exelon and FirstEnergy assert that the Commission’s replacement rate violates the 
major questions doctrine.334  Exelon and FirstEnergy argue that the Commission has no 
authority under FPA section 206 to provide unduly preferential treatment to a certain 
category of customers, but that the Commission established a replacement rate favoring 
Co-Located Load without reasoned explanation.   
(b) 
Determination 
 We disagree with Exelon and FirstEnergy that the December Order violates the 
major questions doctrine.  The major questions doctrine applies in certain “extraordinary 
cases” involving an agency action that results in a “transformative expansion” of its 
authority—especially over issues of great “economic and political significance.”335  In 
 
332 December Order, 193 FERC ¶ 61,217 at P 219. 
333 Id. P 200. 
334 Exelon and FirstEnergy Request for Rehearing at 52. 
335  W. Va. v. EPA, 597 U.S. 697, 721, 724 (2022) (citations and quotations 
omitted).

Docket No. EL25-49-002, et al. 
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such “extraordinary cases,” courts might “hesitate before concluding that Congress meant 
to confer such authority.”336 
 We conclude that this proceeding is not an “extraordinary case” such that the 
December Order does not implicate the major questions doctrine.  In West Virginia v. 
Environmental Protection Agency, the U.S. Supreme Court identified a number of 
indicators that tend to identify a case as extraordinary, none of which are present here.  
First, the December Order does not involve a “transformative expansion” of the FPA or a 
reimagining of the Commission’s long-held interpretation of that statute.337  Instead, the 
Commission acted, as it has previously, by finding that an existing practice was unjust 
and unreasonable and proceeding to establish a just and reasonable replacement rate.338  
Second, the December Order does not entail the use of an “ancillary” or “little-used 
backwater” statutory provision.339  To the contrary, FPA section 206 is central to the 
Commission’s authority over the rates for transmission service in interstate commerce.340  
Third, the Commission did not in the December Order act outside of the Commission’s 
typical area of  “comparative expertise.”341  Indeed, the Commission’s regulation of the 
 
336 Id. at 721 (citations and quotations omitted). 
337 See id. at 724-25 (finding that an agency’s failure to invoke the asserted power 
in the past indicates that the major questions doctrine might apply). 
338 See, e.g., N.Y. v. FERC, 535 U.S. 1 (upholding Commission’s exercise of its 
FPA section 206 authority in its landmark Order No. 888, which established the               
pro forma OATT and established new transmission services); S.C. Pub. Serv. Auth. v. 
FERC, 762 F.3d 41 (upholding Commission’s exercise of its authority under FPA   
section 206 to remedy deficiencies in existing transmission planning practices). 
339 W. Va. v. EPA, 597 U.S. at 724, 730. 
340 See EPSA, 577 U.S. at 290 (“ensur[ing] effective transmission of electric 
power” is one of the “core objects” of the FPA”); N.Y. v. FERC, 535 U.S. at 7 (“[Section] 
205 of the FPA prohibited . . . unreasonable rates and undue discrimination with respect 
to any transmission . . . subject to the jurisdiction of the Commission, and [section] 206 
gave the [Commission] the power to correct such unlawful practices.”) (quotations and 
citations omitted); Bldg. for the Future Through Elec. Reg’l Transmission Plan. & Cost 
Allocation, Order No. 1920, 187 FERC ¶ 61,068 (2024), order on reh’g and clarification, 
Order No. 1920-A, 189 FERC ¶ 61,126, at P 175 (2024) (“FPA section 206 sets forth 
core Commission regulatory authority to remedy unjust and unreasonable rates, and 
practices affecting rates, for the transmission of electric energy in interstate commerce.”), 
order on reh’g and clarification, Order No. 1920-B, 191 FERC ¶ 61,026 (2025). 
341 W. Va. v. EPA, 597 U.S. at 729.

Docket No. EL25-49-002, et al. 
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rates, terms, and conditions of transmission service in interstate commerce sits at the core 
of the Commission’s expertise.342  Fourth, the December Order does not assert authority 
in a manner of great “economic and political significance.”343  Instead, the December 
Order makes important but discrete changes to the manner in which a subset of 
transmission customers take and pay for certain transmission services.   
 In any event, Exelon and FirstEnergy argue that the replacement rate violates the 
major questions doctrine only insofar as it exceeds the Commission’s jurisdiction or is 
unduly discriminatory or preferential.344  As explained above, the replacement rate does 
neither.   
c. 
BTMG 
i. 
Qualifying Facilities 
(a) 
December Order 
 The Commission directed PJM to revise the Tariff to revise the retail BTMG 
netting rules.345  The Commission directed PJM to propose a new MW threshold for the 
amount of load at a particular electrical location that Network Customers may net by 
using BTMG but to otherwise phase-in the elimination of netting.  Specifically, the 
Commission directed PJM to allow Network Customers already using the retail BTMG 
netting rules to continue to do so for a transition period of three years.346  Further, the 
Commission directed PJM to grandfather entities with existing contracts for the specific 
purpose of effectuating a BTMG arrangement for the current term remaining under the 
existing contract.347 
 
342 See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 49-54 (summarizing the 
Commission’s history of reforms to the rates, terms and conditions of interstate 
transmission service). 
343 W. Va. v. EPA, 597 U.S. at 721. 
344 Exelon and FirstEnergy Request for Rehearing at 52. 
345 December Order, 193 FERC ¶ 61,217 at P 221. 
346 Id. P 223. 
347 Id. P 224.

Docket No. EL25-49-002, et al. 
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(b) 
Request for Clarification and/or Rehearing 
 Industrials request clarification on whether cogeneration QFs under the Public 
Utility Regulatory Policies Act of 1978 (PURPA) will be provided access to back-up and 
maintenance power at just and reasonable rates and be credited for capacity based on the 
reliability of their generating units.348  Industrials contend that many QFs are 
cogeneration facilities, and that strong operational and financial incentives exist for 
cogeneration facilities to operate efficiently.  Industrials state that Commission 
regulations require certain QFs to meet specified efficiency standards and thus should be 
encouraged.349  Thus, Industrials argue that many QFs operate with a high capacity factor 
and reliably during transmission peaks.  Industrials accordingly seek clarification on 
whether and how the December Order will apply to cogeneration QFs.  Industrials 
contend that the removal of netting rules will “directly harm large American 
manufacturing facilities that have invested substantial resources into developing and 
maintaining on-site generation.”350  Industrials add that removing netting rules may 
contradict Commission regulations that require back-up and maintenance services for 
cogeneration QFs.  Further, Industrials argue that FCD and NFCD transmission services 
do not appear to account for forced generation outages.  For these reasons, Industrials 
request that the Commission clarify that cogeneration QFs are exempt from the “gross 
load” approach or that PJM must include a reasonable “Back-up Power” transmission 
option that retail BTMG customers, including QFs, can purchase.351 
(c) 
Determination 
 As discussed below, in response to the Industrials’ request for clarification, we 
clarify and set aside, in part, the December Order.   
 First, we clarify that the December Order’s replacement rate does not change any 
obligation under the Commission’s PURPA regulations regarding QFs’ access to 
supplementary, back-up, maintenance, and interruptible power.  The replacement rate 
applies only to Network Customers’ usage of NITS under the Tariff, and nothing in the 
replacement rate undoes the requirement in 18 C.F.R. § 292.305(b)(1) that, as to QFs, 
“each electric utility shall provide . . . Supplementary power, Back-up power, 
 
348 Industrials Request for Clarification or Rehearing at 10; see also id. at 5. 
349 Id. at 11 (citing 18 C.F.R. § 292.205 (2025)).  
350 Id. 
351 Id. at 11-13.

Docket No. EL25-49-002, et al. 
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Maintenance power, and Interruptible power.”352  While Industrials suggest that 
removing netting rules may contradict Commission regulations that require back-up and 
maintenance services for cogeneration QFs, Industrials do not explain how the 
replacement rate results in Industrials no longer being entitled to back-up and 
maintenance power under the Commission’s regulations.  In addition, Industrials do not 
explain why it is necessary for the Commission to adopt a change to “credit [QFs] for 
capacity based on the reliability of their generating units.”353 
 Second, we set aside, in part, the December Order’s directive that PJM establish a 
new MW threshold for the amount of load at a particular electrical location that Network 
Customers may net by using BTMG.354  We find that it is just and reasonable to allow 
certain cogeneration QFs that are Network Customers to be able to net by using BTMG, 
and to be exempt from the new MW threshold, as discussed below.  In the December 
Order, the Commission found that PJM’s retail BTMG rules are no longer consistent with 
cost causation principles because large loads configured in a BTMG arrangement with 
significant generation will raise cost-shifting concerns compared to loads pursuing 
smaller amounts of netting.355  Moreover, the Commission found that PJM’s existing 
retail BTMG rules may lead to both reliability and resource adequacy risks because PJM, 
per its Tariff, is obligated to serve transmission customers using BTMG but does not 
consider such customers in transmission and resource adequacy planning.356  We find that 
there is not sufficient reason, and nor do Industrials articulate such a reason on rehearing, 
to believe that these concerns are inapplicable to cogeneration QFs categorically. 
 However, we recognize, based on the record, that there may be certain industrial 
cogeneration QFs that may be integrated with load such that, when their generator trips 
offline, the load follows (rather than withdrawing energy from the transmission system).  
For example, as Industrials explain as to certain industrial cogeneration QFs, “if the 
generator goes offline, the load promptly follows because the manufacturing facility 
 
352 18 C.F.R. § 292.305(b)(1) (2025). 
353 Industrials Request for Clarification or Rehearing at 10.  
354 December Order, 193 FERC ¶ 61,217 at P 221. 
355 Id. P 186. 
356 Id.  To the extent the Commission’s clarification on this issue conflicts with the 
requested clarification, we otherwise disagree with Industrials’ request to the extent 
Industrials request rehearing in the alternative.  See Industrials Request for Clarification 
or Rehearing at 2.

Docket No. EL25-49-002, et al. 
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cannot function without the steam output from the generation process.”357  We therefore 
direct PJM, within 60 days of the date of issuance of this order, to submit on further 
compliance a process to exempt certain cogeneration QFs from the new retail BTMG 
netting rules if they demonstrate that they are integrated with load such that, when their 
generating facility trips offline, the load follows, and they thus do not present the 
reliability or resource adequacy concerns discussed in the December Order.  In 
developing its compliance proposal, PJM must ensure that the requirements for a 
cogeneration QF to make this demonstration are not unduly burdensome. 
ii. 
Capacity Obligations 
(a) 
December Order 
 The Commission found that PJM’s existing retail BTMG netting rules may lead to 
both reliability and resource adequacy risks because PJM is obligated to serve 
transmission customers using BTMG but does not consider such customers in 
transmission and resource adequacy planning.358  The Commission directed PJM to 
propose a new MW threshold for the amount of load at a particular electrical location that 
Network Customers may net by using BTMG.359  The Commission explained that such a 
threshold should reduce the reliability and resource adequacy risks that large loads may 
pose to PJM, while also allowing for Network Customers to reduce their transmission 
charges in a transparent, not unduly discriminatory fashion. 
(b) 
Request for Clarification and/or Rehearing  
 Industrials seek clarification that the removal of BTMG netting rules will only be 
applicable to transmission and specified ancillary services, not to capacity obligations.  
Industrials represent that the determination of retail customers’ capacity tags is made by 
individual electric distribution companies and that large industrial and institutional users 
have a variety of configurations and approaches to meeting their capacity 
requirements.360  Industrials contend that the Commission did not analyze the impact of 
 
357 Industrials Request for Clarification or Rehearing at 11. 
358 December Order, 193 FERC ¶ 61,217 at P 186. 
359 Id. P 221. 
360 Industrials Request for Clarification or Rehearing at 15-16.

Docket No. EL25-49-002, et al. 
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the BTMG rule changes on retail customers’ capacity obligations or address alternate 
capacity products that a retail customer with BTMG could elect.361 
(c) 
Determination 
 We deny Industrials’ clarification request and sustain the December Order.  The 
Commission’s determination that PJM’s retail BTMG netting rules are no longer just and 
reasonable rested on a finding that PJM’s existing retail BTMG netting rules may lead to 
reliability and resource adequacy risks.362  The Commission set a replacement rate to 
reduce the resource adequacy risks identified in the record.363  We recognize that 
requiring PJM to revise its retail BTMG netting rules may affect capacity obligations,364  
but in the absence of this reform, the resource adequacy problems arising from PJM’s 
existing retail BTMG netting rules would persist because PJM remains obligated to serve 
transmission customers using BTMG but under the existing rules does not consider such 
customers in resource adequacy planning.365  As to Industrials’ concerns about the impact 
of the retail BTMG netting rule changes on retail customers, we agree with Industrials 
that the RAA provisions Industrials cite directly apply to LSEs, not retail customers’ 
capacity obligations,366 and we note that, as part of our replacement rate, we established a 
grandfathering provision such that existing entities may be able to continue netting for 
the remainder of a contract entered into for the purpose of effectuating a BTMG 
arrangement.367  This grandfathering provision may also limit the impacts of the changes 
to PJM’s retail BTMG netting rules upon some entities’ capacity obligations.  In addition, 
as discussed above, we set aside, in part, the December Order and direct PJM to revise its 
Tariff to extend the three new transmission services set forth in the December Order to 
Eligible Customers taking service on behalf of load with BTMG that are willing and able 
to limit their energy withdrawals from the transmission system under certain conditions.  
Thus, Eligible Customers taking transmission service on behalf of load with BTMG that 
 
361 Id. at 16. 
362 December Order, 193 FERC ¶ 61,217 at P 186. 
363 Id. P 221. 
364 See, e.g., PJM, Intra-PJM Tariffs, RAA, Schedule 8 (Determination of 
Unforced Capacity Obligations) (5.3.0). 
365 December Order, 193 FERC ¶ 61,217 at P 186. 
366 See, e.g., PJM, Intra-PJM Tariffs, RAA, Schedule 8 (Determination of 
Unforced Capacity Obligations) (5.3.0). 
367 December Order, 193 FERC ¶ 61,217 at P 224.

Docket No. EL25-49-002, et al. 
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are willing and able to limit their energy withdrawals from the transmission system under 
certain conditions may elect to take FCD and/or NFCD transmission service, which could 
reduce capacity obligations in comparison to a BTMG arrangement where the Eligible 
Customer elects to take NITS.368 
iii. 
Unlawful Taking of Private Property 
(a) 
December Order 
 In the December Order, the Commission directed PJM to revise the retail BTMG 
netting rules in the Tariff.369 
(b) 
Request for Clarification and/or Rehearing 
 Industrials argue that the Commission’s BTMG findings effectuate an unlawful 
taking of private property without providing just compensation, in violation of the Fifth 
Amendment of the United States Constitution.  Industrials contend that there is a “per se 
taking[]” because “the owner is deprived of ‘all economically beneficial us[e]’ of the 
property due to the government action.”370  Industrials assert that certain manufacturing 
facilities with on-site generation would be “completely uneconomic.”371  Separately, 
Industrials contend that there is a regulatory taking under the factors outlined in Penn 
Central Transportation Co. v. New York City.372  In particular, Industrials state that the 
BTMG netting findings will cause, in some instances, devastating economic impacts “but 
perhaps not total deprivation.”373  Industrials also argue that the BTMG netting findings 
 
368 Id. P 211 (“PJM will only plan the transmission system and procure generation 
capacity for the contract demand—not for load growth, like it does for NITS customers—
and PJM will have no obligation to serve the Eligible Customer beyond the contract 
demand.”); id. P 218 (“The new Non-Firm Contract Demand transmission service will 
not include a charge for generation capacity.”). 
369 Id. P 221. 
370 Industrials Request for Clarification or Rehearing at 31-32 (quoting Lingle v. 
Chevron U.S.A., 544 U.S. 528, 538 (2005)).  
371 Id. at 32 (listing examples). 
372 Id. at 33 (citing Penn. Cent. Transp. v. City of N.Y., 438 U.S. 104, 124 (1978)). 
373 Id. at 33-34.

Docket No. EL25-49-002, et al. 
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upset investment-backed expectations and do not “promote or facilitate a public program 
or public good to justify the economic interference.”374  
(c) 
Determination 
 As an initial matter, we dismiss Industrials’ argument that the Commission’s 
BTMG findings effectuate an unlawful taking of private property for lack of finality.375  
The December Order did not make a final decision on the applicability and design of the 
revised retail BTMG netting rules.376  In particular, the Commission stated that it “ma[d]e 
no finding in this order on a threshold” “for the amount of load at a particular electrical 
location that Network Customers may net by using BTMG.”377  It would thus be 
premature to argue or evaluate on rehearing whether those as-yet-undeveloped retail 
BTMG netting rules effectuate an unlawful taking.378 
 In any event, the Commission has an obligation under the FPA to ensure that the 
rates, terms, and conditions of jurisdictional service are just and reasonable.  As the 
Commission found in the December Order, circumstances have changed since the 
Commission approved PJM’s retail BTMG netting rules such that these rules are no 
longer just and reasonable.379  The Commission therefore is establishing a just and 
reasonable replacement rate.  And, as the Courts have held, in the context of setting rates, 
terms, and conditions for jurisdictional service, what is just and reasonable is not a 
taking.380  Instead, in establishing a just and reasonable replacement rate, the Commission 
is balancing the respective rights and obligations of the parties and will determine that 
 
374 Id. 
375 See supra P 106. 
376 December Order, 193 FERC ¶ 61,217 at P 221. 
377 Id. 
378 Algonquin Gas Transmission, 175 FERC ¶ 61,150 at P 8. 
379 December Order, 193 FERC ¶ 61,217 at P 186. 
380 See In re Permian Basin Area Rate Cases, 390 U.S. 747, 770 (1968) (“[T]he 
just and reasonable standard of the Natural Gas Act coincides with the applicable 
constitutional standards and any rate selected by the Commission from the broad zone of 
reasonableness permitted by the Act cannot properly be attacked as confiscatory.”) 
(punctuation and citations omitted); see also N.Y. Indep. Sys. Operator, Inc., 151 FERC 
¶ 61,075, at P 63 (2015).

Docket No. EL25-49-002, et al. 
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appropriate replacement rate through the course of the paper hearing and compliance 
proceedings.381   
iv. 
Materiality Threshold 
(a) 
December Order 
 The Commission directed PJM to propose a new MW threshold for the amount of 
load at a particular electrical location that Network Customers may net by using 
BTMG.382  The Commission stated that parties would have an opportunity to comment 
on PJM’s proposed threshold before we establish this replacement rate.383 
(b) 
Request for Clarification and/or Rehearing 
 Industrials seek clarification that any retail BTMG materiality threshold 
implemented will be sufficiently high to permit traditional manufacturers and institutional 
customers to continue to net generation, consistent with actual use of the transmission 
system.384  Industrials argue that a threshold of at least 200 MW would appropriately 
recognize the major energy investments most existing industrial and institutional loads 
have made over decades, consistent with the “actual use” principle, without making 
 
381 N.Y. Indep. Sys. Operator, Inc., 151 FERC ¶ 61,075 at P 63 (citing Jersey Cent. 
Power & Light Co. v. FERC, 810 F.2d 1168, 1191 (D.C. Cir. 1987) (en banc) (Starr, J. 
concurring) ((“Unlike garden-variety takings, the requirements of the Takings Clause are 
satisfied in the rate regulatory setting when justice is done, that is to say the striking of a 
reasonable balance between competing interests.”)); see also supra P 137 (describing the 
materiality threshold, phase-in, and grandfathering), PP 141-142 (setting aside the 
December Order in part to allow certain cogeneration QFs to continue to net). 
382 December Order, 193 FERC ¶ 61,217 at P 221. 
383 Id. 
384 Industrials Request for Clarification or Rehearing at 16.

Docket No. EL25-49-002, et al. 
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uneconomic their resource adequacy contributions.385  Industrials contend that this 
threshold would still address the primary concern driven by new large loads.386 
 To the extent the Commission does not grant clarification, Industrials argue that 
the MW materiality threshold, transition period, and grandfathering provision fail to 
correct the asserted defects created in the December Order.387  While Industrials 
“welcome exemptions as helpful,” they describe those policies as “the exception that 
proves the rule.”388  Industrials contend that the threshold could create unintended 
consequences such as perverse incentives to make on-site generation projects smaller, 
undue discrimination via a bright-line threshold, or a limit that is too low.389  Industrials 
suggest that, rather than an arbitrary threshold, the Commission should maintain its 
traditional netting approach but find alternative means to ensure that standby or backup 
costs are addressed for very large loads.  Industrials recommend that if the Commission 
pursues a mandatory threshold, it should choose a multi-pronged threshold aligned with 
the drivers of current transmission demand and the reliability risks posed.390  Specifically, 
Industrials argue, the Commission should set the threshold high enough to permit 
traditional manufacturers and industrial loads to continue netting—such as 200 MW.391 
 
385 Id. at 16 & n. 23 (“We understand that industrial combined heat and power . . . 
units may, in certain cases, exceed 200 MW.  Given the Administration’s interest in 
reshoring American manufacturing and the pressing need to keep long-established 
generation units economic, 200 MW may be insufficient.”).   
386 Id. at 16-17. 
387 Id. at 42.  
388 Id. 
389 Id. at 42-43 (stating also that “[n]either a MW-based threshold nor a 
grandfathering provision correct jurisdictional deficiencies” and the Commission should 
“find alternative means to ensure that standby or backup costs are addressed for very 
large loads”). 
390 Id. at 43.  
391 Id. at 43-44.

Docket No. EL25-49-002, et al. 
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(c) 
Determination 
 As an initial matter, we dismiss Industrials’ argument that any retail BTMG 
materiality threshold implemented will be insufficiently high for lack of finality.392  The 
December Order did not make a final decision on the materiality threshold to be used in 
the revised the retail BTMG netting rules.393  In particular, the Commission stated that it 
“ma[d]e no finding in this order on a threshold” “for the amount of load at a particular 
electrical location that Network Customers may net by using BTMG.”394  It would thus 
be premature to argue or evaluate on rehearing whether that as-yet-undeveloped retail 
BTMG materiality threshold be insufficiently high.395 
 In response to the Industrials’ arguments on rehearing regarding the MW 
threshold, transition period, and grandfathering provision, we continue to find that this 
three-pronged approach as to a replacement rate is just and reasonable.396  As an initial 
matter, we note that Industrials primarily take issue with the Commission’s decision to 
set a MW threshold, alleging it is arbitrary and may be unduly discriminatory.397  We 
disagree.  We recognize that no threshold may be perfect, but the Commission has 
discretion in drawing administrative lines it deems necessary,398 and we continue to 
believe that a threshold is not only necessary for the reasons set out in the December 
Order, but also that we can exercise reasonable discretion to set a threshold consistent 
with the Commission’s intent to reduce the concerns raised by PJM’s existing retail 
BTMG netting rules.  As the Commission explained in the December Order, “such a 
threshold should reduce the reliability and resource adequacy risks [] that large loads may 
 
392 See supra P 106. 
393 December Order, 193 FERC ¶ 61,217 at P 221. 
394 Id. 
395 Algonquin Gas Transmission, 175 FERC ¶ 61,150 at P 8. 
396 December Order, 193 FERC ¶ 61,217 at PP 221-224. 
397 Industrials Request for Clarification or Rehearing at 16-17, 42-43. 
398 See Vonage Holdings Corp. v. FCC, 489 F.3d 1232, 1242 (D.C. Cir. 2007) (“It 
is true that an agency may not pluck a number out of thin air when it promulgates rules in 
which percentage terms play a critical role.  When a line has to be drawn, however, the 
Commission is authorized to make a ‘rational legislative-type judgment.’  If the figure 
selected by the agency reflects its informed discretion, and is neither patently 
unreasonable nor ‘a dictate of unbridled whim,’ then the agency’s decision adequately 
satisfies the standard of review.”) (citation and internal quotation marks omitted).

Docket No. EL25-49-002, et al. 
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pose to PJM, while also allowing Network Customers to reduce their transmission 
charges in a transparent, not unduly discriminatory fashion.”399  The Commission also 
acknowledged that such a materiality threshold “will not eliminate the risk” identified in 
the December Order, but found that it “will ensure that the risk is limited.”400  As the 
Commission explained in the December Order, an important part of the problem is that 
“PJM’s existing retail BTMG netting rules do not limit the amount of qualifying load that 
a Network Customer may net by using BTMG.”401  We also note that, as discussed 
above, we set aside, in part, the December Order’s elimination of BTMG netting as to 
certain cogeneration QFs.  In addition, we note that above we set aside, in part, the 
December Order and extend the three new transmission services set forth in the 
December Order to Eligible Customers taking service on behalf of load with BTMG that 
are willing and able to limit their energy withdrawals from the transmission system under 
certain conditions, thereby providing such customers the option to elect to take a 
transmission service that matches their preferred use of the transmission system.402  
Lastly, we note that, while Industrials suggest the Commission find an alternative 
approach to a mandatory threshold to ensure that standby or backup costs are addressed 
for “very large loads,”403 they fail to support their request with any specificity.404  
 
399 December Order, 193 FERC ¶ 61,217 at P 221. 
400 Id. 
401 Id. P 186. 
402 Id. P 194 (stating that “Eligible Customers, on behalf of the Co-Located Loads 
that they represent, may choose the transmission services that match their preferred use of 
the transmission system”). 
403 Industrials Request for Clarification or Rehearing at 43. 
404 FPA section 313(a) requires that an “application for rehearing shall set forth 
specifically” its grounds.  16 U.S.C. § 825l(a) (emphasis added).  We follow Commission 
practice, with which courts have agreed, and reject arguments on rehearing, such as this 
one, lacking sufficient specificity.  PJM Interconnection, L.L.C., 171 FERC ¶ 61,040                 
at P 22; see also Ind. Util. Regul. Comm’n, 668 F.3d at 736; LA Storage, LLC, 182 FERC 
¶ 61,026 at P 25 & n.75.

Docket No. EL25-49-002, et al. 
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2. 
Necessary Study Process for Existing Interconnection Customers 
a. 
Treatment of Capacity Interconnection Rights (CIRs) for 
Co-Located Generators 
i. 
December Order 
 The Commission found that an existing generator may not begin serving                    
Co-Located Load that is not Network Load until it has de-listed its CIRs for the portion 
of the generator to be designated to serve any Co-Located Load that is not receiving 
NITS.405  A capacity resource’s CIRs are rights to inject generation as a Generation 
Capacity Resource into the transmission system at the Point of Interconnection.406   
ii. 
Request for Clarification and/or Rehearing 
 Constellation argues that the December Order appears to require a capacity 
resource to delist its CIRs even when the capacity resource remains fully capable of 
serving the grid during capacity emergencies.407  Constellation explains that generators 
and Co-Located Load may seek contractual arrangements in which the generator will 
serve the grid rather than the Co-Located Load during a capacity emergency and the             
Co-Located Load will either curtail or rely on backup generation.  Constellation claims 
that it would be inconsistent with PJM’s existing rules to require delisting in these 
circumstances.  According to Constellation, PJM’s existing rules only require a capacity 
resource entering an external sale to delist its CIRs when the resource “has a financially 
and physically firm commitment to an external sale of its capacity.”408   
 Constellation therefore seeks clarification that the December Order does not 
require a capacity resource to delist its CIRs to serve a Co-Located Load that is taking 
NFCD transmission service if PJM can verify that the Co-Located Load has no 
contractual right to energy from the generator during a capacity emergency and that the 
Co-Located Load has the ability either to curtail or draw on back-up power.409  
 
405 December Order, 193 FERC ¶ 61,217 at P 230. 
406 PJM Interconnection, L.L.C., 168 FERC ¶ 61,155, at P 7 n.15 (2019). 
407 Constellation Request for Clarification or Rehearing at 3 (citing December 
Order, 193 FERC ¶ 61,217 at P 230). 
408 Id. at 4 (quoting PJM, Intra-PJM Tariffs, OATT, attach. DD.6 § 6.6) (emphasis 
in original). 
409 Id. at 4-5 (referring to “the ability to (i) interrupt and/or (ii) turn on back-up 
diesels or other back-up power or draw on batteries when transmission under the

Docket No. EL25-49-002, et al. 
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Constellation argues that the Commission could require the Co-Located Load to disclose 
information regarding its protective relay scheme and its interruptible commitment and 
could impose penalties on the Co-Located Load for failure to comply with its 
commitment. 
 To the extent that the Commission does not grant clarification, Constellation seeks 
rehearing.  Constellation argues that requiring a capacity resource to delist its CIRs in 
these circumstances would be a failure of reasoned decision making.410  Constellation 
also argues that it would be unduly discriminatory to require a capacity resource serving a 
Co-Located Load to delist for entering into an interruptible commitment but not to 
require capacity resources to delist before making other non-firm commitments.411 
iii. 
Determination 
 We deny Constellation’s request for clarification and sustain the December 
Order’s finding that an existing generator may not begin serving Co-Located Load that is 
not Network Load until it has delisted its CIRs for the portion of the generator to be 
designated to serve any Co-Located Load that is not receiving NITS.412 
 Constellation proposes a scenario in which an Eligible Customer taking NFCD 
transmission service on behalf of Co-Located Load would not be allowed to withdraw 
power from the transmission system during emergency conditions and the Eligible 
Customer would guarantee that it would further curtail its demand in order to allow the 
Co-Located Generator to provide energy to the system.  NFCD transmission service 
governs when an Eligible Customer may withdraw energy from the transmission system, 
but it does not govern the firmness of any bilateral agreement to supply energy between 
the Co-Located Load and the Co-Located Generator.  We understand Constellation’s 
scenario to be one in which the Co-Located Load—when relying on the Co-Located 
Generator—does not schedule its power by relying on FCD or NFCD transmission 
service.  
 
non-firm contract demand service is interrupted and the co-located generator is serving 
the grid”). 
410 Id. at 6 (citing Elec. Consumers Res. Council v. FERC, 747 F.2d 1511, 1513-14 
(D.C. Cir. 1984)). 
411 Id. (citing 5 U.S.C. § 706(2)(A); Consol. Edison of N.Y., Inc. v. FERC, 45 F.4th 
265 (D.C. Cir. 2022)). 
412 December Order, 193 FERC ¶ 61,217 at P 230.

Docket No. EL25-49-002, et al. 
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 Under Constellation’s scenario, the Co-Located Generator would not be capable of 
meeting its entire capacity requirement.  In addition to the requirement to perform during 
emergencies, Generation Capacity Resources are required to offer into the Day-Ahead 
Market throughout the delivery year.413  Constellation’s proposal would allow a 
Generation Capacity Resource to violate this requirement and provide an inferior 
capacity product (compared to other Generation Capacity Resources) for the same 
capacity payment.  We thus deny Constellation’s request for clarification and sustain the 
December Order. 
 We also reject Constellation’s argument that Generation Capacity Resources 
engaged in non-firm external bilateral transactions are not required to delist their CIRs 
and are comparable.414  A Generation Capacity Resource engaged in a non-firm external 
bilateral transaction must still make offers into PJM’s day-ahead market.415   
b. 
Cost Responsibility for Network Upgrades 
i. 
December Order 
 In the December Order, the Commission required PJM to revise its Tariff to 
expressly indicate that the Interconnection Customer will be responsible for the costs of 
any modifications or Network Upgrades that are needed as a result of PJM’s study of the 
change to the Interconnection Service Agreement (ISA) or Generation Interconnection 
Agreement (GIA) to allow the existing generator to serve Co-Located Load, including to 
reflect any reduction in CIRs, inclusive of all necessary Network Upgrades.  The 
Commission found that this change will clarify that costs associated with such                      
Co-Location Arrangements will not be unfairly shifted to other transmission customers.  
The Commission further directed PJM to revise its Tariff to clarify that an existing 
generator may not commence service to a Co-Located Load until all required Network 
Upgrades, special protection schemes, and metering are in service.416 
 
413 Under the Tariff, a capacity resource is required to offer its Installed Capacity 
(ICAP) equivalent of the resource’s cleared Unforced Capacity (UCAP) into the PJM 
energy markets every day if not on outage or derated.  PJM, Intra-PJM Tariffs, OATT, 
attach. K, app. § 1.10 (Scheduling) (46.1.1), § 1.10.1A(d). 
414 Constellation Request for Clarification or Rehearing at 6. 
415 PJM, Intra-PJM Tariffs, OATT, attach. K, app. § 1.10 (46.1.1), § 1.10.1A(d). 
416 December Order, 193 FERC ¶ 61,217 at P 228; see also id. P 176 
(summarizing same).

Docket No. EL25-49-002, et al. 
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ii. 
Request for Rehearing 
 Exelon and FirstEnergy challenge the Commission’s directive that an 
Interconnection Customer seeking to serve Co-Located Load using an existing generator 
must bear the costs of all Network Upgrades.417  Exelon and FirstEnergy contend that the 
Commission has departed, without explanation, from its policy that all transmission 
customers share the embedded costs of the transmission system, including Network 
Upgrade costs, consistent with cost causation principles.418  Exelon and FirstEnergy 
assert that this policy is sensible because all loads benefit from the transmission network, 
including Co-Located Load.  Exelon and FirstEnergy argue that the Commission 
acknowledges that Co-Located Load benefits from the transmission network as a whole 
because the Commission found Co-Located Load relies on regulation and black start.419  
Exelon and FirstEnergy contend that regulation and black start cannot be delivered in 
isolation:  they depend on diverse resources around the grid transmitting power over 
transmission lines, on other operating reserves and voltage support services, and on 
Network Upgrades.  Exelon and FirstEnergy also argue that the December Order is 
internally inconsistent and discriminatory because it preserves NITS as a just and 
reasonable approach, but the NITS funding model conflicts with the proposed assignment 
of costs to Co-Located Load.420 
 Exelon and FirstEnergy assert that the Commission should not erode its rolled-in 
rate policy and identify several consequences of such erosion.421  First, Exelon and 
FirstEnergy contend that, if Co-Located Loads need only pay for incremental investment, 
they avoid paying for the broader system on which they depend, resulting in other 
customers paying a forced subsidy.422  Exelon and FirstEnergy express concern that, once 
a Co-Located Load fulfills its responsibility for funding certain upgrades, prohibitions on 
“and” pricing mean the Co-Located Load would not be responsible for further 
transmission service payments even though the transmission system requires 
maintenance.  Second, Exelon and FirstEnergy argue that the Commission’s approach 
creates challenges akin to those in the generator interconnection space, such as the 
potential for future Co-Located Load customers to trigger significant upgrades, and 
 
417 Exelon and FirstEnergy Request for Rehearing at 42-43. 
418 Id. at 42. 
419 Id. at 43. 
420 Id. at 44. 
421 Id. at 44-47. 
422 Id. at 45.

Docket No. EL25-49-002, et al. 
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incentives for speculative behavior and Point of Interconnection shopping.423  Third, 
Exelon and FirstEnergy argue that significant up-front requirements could hinder 
economic development for Co-Located Load customers that are not data centers.  
iii. 
Determination 
 We sustain the December Order’s requirement that an Interconnection Customer 
will be responsible for the costs of any modifications or Network Upgrades that are 
needed to allow the existing generator to serve Co-Located Load, including to reflect any 
reduction in CIRs, inclusive of all necessary Network Upgrades.424  We disagree with 
Exelon and FirstEnergy’s argument that the Commission created a “new paradigm” as to 
Interconnection Customers’ cost responsibility for Network Upgrades needed to 
accommodate modifications those customers make to their own generators.425  To the 
contrary, the Commission directed PJM to revise the Tariff to expressly state that 
Interconnection Customers have this cost responsibility in order to “clarify that costs 
associated with such Co-Location Arrangements will not be unfairly shifted.”426  In other 
words, even without this revision to improve the Tariff’s clarity, this requirement was the 
preexisting one.  The Tariff provides that an Interconnection Customer is responsible for 
the costs of additions to the Transmission System that are required to accommodate 
modifications to the generator.427  For example, apart from Co-Location Arrangements, if 
an Interconnection Customer decreased the capacity of a generator due to technological 
changes at that facility, the Interconnection Customer would be responsible for the costs 
of Network Upgrades needed to accommodate that decrease.428  This requirement 
 
423 Id. at 46. 
424 December Order, 193 FERC ¶ 61,217 at P 228. 
425 Exelon and FirstEnergy Request for Rehearing at 42-47. 
426 December Order, 193 FERC ¶ 61,217 at P 228 (emphasis added).   
427 PJM, Intra-PJM Tariffs, pt. IX, subpt. B, app. 2 (2.0.0), § 3.4(b) (Modification 
Costs) (“Project Developer shall be responsible for the costs of any additions, 
modifications, or replacements to the Interconnection Facilities and Transmission Owner 
Upgrades or the Transmission System that are required, in accord with Good Utility 
Practice and/or to maintain compliance with Applicable Laws and Regulations or 
Applicable Standards, in order to accommodate additions, modifications, or replacements 
made by Project Developer to the Generating Facility or Merchant Transmission Facility 
or to the Project Developer Interconnection Facilities.”); see also, e.g., id. Attachment O, 
Appendix 2, § 3.4(b) Modification Costs (0.0.0).  
428 Id. Part IX.B, Appendix 2, § 3.4(b) Modification Costs (2.0.0).

Docket No. EL25-49-002, et al. 
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likewise applies to Interconnection Customers seeking to modify their interconnection to 
serve Co-Located Load if the attendant decrease in energy injected to the transmission 
system necessitates Network Upgrades.  Accordingly, if the Commission had not directed 
the revision at issue here, Interconnection Customers would still bear the cost 
responsibility at issue—the Commission simply acted to improve the clarity of the Tariff 
on this topic.  Exelon and FirstEnergy thus attack a requirement in the Tariff that the 
Commission approved before this proceeding and that the Commission did not change in 
this proceeding.   
 For the same reason, Exelon and FirstEnergy are incorrect in arguing that the 
Commission “depart[ed] from prior precedent” with a requirement that “differs from the 
approach taken in the PJM Tariff.”429  As explained, the Commission did not change the 
preexisting Tariff regime.  In any event, despite their assertion, Exelon and FirstEnergy 
do not include citations to precedent addressing this topic.430   
 Exelon and FirstEnergy also misunderstand the requirement they criticize.  Exelon 
and FirstEnergy characterize the Commission’s directive as ordering that “[C]o-[L]ocated 
[L]oad must self-fund any needed transmission upgrades.”431  The cost responsibility at 
issue, however, is limited to existing Interconnection Customers and pertains only to the 
specified Network Upgrades related to their own modifications.432  In short, the 
Commission did not direct that Co-Located Load would self-fund Network Upgrades.  
Their criticisms of the clarification that the Commission directed to the current Tariff are 
thus flawed.  The Commission specifically stated that the requirement to self-fund any 
needed Network Upgrades was appropriate because when “an Interconnection Customer 
seek[s] to serve Co-Located Load using an existing generating facility” “existing 
transmission customers” must be “protect[ed]” “from bearing the cost of Network 
Upgrades required for an Interconnection Customer to begin serving Co-Located 
Load.”433  Otherwise, costs could be “unfairly shifted” based on the conduct of 
 
429 Exelon and FirstEnergy Request for Rehearing at 42, 44. 
430 In the relevant section of Exelon and FirstEnergy’s rehearing request, they do 
cite several cases and orders that do not address this topic.  For example, Exelon and 
FirstEnergy cite Coalition of MISO Transmission Customers v. FERC, 45 F.4th 1004, 
1009 (D.C. Cir. 2022), for a general statement of cost causation principles and they cite 
two orders regarding load-ratio share for NITS.  Id. at 42-47 & nn.110-111. 
431 Id. at 42. 
432 PJM, Intra-PJM Tariffs, pt. IX, subpt. B, app. 2, (2.0.0), § 3.4(b) (Modification 
Costs). 
433 December Order, 193 FERC ¶ 61,217 at P 176 (emphasis added).

Docket No. EL25-49-002, et al. 
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Interconnection Customers.434  The entity responsible for causing the need for the 
Network Upgrade costs is therefore the relevant Interconnection Customer, and Exelon 
and FirstEnergy are incorrect to assert that a “load pays” framework should apply here.435  
It is the conduct of the Interconnection Customer that triggers the Network Upgrades at 
issue.  
 Exelon and FirstEnergy nonetheless contend that “[C]o-[L]ocated [L]oad should 
be charged for the benefits it receives from the grid and for the burdens it places upon the 
grid.”436  Exelon and FirstEnergy further give the example of the use of regulation and 
black start services.437  The December Order appropriately addressed such use.  The 
December Order determined, for example, that Eligible Customers serving Co-Located 
Loads that seek to rely on the transmission system to the same extent as Network 
Customers will continue to be eligible to take NITS, billed on a gross demand basis; 
Eligible Customers can take and pay for the new contract demand transmission services 
that reflect a Co-Located Load’s ability to limit withdrawals from the transmission 
system; and Eligible Customers taking transmission service on behalf of Co-Located 
Load must be assessed charges for regulation and black start services on a gross demand 
basis, to ensure appropriate cost recovery for such services.438  In sum, the findings we 
discuss here related to Interconnection Customer cost responsibility do not disturb the 
Commission’s findings addressing appropriate charges for transmission service—an 
obligation on Eligible Customers not Interconnection Customers.  
 Exelon and FirstEnergy also argue that the Commission improperly assessed “cost 
causation” because it “randomly applied” “cost responsibility” “only to cases where the 
added load is served through an existing generator interconnection facility.”439  As 
explained above, however, the Commission simply applied the existing Tariff.  The 
 
434 Id. P 228. 
435 Exelon and FirstEnergy Request for Rehearing at 43; see also id. at 43-44 
n.113 (stating that the December Order “departs from th[e] longstanding approach” of 
“rolling the costs of load-driven network upgrades into transmission rates”).  
436 Id. at 43; see also id. at 45-46; id. at 47 (stating that “it should not be assumed 
that large loads will trigger system upgrades with costs in excess of what they would 
otherwise contribute to the system if they paid traditional network rates based on their 
load-share ratio”).  
437 Id. at 43. 
438 December Order, 193 FERC ¶ 61,217 at P 160. 
439 Exelon and FirstEnergy Request for Rehearing at 44.

Docket No. EL25-49-002, et al. 
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Commission likewise affirmed the allocation of cost responsibility to the parties that 
cause the costs—the Interconnection Customers—who do so through their conduct in 
modifying their existing arrangement.440  Accordingly, we disagree with Exelon and 
FirstEnergy’s assertion that these costs should instead be spread “to all network 
customers.”  In PJM, the costs of Network Upgrades are directly assigned to the 
interconnection customer—referred to as participant funding.441  In its Order No. 2003 
compliance proceeding, PJM explained that “the ‘but for’ provisions of the PJM tariff . . . 
require an Interconnection Customer to pay 100 percent of the Network Upgrades that 
must be made for the Interconnection Customer to connect to the PJM grid.”442  In PJM, 
Interconnection Customers are also responsible for the costs of any changes to the 
transmission system that are required to accommodate additions, modifications, or 
replacements made by the Interconnection Customer to the generator or its 
interconnection facilities.443  The Commission’s directive thus adheres to Commission 
precedent and the Tariff and also does not conflict with (or change) “the Network Service 
funding model.”444 
 We also find unavailing the “several issues” Exelon and FirstEnergy contend the 
Commission’s determination created.445  We find each speculative and unsupported by 
evidence.  More specifically, Exelon and FirstEnergy assert that the Commission is 
improperly accounting for a “benefit to other customers to include new [C]o-[L]ocated 
[L]oads in the pool of payers for the existing transmission network.”446  Yet as explained 
above, the December Order establishes a set of transmission service options that ensures 
that Eligible Customers taking service on behalf of Co-Located Loads are allowed to 
 
440 Indeed, Exelon and FirstEnergy acknowledge that “exiting incumbent 
generators” cause the relevant costs by referring to “transmission upgrade costs they 
cause by serving [C]o-[L]ocated [L]oad.”  Id. 
441 PJM Interconnection, L.L.C., 108 FERC ¶ 61,025, at P 20 (2004). 
442 Id. P 19.  PJM’s current generator interconnection rules include similar “but 
for” provisions.  See PJM, Intra-PJM Tariffs, pt. VIII, subpt. C, § 404 (1.0.0), 
§ 404(A)(5) (Cost Allocation for Network Upgrades).  
443 PJM, Intra-PJM Tariffs, pt. IX, subpt. B, app. 2, § 3.4 (2.0.0), § 3.4(b) 
(Modification Costs). 
444 Exelon and FirstEnergy Request for Rehearing at 44. 
445 Id. at 45-47 (including argument that the Commission’s “approach creates 
challenging dynamics like those we have seen in the generator interconnection space”). 
446 Id. at 45-46.

Docket No. EL25-49-002, et al. 
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choose the transmission service that aligns with their use of the transmission system and 
therefore aligns the charges for service with the benefits received.  Exelon and 
FirstEnergy’s conjecture that “significant up-front requirements could hinder economic 
development”447 disregards the voluntary nature of Co-Location Arrangements, which 
reflect an additional opportunity for developers to consider. 
3. 
New Generators Serving Co-Located Load 
a. 
December Order 
 In the December Order, the Commission found that the Tariff is 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.448  Pertinent to new generators, the Commission directed 
PJM to revise its Tariff to clarify that PJM shall consider requests for interconnection 
service below the full generating capability of the generator, so that an Interconnection 
Customer may request interconnection service at a level below its maximum facility 
output to serve Co-Located Load;449 that Interconnection Customers seeking to use new 
generators to serve Co-Located Load may use existing procedures to accelerate a new 
service request if the request has no cost allocation for Network Upgrades and does not 
require further studies;450 that an Interconnection Customer seeking to use a new 
generator to serve Co-Located Load may request provisional interconnection service;451 
and that an Interconnection Customer seeking to use a new generator to serve Co-Located 
Load at an existing Point of Interconnection may request Surplus Interconnection 
Service, if the existing Interconnection Customer at that Point of Interconnection has 
made Surplus Interconnection Service available.452 
 
447 Id. at 46-47. 
448 December Order, 193 FERC ¶ 61,217 at P 159. 
449 Id. P 232. 
450 Id. P 233. 
451 Id. P 234. 
452 Id. P 235.

Docket No. EL25-49-002, et al. 
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b. 
Request for Clarification 
 Joint Parties request the Commission clarify that a Co-Located Load may 
nominate a net withdrawal limit in the same manner that it may nominate a net injection 
limit when requesting new or modifying existing interconnection service.453  Joint Parties 
argue that the Commission found that creating new transmission services is necessary to 
ensure that Co-Located Loads pay only for the services they use and to avoid costly and 
inefficient transmission system buildout, and that the same logic “should compel 
complementary reforms to the generator interconnection process, because that process 
also may evaluate withdrawals from the Co-Located Load and therefore may also 
result—absent clarification—in ‘costly and inefficient transmission system buildout.’”454  
Joint Parties argue that clarification is necessary to realize the Commission’s intent of 
ensuring that Co-Located Loads do not pay for services that they do not use and do not 
trigger Network Upgrades that they do not need.  Joint Parties explain that, to the extent 
PJM performs interconnection service study steps involving withdrawal assumptions 
from both the storage facility and the Co-Located Load, those steps “must allow the 
interconnection customer to provide for limits to the injection and withdrawal rights for 
the generation and co-located load facilities reflecting the proposed integration of those 
facilities.”455  Joint Parties clarify that they recommend against the Commission requiring 
Co-Located Load be included in the interconnection study process, as the timing of the 
load interconnection process may not match.456 
 Joint Parties argue that, without clarification, PJM may assume that the                         
Co-Located Load and the charging load of the storage resource create overlapping grid 
impacts, when both could be managed to limit the overall withdrawal of the resource and 
avoid withdrawing energy when doing so would create grid impacts that necessitate 
Network Upgrades.  Joint Parties explain that, while the December Order recognizes that 
“co-located resources” can limit withdrawals and prevent unnecessary transmission 
buildout, Joint Parties argue the order applies this logic only to transmission service and 
not interconnection service.457  Joint Parties contend that not applying this logic to 
interconnection service would reduce the benefits of creating the non-firm transmission 
 
453 Joint Parties Request for Clarification at 2-3, 5 (citing December Order,                   
193 FERC ¶ 61,217 at P 232). 
454 Id. at 3 (citing December Order, 193 FERC ¶ 61,217 at P 177). 
455 Id. at 5-6. 
456 Id. at 8 n.20. 
457 Id. at 10 (citing December Order, 193 FERC ¶ 61,217 at P 199).

Docket No. EL25-49-002, et al. 
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service.458  Joint Parties request that the Commission require PJM to specify what 
information about the Co-Located Load is required for the purposes of the new service 
request study process, similar to the Commission’s requirement about the Necessary 
Study process, to ensure that PJM does not include overlapping load and energy storage 
withdrawals.459 
c. 
Determination 
 We deny Joint Parties’ request for clarification.  Joint Parties’ request 
misconstrues the findings in the December Order that the Tariff is 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.460  The December Order did not require PJM to 
integrate into the interconnection study process operating assumptions of both a                     
Co-Located Load and electric storage resources that are part of a Co-Location 
Arrangement.  PJM has already committed to studying the electric storage resources of 
Interconnection Customers as charging during off-peak periods, consistent with PJM’s 
fuel-based dispatch assumptions set forth in its planning criteria.461   
D. 
Informational Report 
1. 
December Order 
 In the December Order, the Commission directed PJM to submit in Docket             
No. EL25-49-000, within 30 days of the date of issuance of the December Order, a 
detailed informational report addressing, among other things “the development of 
enhanced load forecasting . . . measures to assist PJM in determining the amount of new 
capacity that is needed to maintain system reliability.”462 
 
458 Id. at 9-10. 
459 Id. at 8 (citing December Order, 193 FERC ¶ 61,217 at P 227). 
460 December Order, 193 FERC ¶ 61,217 at P 159. 
461 PJM Interconnection, 195 FERC ¶ 61,031, at P 180 (2026) (accepting PJM’s 
proposal, in relevant part, in compliance with the Commission’s Order No. 2023 
interconnection reforms). 
462 December Order, 193 FERC ¶ 61,217 at PP 237-239.

Docket No. EL25-49-002, et al. 
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2. 
Request for Clarification 
 PIOs request clarification as to how the Commission intends to respond to or 
otherwise use information provided in the record regarding PJM’s load forecasting 
practices.  PIOs further request that any subsequent order from the Commission address 
the issues raised in the record regarding the continuing and ongoing deficiencies in PJM’s 
load forecasting process.  PIOs explain that PJM is using these load forecasts as inputs in 
the upcoming Base Residual Auction and RTEP and argue that, without a specific 
Commission directive, PJM is unlikely to timely resolve issues that PIOs allege exist with 
the load forecasts.463  PIOs note that the Commission required PJM to provide an 
informational filing that includes an update regarding the development of “enhanced load 
forecasting” and acknowledge that the Commission stated that it “will not act on or notice 
this informational [f]iling.”464 
 PIOs note that Commissioner Rosner submitted a letter to PJM about load 
forecasting in September 2025 and take issue with PJM’s October 2025 response.465  
According to PIOs, PJM’s response to this letter does not require or specify a particular 
methodology for forecasting large loads, without which PIOs allege that LSEs and 
Electric Distribution Companies will continue to report data with widely varying 
accuracy and that load forecasts will remain uncertain.  PIOs also argue that PJM’s 
response fails to identify a way for PJM to address the double counting of data centers or 
to enable PJM to respond dynamically to significant updates to load forecasts.466 
 PIOs contend that recent events have validated their concerns regarding the 
accuracy of PJM’s load forecasts.  For example, according to PIOs, PJM staff have 
acknowledged that the 2026 forecast would likely reflect a decrease in forecasted load for 
that time period in light of an update to how PJM implements load adjustments.  Given 
the alleged inaccuracy of PJM’s load forecasts, and because PJM uses its load forecasts 
to essentially set the demand curve for capacity obligations, for reliability studies, and to 
support the RTEP, PIOs question how these processes remain just and reasonable without 
significant revisions to PJM’s load forecasting practices.467 
 
463 PIOs Request for Clarification at 2-3. 
464 Id. at 2 (citing December Order, 193 FERC ¶ 61,217 at P 238 & n.486). 
465 Id. at 4-5. 
466 Id. 
467 Id. at 5-7.

Docket No. EL25-49-002, et al. 
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3. 
Determination 
 We deny the request for clarification.  The directive in the December Order to 
PJM to file an informational report that includes load forecasting represents the 
Commission’s actions in this proceeding related to load forecasting.468  The Commission 
will review the informational report in its normal course and remains committed to 
monitoring PJM’s load forecasting.  Separately, we note that in the order that we are 
issuing concurrently in Docket No. EL26-67-000, we direct PJM to show cause as to why 
its Tariff remains just and reasonable without sufficiently clear and consistent Tariff 
provisions that address the application process for requesting transmission service to 
Eligible Customers on behalf of large loads and the study procedures for studying the 
provision of transmission service to Eligible Customers on behalf of large loads, 
including 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).   
V. 
Compliance 
A. 
BTMG Rules 
1. 
Materiality Threshold 
a. 
December Order 
 The Commission found that PJM’s existing retail BTMG netting rules were no 
longer just and reasonable and directed several changes, including directing PJM to 
propose a new MW threshold for the amount of load at a particular electrical location that 
Network Customers may net by using BTMG.469  The Commission found that a 
materiality threshold would reduce the reliability and resource adequacy risks that large 
loads may pose to PJM, while also allowing for Network Customers to reduce their 
transmission charges in a transparent, not unduly discriminatory fashion.  The 
Commission noted “as points of reference that PJM requires any generator larger than             
10 MW to be individually metered and that the Commission’s definition of a small 
generator is 20 MW.”470 
 
468 December Order, 193 FERC ¶ 61,217 at PP 237-239. 
469 Id. P 221.  The Commission did not direct PJM to make any changes to its rules 
for Non-Retail BTMG, finding that the record did not demonstrate the need for changes 
given that Non-Retail BTMG is already capped.  Id. P 222.  
470 Id. P 221 (citing PJM Manual 14G:  Generation Interconnection Requests,            
Rev. 8 (eff. July 26, 2023), § 1.6.2; Standardization of Small Generator Interconnection

Docket No. EL25-49-002, et al. 
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b. 
PJM Compliance Filing 
 PJM proposes to modify the existing Tariff definition of BTMG and add a new 
definition for Retail BTMG to establish a materiality threshold for Retail BTMG.471  PJM 
explains that the current Tariff definition of BTMG includes both Retail and Non-Retail 
BTMG, but the Tariff only specifically defines Non-Retail BTMG.472  Therefore, PJM 
proposes to separately define Retail BTMG as BTMG that is used to serve a retail load 
served by a Network Customer located at the same electrical location, where such 
generation has a cumulative nameplate rating of no greater than 50 MW.473  PJM also 
proposes to clarify in the Tariff that Retail BTMG may not be part of a Co-Located Load 
configuration.  PJM argues that this clarification is necessary “to avoid unexpected and 
unintended hybrid scenarios mixing BTMG and the new transmission service 
products.”474 
 PJM states that the proposed materiality threshold, along with other exclusions 
discussed below, will avoid the “unintended consequence of causing Retail BTMG 
resources to prematurely cease operations and discontinue investment in grid-enhancing 
backup generation,” which may otherwise impact system reliability.475  PJM argues that a 
lower threshold of 10 or 20 MW would likely exclude Retail BTMG with limited impact 
on the transmission system in comparison to Co-Located Load coming online today.  
 
Agreements & Procs., Order No. 2006, 111 FERC ¶ 61,220, at P 1, order on reh’g, Order 
No. 2006-A, 113 FERC ¶ 61,195 (2005), order granting clarification, Order No. 2006-B, 
116 FERC ¶ 61,046 (2006)). 
471 Compliance Transmittal at 6-7 (citing December Order, 193 FERC ¶ 61,217              
at P 179). 
472 Id. at 5-6 (citing PJM, Intra-PJM Tariffs, pt. I, Definitions A-B (24.0.0), Behind 
The Meter Generation; PJM, Proposed Tariff, PJM, pt. I, Definitions L-M-N (52.0.0), 
Non-Retail Behind The Meter Generation).  PJM explains Non-Retail BTMG is BTMG 
used to net load through a distribution system.  PJM clarifies that no substantive changes 
are proposed to the Non-Retail BTMG netting rules, but PJM does propose clarifying 
Tariff edits to avoid confusion with the new retail BTMG netting rules.  Id. at 7, 15-16. 
473 Id. at 7. 
474 Id. at 18. 
475 Id. at 12.

Docket No. EL25-49-002, et al. 
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PJM also contends that many of the lower MW generators would not be willing to enter 
the interconnection queue due to age and the potential cost of Network Upgrades.476 
 PJM also proposes to exclude on-site backup generation at the same electrical 
location as the retail load that can only be used to serve such retail load during conditions 
that may threaten the integrity or reliability of the PJM region or the regional power 
system from the 50 MW materiality threshold, arguing that to do otherwise would 
disincentivize retail customers from installing backup generation that would improve 
reliability.477  PJM notes that the Department of Energy recently issued an order during 
Winter Storm Fern directing PJM to direct backup generation resources to operate before 
taking certain emergency actions.478  PJM states that exempting backup generation from 
the materiality threshold will ensure this reliability tool remains available.  Finally, PJM 
states that a materiality threshold based on the size of the generator that may qualify as 
Retail BTMG, rather than the amount of load that may net, establishes a clear and bright 
line for what can continue qualifying as Retail BTMG, given that the size of a load may 
fluctuate.479 
 PJM states that, should the Commission not accept PJM’s proposal regarding 
grandfathering, discussed below, PJM requests the Commission to allow a higher interim 
initial materiality threshold for the start of the transition period to avoid causing Retail 
BTMG to cease operations and exacerbate the resource adequacy issues in PJM.480  PJM 
states that, should the Commission take this path, PJM would commit to reviewing 
additional data on the size and extent of existing Retail BTMG to inform a final 
threshold. 
c. 
Pleadings 
i. 
Size of Threshold 
 Constellation argues that PJM’s proposed 50 MW materiality threshold for BTMG 
is too high and urges the Commission to either reject it or require modifications to 
 
476 Id. at 12-13. 
477 Id. at 13 (citing US Department of Energy, Order No. 202-26-06 (Jan. 26, 
2026), https://www.energy.gov/documents/doe-order-no-202-26-06-pjm). 
478 Id. at 13-14 (citing US Department of Energy, Order No. 202-26-06). 
479 Id. at 13-14. 
480 Id. at 14-15 (noting PJM ICC’s request for a 200 MW threshold in PJM ICC’s 
Request for Clarification or Rehearing, Docket No. EL25-49-000, et al., at 44).

Docket No. EL25-49-002, et al. 
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address undue discrimination against Co-Located Loads.  Constellation argues that this 
threshold will allow a significant number of loads with BTMG to take advantage of 
unjust and unreasonable netting and include backup generation as offsetting BTMG, but 
deny such treatment to Co-Located Load, despite there being no physical, technical, or 
economic reason why a netting construct should apply differently for customers with 
BTMG or with Co-Located Generators.  Constellation argues that PJM has not provided 
any explanation for why the proposed threshold is relevant to reducing the reliability and 
resource adequacy risks that large or increasing BTMG may pose to PJM and argues that 
PJM’s justifications for the threshold are unsupported.481   
 Other parties argue that PJM’s proposed threshold is too low.482  
Industrials/Amtrak argue that a threshold of at least 200 MW would better capture the 
large loads driving reliability and cost-shifting concerns, while maintaining the existing 
retail BTMG netting rules that promote smaller resource adequacy investments, and 
avoid economic damage to industrial, institutional, and transportation sectors.  
Industrials/Amtrak argue that a 200 MW threshold is also appropriate because PURPA 
defines small generation for non-cogeneration QFs as 80 MW or smaller, meaning large 
generation must be greater than 80 MW.  Industrials/Amtrak also argue that this threshold 
would simplify the transition process by eliminating most grandfathering issues and 
bolstering resource adequacy and grid efficiency, thereby avoiding inefficient 
transmission investment.  Industrials/Amtrak argue that a 200 MW threshold would 
respect the importance of onshoring manufacturing and support Amtrak’s operations, 
because Amtrak relies on more than 50 MW of retail BTMG, generated at 25 Hz, to 
provide energy supply and the only black start capability to the south end of Amtrak’s 
Northeast Corridor traction power system.483   
 Energy Artisans also support a 200 MW materiality threshold.484  Energy Artisans 
argue that, for sites that exceed this higher threshold, the Commission should require 
PJM to use the proposed Interim NITS because it would provide PJM with a “safety 
 
481 Constellation Protest and Comments on Compliance Filing at 9-11. 
482 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 9, 25; 
Crusoe Comments on Compliance Filing at 4; Eastman Protest and Comments on 
Compliance Filing at 6; EDFps Comments on Compliance Filing at 4; Energy Artisans 
Protest of Compliance Filing at 1; DPN Comments on Compliance Filing at 4. 
483 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 9, 25, 
31, 33, 39. 
484 Energy Artisans Protest of Compliance Filing at 2.

Docket No. EL25-49-002, et al. 
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switch” to manage reliability during peak emergencies without forcing expensive 
upgrades or disconnection on industrial users. 
 Eastman similarly argues that, if the Commission does not maintain netting for 
BTMG facilities like Eastman’s Kingsport facility, the Commission must establish a 
threshold of at least 200 MW on a permanent basis.  Eastman explains that its Kingsport 
facility has generation with a nameplate capacity of 194 MW, but that it cannot withdraw 
that amount of energy through its interconnection with Kingsport Power and could not 
operate solely on electric power from the grid.  Eastman argues that imposing an 
arbitrarily low materiality threshold would eliminate the grid benefits that its BTMG 
facilities have provided.485 
 Industrials/Amtrak and Eastman argue that setting the threshold too low will 
increase costs for many existing loads with BTMG and make a lot of existing BTMG 
uneconomic.486  Industrials/Amtrak argue that even if load with BTMG were to have that 
generation participate in the PJM markets, there is no guarantee of that generation 
earning sufficient revenue to make up for the loss of netting, especially as transmission 
upgrades may be required to interconnect the generation.  Industrials/Amtrak also argue 
that setting the threshold too low will force substantial burdens on existing customers to 
become Commission-regulated public utilities, secure PJM membership, and undertake 
related credit and risk requirements.  Moreover, Industrials/Amtrak argue, a low 
threshold would remove the incentive to operate efficiently and during stressed system 
conditions, as well as create additional work for PJM staff to study BTMG that must 
either go through the interconnection queue or deactivate.  Industrials/Amtrak contend 
that retirement of existing BTMG would increase demand and transmission planning 
needs in the near term, resulting in higher transmission rates.487  Energy Artisans argue 
that PJM’s proposed 50 MW materiality threshold is an arbitrary cap that ignores the 
capital-intensive investments made by large-scale industrial facilities.488   
 Industrials/Amtrak argue that BTMG can provide benefits to the transmission 
system, including reducing large loads on the system, congestion, and transmission 
 
485 Eastman Protest and Comments on Compliance Filing at 6. 
486 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 7; 
Eastman Protest and Comments on Compliance Filing at 6. 
487 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 15, 
25-26, 28. 
488 Energy Artisans Protest of Compliance Filing at 1.

Docket No. EL25-49-002, et al. 
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system build out, as well as operating during system emergencies.489  EDFps argues that 
BTMG can reduce grid congestion, avoid queue delays, lower Network Upgrade needs, 
and provide economic and community benefits such as tax revenues and jobs.490 
 Crusoe argues that while the 50 MW threshold aligns with PJM’s definition of 
large load additions, this threshold is not a bright-line test for what constitutes a 
reliability risk.  Crusoe contends that the materiality threshold should be flexible to 
account for the fact that Co-Location Arrangements can vary significantly and should be 
scaled in proportion to the load served.  Crusoe argues that a lower threshold risks forcing 
existing BTMG resources offline during the transition period, which would increase 
burden on the grid by converting currently netted load into Network Load.  Crusoe claims 
that BTMG arrangements benefit the transmission system by serving load on a 
streamlined basis, avoiding generator interconnection queue delays, and reducing the 
need for Network Upgrades.491 
 Energy Artisans also contend that the 50 MW materiality threshold is unduly 
discriminatory because it establishes a 50 MW nameplate cap for retail BTMG while 
maintaining a 3,000 MW regional cap for Non-Retail BTMG.492  In the absence of 
demonstrated negative impacts from existing BTMG configurations, Energy Artisans 
claim that the 50 MW materiality threshold is a pretext for cost-shifting. 
 EDFps argues that PJM’s proposed 50 MW threshold is arbitrary and will 
disincentivize large loads from installing their own generation and thereby stifle 
innovation.  EDFps contends that the threshold will instead incentivize the development 
of smaller loads, as well as segmented loads close in proximity to avoid the threshold, 
leading to inefficient and redundant construction of interconnection facilities.  EDFps 
notes that the “optimal sizing of Retail BTMG” for an artificial intelligence data center, 
for example, would be higher than 50 MW and that the threshold would force new large 
loads to develop grid-connected resources instead of BTMG resources.493  EDFps argues 
that this threshold would result in generation going through the interconnection process 
unnecessarily. 
 
489 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 6. 
490 EDFps Comments on Compliance Filing at 2, 4. 
491 Crusoe Comments on Compliance Filing at 4-5. 
492 Energy Artisans Protest of Compliance Filing at 2. 
493 EDFps Comments on Compliance Filing at 4.

Docket No. EL25-49-002, et al. 
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 EDFps argues the materiality threshold should instead be 100% of the load size at 
the electrical location, “combined with operational safeguards and appropriate 
transmission charges.”494  Specifically, EDFps proposes that retail BTMG larger than           
50 MW would still be permitted to net generation against load for the purposes of energy 
and capacity market settlements, but would pay transmission and/or distribution network 
charges on a gross basis.495  
 DPN similarly argues that PJM’s proposal may be too restrictive for digital 
infrastructure projects, many of which operate at scales well above 50 MW, and that 
behind-the-meter configurations can provide a viable pathway to speed-to-power.  
Additionally, DPN argues, the Commission should not require projects to rely on a 
framework that may compound PJM’s already significant queue and study delays without 
greater justification.  DPN argues that the Commission should require PJM to better 
justify why 50 MW is the appropriate threshold at this stage and whether a higher 
threshold, at least on an interim basis, would better accommodate current uncertainty 
while PJM and the Commission continue to refine their understanding of large load 
impacts.496 
 AEU/SEIA claim that PJM’s proposal to require site-located generation to enter 
the interconnection queue is unjust and unreasonable.  AEU/SEIA assert that PJM 
requires BTMG arrangements that exceed the materiality threshold or do not qualify for 
grandfather status to transition to a Co-Location Arrangement, which entails pursuing a 
full interconnection agreement with PJM.  AEU/SEIA contend that there is no benefit to 
subjecting these projects to the standard queue process as they do not require 
deliverability and will rarely trigger Network Upgrades.  AEU/SEIA requests that PJM 
be encouraged to establish a streamlined, expedited process for resources that do not 
intend to export to the grid, which would allow PJM to maintain visibility while 
minimizing delays for non-exporting resources.497 
ii. 
PJM Proposal to Tie Threshold to Generator 
Nameplate Rating 
 Several parties urge the Commission to reject PJM’s proposal to base the 
materiality threshold on the amount of generation that can be netted rather than load, 
 
494 Id. at 1-2. 
495 Id. at 4-5. 
496 DPN Comments on Compliance Filing at 4-5. 
497 AEU/SEIA Limited Protest of Compliance Filing at 11-13.

Docket No. EL25-49-002, et al. 
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arguing that this proposal is inconsistent with the December Order.498  BTMG Parties 
argue that the scale of the reduction in load (i.e., what PJM considers and plans for versus 
what PJM may actually need to serve) determines whether the potential for resource 
adequacy problems and cost shifts are problematic—not the nameplate of the generation 
used to effect the load reduction.499  Similarly, Industrials/Amtrak argue that nameplate 
capacity does not necessarily reflect the actual capability of BTMG, such as, for example, 
a steam system where the generation output is limited by the steam system’s 
capability.500   
 BTMG Parties further argue that such a nameplate generation-based threshold is 
unjust, unreasonable, and unduly discriminatory because it would also unnecessarily 
constrain commercial opportunities to serve loads with BTMG without better protecting 
reliability or commensurate reductions in resource adequacy or cost-shift risks and would 
treat differently BTMGs with similar resource adequacy and cost-shift impacts.  BTMG 
Parties argue that accepting PJM’s proposal would violate notice requirements and that 
the metering, telemetry, and control capabilities already deployed for existing BTMG 
resources demonstrate that BTMG can reliably comply with the operational requirements 
necessary to implement a netting-based threshold.501 
 BTMG Parties argue that, in the alternative, the Commission should require PJM 
to increase its proposed nameplate rating-based materiality threshold for retail BTMG 
eligibility to 200 MW to preserve opportunities for load to realize the commercial benefit 
of sizing nameplate generation above the amount of load that a retail customer seeks to 
net while still achieving the Commission’s aim of limiting resource adequacy impacts 
and cost-shift concerns.502  
 AEU/SEIA argue that PJM’s proposed threshold is inconsistent with how PJM 
assesses capacity accreditation in the capacity market and lacks the necessary flexibility 
to accommodate resource diversity and hybrid configurations such as storage paired with 
solar.  AEU/SEIA add that there are a number of reasons that, in a BTMG configuration, 
 
498 BTMG Parties Joint Protest of Compliance Filing at 1, 4-5; Industrials/Amtrak 
Joint Protest and Comments on Compliance Filing at 34-35 (citing December Order,             
193 FERC ¶ 61,217 at P 179); AEU/SEIA Limited Protest of Compliance Filing at 3.  
See also Earthjustice Reply Briefing at 24. 
499 BTMG Parties Joint Protest of Compliance Filing at 6. 
500 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 35. 
501 BTMG Parties Joint Protest of Compliance Filing at 2, 6-12. 
502 Id. at 2, 12-13.

Docket No. EL25-49-002, et al. 
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the generator’s nameplate capacity exceeds the customer’s netting.  AEU/SEIA contend 
that a reasonable approach would be to permit facilities to exceed 50 MW nameplate 
capacity provided the customer’s netting is limited to 50 MW, and the facility uses 
approved telemetry and automated system controls.503  Appalachian Voices argues that 
PJM’s compliance filing is unclear as to whether it will apply the 50 MW materiality 
threshold to all generation or to each individual generator at a single customer site.504   
 Industrials/Amtrak state that, if the Commission opts for a generation-based 
materiality threshold, they support PJM’s proposal on backup generation.505  
Industrials/Amtrak explain that emergency backup generation is often sized similarly to 
other on-site generation to function as a full backup power source and provides additional 
generation options in emergency conditions, such as the Department of Energy’s recent 
statement regarding the operation of private, behind-the-meter generation during Winter 
Storm Fern.506  EDFps argues that the Commission should direct PJM to clarify that 
battery energy storage systems and hybrid systems functioning in a load-following,             
non-exporting capacity manner during a curtailment event qualify under the “backup 
generation” exception from the materiality threshold for the revised retail BTMG netting 
rules and can continue to serve the load regardless of their size.507 
iii. 
PJM Proposal to Disqualify Network Customers 
Above the Materiality Threshold 
 Several parties argue that the Commission should allow netting up to the amount 
of the materiality threshold, rather than disqualifying a customer from netting for any 
amount of load if its BTMG exceeds the threshold.508  Industrials/Amtrak argue that this 
allowance would be more consistent with the December Order, reduce discrimination 
concerns, and avoid incentivizing loads to reduce the size of their generation to ensure 
 
503 AEU/SEIA Limited Protest of Compliance Filing at 4-5. 
504 Appalachian Voices Limited Protest of Compliance Filing at 4 (citing 
Compliance Transmittal at 11-12). 
505 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 10. 
506 Id. at 40-41 (citing U.S. Department of Energy, Emergency Order                           
No. 202-26-06). 
507 EDFps Comments on Compliance Filing at 8. 
508 Id. at 9, 34; Eastman Protest and Comments on Compliance Filing at 7; Energy 
Artisans Protest of Compliance Filing at 2; EDFps Comments on Compliance Filing at 5.

Docket No. EL25-49-002, et al. 
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netting eligibility.509  Industrials/Amtrak contend that PJM’s proposal would distort 
investment decisions, produce outcomes disconnected from actual system needs, harm 
resource adequacy, and harm economic development opportunities in PJM.510   
 Energy Artisans contend that by rejecting a hybrid BTMG and Co-Location 
approach, under which facilities could net up to the materiality threshold, PJM would 
force large loads off of BTMG status and onto the grid.511  EDFps disagrees with PJM 
that allowing netting up to the amount of the materiality threshold would lead to 
additional metering costs, noting that grandfathered entities and those below the threshold 
would not incur any such costs.  EDFps also argues that it should be up to individual 
entities whether the additional cost for metering is worth exceeding the threshold.  EDFps 
states that load served by a retail BTMG resource would be required to purchase NFCD 
transmission service up to the amount covered by the retail BTMG and FCD transmission 
service for the remainder of the load and could not lean on the system.512  
iv. 
Answers 
 Indicated TOs argue that PJM’s proposed 50 MW materiality threshold strikes the 
appropriate balance between allowing continued use of retail BTMG and limitations to 
ensure reliability.  Indicated TOs agree with PJM that 50 MW is reasonable because it 
aligns with the PJM Board’s definition of large load additions, preserves existing 
treatment for smaller and longstanding retail BTMG arrangements, and avoids sweeping 
in retail customers whose grid impacts are comparatively limited.  Indicated TOs argue 
that PJM reasonably based the threshold on generator size because generator capacity is 
static.513 
 Industrials/Amtrak argue that the Indicated TOs fail to substantiate their position 
with any evidence in support of the 50 MW threshold, and do not address any of the 
arguments for a 200 MW or greater threshold.  Industrials/Amtrak contend that load 
under 200 MW, particularly industrial and institutional load, is not driving current 
 
509 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 9-10. 
510 Id. at 36. 
511 Energy Artisans Protest of Compliance Filing at 2. 
512 EDFps Comments on Compliance Filing 2, 6-7. 
513 Indicated TOs April 24 Answer at 2-3.

Docket No. EL25-49-002, et al. 
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reliability challenges.514  Eastman contends that the Indicated TOs’ answer 
inappropriately lumps together all industrial BTMG facilities, ignoring that not all loads 
using BTMG create reliability and resource adequacy risks.515  BTMG Parties argue that 
Indicated TOs’ defense of a nameplate-based threshold is non-responsive to the BTMG 
Parties’ argument because the sole question before the Commission is compliance.516  
Indicated TOs respond that PJM’s 50 MW threshold is reasonable and should be 
accepted.517  Indicated TOs further argue that the Commission did not preclude a 
generation-based threshold, as it provided points of reference based on generator size, not 
the size of the load.518  Indicated TOs lastly allege that parties conflate the two issues of 
the materiality threshold and the grandfathering provision, and that the need for an 
adequate grandfathering provision is not a convincing reason to increase the size of the 
materiality threshold. 
d. 
Determination 
 We accept in part, and reject in part, PJM’s compliance filing with respect to the 
BTMG materiality threshold.  Specifically, we accept as just and reasonable PJM’s 
proposal to set the materiality threshold at 50 MW and to exclude on-site backup power 
from that threshold.  However, we reject PJM’s proposal to apply the threshold to the 
cumulative nameplate capacity of generation that is used to serve a retail load served by a 
Network Customer located at the same electrical location, rather than to the total amount 
of load that can be netted at that electrical location, because this proposal does not 
comply with the Commission’s directives in the December Order.519  We thus direct PJM 
to file, within 60 days of the date of this order, a compliance filing to revise its proposed 
 
514 Industrials/Amtrak Answer at 3-4 (citing Industrials/Amtrak Joint Protest and 
Comments on Compliance Filing at 25). 
515 Eastman Answer at 2 (citing December Order, 193 FERC ¶ 61,217 at P 107). 
516 BTMG Parties Answer at 2-3. 
517 Indicated TOs June 3 Answer at 3. 
518 Id. at 4. 
519 We therefore reject Proposed Tariff, § I.1 Definitions R-S (Retail Behind The 
Meter Generation) (46.0.0) and § VIII.A 400, Definitions R (Retail Behind The Meter 
Generation) (7.0.0).  We accept Proposed Tariff, § I.1 Definitions A-B (Behind The 
Meter Generation) (24.0.0); § III.34.2 (Netting of Retail Behind the Meter Generation) 
(1.0.0); § III.34.3 (Netting of Non-Retail Behind The Meter Generation) (2.0.0); § VII.A 
300, Definitions B (Behind The Meter Generation) (2.0.0); and § VIII.A 400,            
Definitions B (Behind The Meter Generation) (2.0.0).

Docket No. EL25-49-002, et al. 
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definition of Retail BTMG in its Tariff to permit a Network Customer to net up to                 
50 MW of load that it is serving using BTMG at a particular electrical location. 
 In the December Order, the Commission explained the materiality threshold as 
follows:  “Such a threshold should reduce the reliability and resource adequacy risks 
discussed above that large loads may pose to PJM, while also allowing for Network 
Customers to reduce their transmission charges in a transparent, not unduly 
discriminatory fashion.”520  Based on the record here, we find that a threshold of 50 MW 
is just and reasonable and preferable to the 200 MW threshold that some commenters 
propose because a 50 MW threshold will ensure that PJM plans its transmission system 
and procures sufficient capacity resources to serve a greater percentage of the load that, 
in the event that the BTMG that typically serves it is unavailable, PJM would be 
nonetheless obligated to serve.  As such, we find that PJM’s proposed 50 MW materiality 
threshold is more likely to help maintain resource adequacy and reliability relative to a 
larger threshold.521  Whereas Constellation argues that PJM’s proposed materiality 
threshold of 50 MW is too high and unsupported, we agree with PJM that 50 MW strikes 
a reasonable balance between a lower threshold, which may restrict netting more than 
necessary to respond to resource adequacy concerns, and a higher threshold, which would 
fail to address the resource adequacy concerns identified in the December Order.522   
 In response to protesters’ concerns that the proposed materiality threshold of                
50 MW is too low and will result in significant economic consequences to existing 
BTMG arrangements,523 we note that the Commission addressed this concern in the 
 
520 December Order, 193 FERC ¶ 61,217 at P 221. 
521 See id. P 186 (“We find that PJM’s existing BTMG rules may lead to both 
reliability and resource adequacy risks because PJM, per its Tariff, is obligated to serve 
transmission customers using BTMG but does not consider such customers in 
transmission and resource adequacy planning.”). 
522 See Vonage Holdings Corp. v. FCC, 489 F.3d at 1242; ExxonMobil Gas Mktg. 
Co. v. FERC, 297 F.3d 1071, 1085 (D.C. Cir. 2002) (“We are generally ‘unwilling to 
review line-drawing performed by the Commission unless a petitioner can demonstrate 
that lines drawn . . . are patently unreasonable, having no relationship to the underlying 
regulatory problem.’”) (citations omitted). 
523 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 27-28 
(alleging economic damage to retail customers); DPN Comments on Compliance Filing 
at 4 (expressing concern that 50 MW risks foreclosing pathways for digital infrastructure 
projects “through imposing additional barriers to utilization”); Eastman Protest and 
Comments on Compliance Filing at 6 (“the proposed threshold would remove the 
economic benefits that Eastman has relied on to continue operating its BTMG at the

Docket No. EL25-49-002, et al. 
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December Order and established separate mechanisms—a transition period of three years 
for Network Customers currently using PJM’s retail BTMG netting rules and 
grandfathering for certain entities in a BTMG arrangement—in recognition of the 
potential impacts for existing BTMG customers of a change in the retail BTMG netting 
rules.524  While we recognize the concerns raised in this record that adopting any 
limitations on netting may have economic consequences for individual Network 
Customers, we must balance those concerns against the Commission’s finding that PJM’s 
retail BTMG netting rules are unjust and unreasonable due to the reliability, resource 
adequacy, and cost-shifting concerns they create.525  As discussed above, the materiality 
threshold primarily serves to reduce reliability and resource adequacy risks that large 
loads may pose to PJM, and we find that PJM’s proposed 50 MW materiality threshold 
strikes a reasonable balance between mitigating those risks and limiting the costs 
associated with doing so. 
 We decline to require Eligible Customers seeking NITS on behalf of load with 
BTMG to take Interim NITS for load above the materiality threshold, as Energy Artisans 
request.  Energy Artisans appear to contemplate taking a combination of Interim NITS 
and NITS at the same Point of Delivery, which is not permitted.526  However, we note 
that such customers may take Interim NITS, as discussed in Part IV.527   
 We also disagree with arguments that the materiality threshold should be higher to 
ensure that BTMG resources have an incentive to operate efficiently.528  This concern 
 
Kingsport facilities . . . .”); Energy Artisans Protest of Compliance Filing at 1 (“PJM’s 
proposal to implement a 50 MW ‘Materiality Threshold’ for Retail BTMG is an arbitrary 
cap that ignores the long-term, capital-intensive investment cycles of large-scale 
industrial facilities.”). 
524 December Order, 193 FERC ¶ 61,217 at PP 222-224. 
525 Id. P 186. 
526 Energy Artisans Protest of Compliance Filing at 2 (“For sites exceeding this 
200 MW threshold, the Commission should direct PJM to utilize the proposed [Interim 
NITS] under the new Part XI of the Tariff.”). 
527 See supra Part IV.C.1.b.i (extending the three new transmission services set 
forth in the December Order to Eligible Customers taking service on behalf of load with 
BTMG that are willing and able to limit their energy withdrawals from the transmission 
system under certain conditions). 
528 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 7, 16, 
25, 32.

Docket No. EL25-49-002, et al. 
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does not overcome the Commission’s finding that large amounts of netted Network Load 
present reliability and resource adequacy risks.  When BTMG operates during peak or 
emergency conditions, it may enhance resource adequacy in the short term by lowering 
the demand on the system, but when it fails to operate (which, despite any incentive to 
operate, is possible), the result would be that PJM would have an obligation to serve the 
load that such BTMG typically serves without having planned adequate transmission 
facilities or procured sufficient capacity resources to fulfill that obligation.  The 
Commission found that risk unjust and unreasonable in the December Order.529  
 We also disagree with Energy Artisans that a 50 MW materiality threshold is 
unduly discriminatory because it establishes a 50 MW cap for Retail BTMG while 
maintaining a 3,000 MW regional cap for Non-Retail BTMG.530  The materiality 
threshold and the cap on Non-Retail BTMG function differently—the Non-Retail BTMG 
cap is a region-wide cap on the amount of load that may net using Non-Retail BTMG,531 
whereas the materiality threshold for Retail BTMG is on the amount of load that may net 
at a particular electrical location.532   
 We acknowledge EDFps’ concern that a 50 MW materiality threshold on Retail 
BTMG could encourage the development of smaller loads combined with smaller 
generators, and force new large loads to develop resources interconnected to the 
transmission system instead of BTMG resources.533  As the Commission explained in the 
December Order, the Commission eliminated retail BTMG netting to prevent large loads 
from using the retail BTMG netting rules; the Commission agreed with PJM that 
allowing large loads to net is problematic because such loads do not carry reserves and 
are able to rely on the transmission system when the BTMG is not sufficient to meet the 
load.534  EDFps’ alternative proposal would not remedy this concern because it would 
continue to net BTMG for the purposes of capacity market settlements.535 
 
529 December Order, 193 FERC ¶ 61,217 at P 186. 
530 Energy Artisans Protest of Compliance Filing at 2. 
531 See PJM, Intra-PJM Tariffs, OATT, § III, § 34.3 (Netting of Non-Retail Behind 
The Meter Generation) (1.0.0). 
532 December Order, 193 FERC ¶ 61,217 at P 221. 
533 EDFps Comments on Compliance Filing at 3-4. 
534 December Order, 193 FERC ¶ 61,217 at P 186. 
535 EDFps Comments on Compliance Filing at 4-5.

Docket No. EL25-49-002, et al. 
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 Further, we find AEU/SEIA’s assertion that requiring BTMG arrangements that 
exceed the materiality threshold or do not qualify for grandfather status to transition to a 
Co-Location Arrangement, which entails pursuing an interconnection agreement with 
PJM, is unjust and unreasonable is an untimely request for rehearing of the December 
Order.  In the December Order, the Commission found that PJM’s existing retail BTMG 
netting rules are unjust and unreasonable because they may lead to both reliability and 
resource adequacy risks in PJM.536  The Commission then directed PJM to revise its retail 
BTMG netting rules to establish a new MW materiality threshold for the amount of load 
at a particular electrical location that Network Customers may net using BTMG and to 
implement a transition process that includes the ability to grandfather certain entities with 
existing contracts.537  Because AEU/SEIA’s assertion challenges the Commission’s 
finding that PJM’s existing retail BTMG netting rules are unjust and unreasonable and 
the related compliance directives—and not whether PJM complied with those 
directives—we find that it is an untimely request for rehearing of the December Order 
and dismiss it on that basis.538  
 However, we agree with protesters that PJM’s proposal to design the materiality 
threshold for netting based on whether the “generation has a cumulative nameplate rating 
of no greater than 50 MW” fails to comply with the Commission’s directive in the 
December Order.  Specifically, the Commission directed PJM to “propose a new MW 
threshold for the amount of load at a particular electrical location that Network 
Customers may net by using BTMG.”539  As such, PJM’s proposal to instead apply the 
materiality threshold to the cumulative nameplate capacity of the generation used by a 
Network Customer to serve retail load located at the same electrical location is facially 
inconsistent with the December Order.   
 PJM alleges that its proposal to apply its proposed materiality threshold based on 
the cumulative nameplate capacity of the generation is consistent with or superior to the 
Commission’s directive to limit reliability and resource adequacy risks.  In particular, 
PJM alleges that its proposal is consistent with the Commission’s points of reference to 
various generator sizes, as well as the recognition that BTMG is defined as a generation 
unit rather than a load.  We find PJM’s arguments unpersuasive.  While the Commission 
 
536 December Order, 193 FERC ¶ 61,217 at P 179 (finding that “the existing 
BTMG rules may lead to both reliability and resource adequacy risks because PJM, per 
its Tariff, is obligated to serve transmission customers using BTMG but does not consider 
such customers in transmission and resource adequacy planning”). 
537 Id. P 179. 
538 Louisville Gas & Elec. Co., 185 FERC ¶ 61,120, at P 39 (2023). 
539 December Order, 193 FERC ¶ 61,217 at P 221 (emphasis added).

Docket No. EL25-49-002, et al. 
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referenced examples of generator sizes in the December Order, those examples were in 
reference to an unambiguous threshold for the amount of load that a Network Customer 
may net.540  In addition, while BTMG is defined as a generation unit, that fact alone is 
not a reason to propose to apply the materiality threshold to a Network Customer based 
on the amount of generation at the same electrical location rather than applying that 
threshold to the amount of load that may be netted at that location.  Lastly, PJM avers 
that, whereas load sizes can fluctuate, the nameplate capacity of a generator provides a 
bright line for purposes of qualifying for netting.  This argument too is unpersuasive, 
because regardless of whether a Network Customer’s load increases or decreases over 
time, the 50 MW materiality threshold we approve today makes clear how much of the 
load at a single electrical location a Network Customer may net using BTMG.   
 We also agree with protesters that PJM’s interpretation of the December Order as 
prohibiting any netting when a Network Customer exceeds the materiality threshold is 
incorrect.541  PJM supports its interpretation by pointing to the Commission’s directive in 
the December Order that PJM “maintain the current BTMG rules for customers that fall 
below a new MW materiality threshold,” but PJM reads this language out of context.542  
Read in full context, the Commission’s replacement rate for BTMG in the December 
Order only involves setting a new materiality threshold “for the amount of load at a 
particular electrical location that Network Customers may net by using BTMG,” which 
the Commission further stated would “allow[] for Network Customers to reduce their 
transmission charges in a transparent, not unduly discriminatory fashion.”543  Thus, we 
find that the Commission’s directive in the December Order allows for netting of load up 
to the newly established materiality threshold.  
 Moreover, the Commission expressly states that a materiality threshold “for all 
BTMG should reduce the reliability and resource adequacy risks that large or increasing 
 
540 Id. (“Although we make no finding in this order on a threshold that would be 
just and reasonable, we note as points of reference that PJM requires any generator larger 
than 10 MW to be individually metered and that the Commission’s definition of a small 
generator is 20 MW.”) (footnotes omitted). 
541 Compliance Transmittal 10-11 (“[T]he proposal is based on an interpretation of 
the compliance directive that demands an ‘all or nothing’ approach to Retail BTMG 
qualification—meaning that a Retail BTMG cannot both net up to a certain threshold but 
still potentially have generation and load above that threshold which cannot be net”); see 
Eastman Protest and Comments on Compliance Filing at 7; Industrials/Amtrak Joint 
Protest and Comments on Compliance Filing at 34. 
542 Compare December Order, 193 FERC ¶ 61,217 at P 179, with id. P 221. 
543 Id. P 221 (emphasis added).

Docket No. EL25-49-002, et al. 
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BTMG may pose to PJM.”544  To use an example similar to that provided by the BTMG 
Parties, PJM’s proposal would prohibit a Network Customer serving 50.1 MW of load 
using BTMG from netting any load, but it would allow a Network Customer serving             
50 MW of load using BTMG to net all of that 50 MW of load, even though they have 
virtually identical resource adequacy impacts on the transmission system.545  We find that 
this outcome would be unduly discriminatory and conflict with the December Order.546  
We also note that protesters persuasively dispute PJM’s suggestion that its proposal helps 
load with BTMG avoid incurring significant costs and compliance risks if their 
arrangements exceed the materiality threshold.547  We agree with EDFps that Network 
Customers should decide whether the costs and requirements associated with complying 
with the revised retail BTMG netting rules are appropriate or cost-effective for their 
business when determining whether to maintain or pursue BTMG arrangements.548   
 In response to EDFps’ request that the Commission clarify that electric storage 
resources and hybrid resources qualify for the back-up exemption, we note that PJM’s 
retail BTMG netting rules do not restrict what resources may qualify as back-up 
generation, but instead specify only that the generation must be at the same electrical 
location as the retail load and that it can only be used to serve such retail load during 
conditions that may threaten the integrity or reliability of the PJM Region or the regional 
power system.549   
 Accordingly, we direct PJM to file, within 60 days of the date of issuance of this 
order, a compliance filing to revise its Tariff consistent with the Commission’s directive 
in the December Order and our determination here.  Specifically, we reject PJM’s 
 
544 Id. P 179. 
545 BTMG Parties Joint Protest of Compliance Filing at 10. 
546 December Order, 193 FERC ¶ 61,217 at P 221 (“Such a threshold should 
reduce the reliability and resource adequacy risks discussed above that large loads may 
pose to PJM, while also allowing for Network Customers to reduce their transmission 
charges in a transparent, not unduly discriminatory fashion.”).   
547 See, e.g., BTMG Parties Joint Protest of Compliance Filing at 11 n.20 (“PJM 
does not provide any factual support for these assertions, and these statements do not 
match BTMG Parties’ experience as developers of BTMG in PJM.”). 
548 EDFps Comments on Compliance Filing at 7. 
549 Id., pt. VIII, Subpart A, section 400 Definitions R (definition of Retail Behind 
the Meter Generation) (7.0.0).

Docket No. EL25-49-002, et al. 
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proposed definition of Retail Behind The Meter Generation550 and direct PJM to submit a 
compliance filing modifying the Tariff to instead create a materiality threshold that 
allows Network Customers to net from their Network Load up to 50 MW of load served 
by using BTMG at a single electrical location. 
2. 
Grandfathering and Transition Period 
a. 
December Order 
 The Commission directed PJM to establish a transition period of three years for 
Network Customers currently using PJM’s existing retail BTMG netting rules.551  The 
Commission also directed PJM to include in its compliance filing revisions to grandfather 
entities with existing contracts for the specific purpose of effectuating a BTMG 
arrangement for the current term remaining under the existing contract.552  The December 
Order did not direct any changes to Non-Retail BTMG.553 
b. 
PJM Compliance Filing 
 PJM proposes to modify the existing Tariff definition of BTMG and add a new 
definition for Retail BTMG to implement a three-year transition period and provide the 
ability to grandfather certain entities with existing contracts.554  Specifically, PJM 
proposes that any existing retail BTMG with a contract that was entered into as of the 
date of the December Order would be permitted to remain eligible to net against Network 
Loads as Retail BTMG irrespective of the materiality threshold through the term of the 
contract.555  PJM explains that this proposal could include a wide variety of contracts, 
including “utility contracts, fuel contracts, maintenance contracts, and more.”556  PJM 
 
550 PJM, Proposed Tariff, § I.1 Definitions R-S (Retail Behind The Meter 
Generation) (46.0.0) and § VIII.A 400, Definitions R (Retail Behind The Meter 
Generation) (7.0.0). 
551 December Order, 193 FERC ¶ 61,217 at P 223. 
552 Id. P 224. 
553 Id. P 222. 
554 Compliance Transmittal at 6-7 (citing December Order, 193 FERC ¶ 61,217                
at P 179). 
555 Id. at 8. 
556 Id.

Docket No. EL25-49-002, et al. 
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further proposes that this exemption would encompass existing renewal or extension 
rights recognized under any existing contracts to “avoid interference with such reliance 
expectations upon which investment decisions likely have been made . . . .”557  PJM 
states that if the Commission accepts its proposal, it will explore with stakeholders 
whether manual language should be developed to help elaborate on what types of 
agreements may qualify.558 
c. 
Pleadings 
i. 
Comments 
 AEU/SEIA ask the Commission to reject PJM’s proposal to transition existing 
retail BTMG through December 18, 2028 and instead extend the transition period until 
the effective date of PJM’s compliance filing to avoid harming projects already 
underway.  AEU/SEIA allege that setting the grandfathering date earlier than the 
effective date for the new co-location pathways would leave a problematic gap for 
projects that were moving forward in good faith and exacerbate uncertainty.  AEU/SEIA 
argue that any project “in process” as of the transition date should be eligible for 
grandfathering if it has made significant progress toward completion though not fully 
operational.559  Otherwise, AEU/SEIA allege, PJM’s proposal will result in significant 
stranded assets.   
 Similarly, BTMG Parties argue that the deadlines for the transition period and 
grandfathering eligibility will exclude retail customers that recently finalized or will 
imminently finalize projects while providing limited system benefit.  BTMG Parties 
argue that PJM should be required to instead use the date of a Commission order acting 
on PJM’s filing, or, at minimum, 180 days from the December 18, 2025 date of the                 
Co-Location Order (June 16, 2026), as the date from which the grandfathering and 
transition period run.  BTMG Parties argue that this date would better afford a workable 
transition for market participants that does not penalize developers for attempting to 
develop resources during a historic resource adequacy crisis in PJM.560 
 AEU/SEIA also ask the Commission to clarify that the types of agreements that 
may qualify for PJM’s proposal include utility interconnection study agreements, 
engineering, procurement, and construction contracts, and any form of binding agreement 
 
557 Id. at 9. 
558 Id. at 9 n.32. 
559 AEU/SEIA Limited Protest of Compliance Filing at 7-9. 
560 BTMG Parties Joint Protest of Compliance Filing at 2-3, 13-16.

Docket No. EL25-49-002, et al. 
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between the load and the BTMG developer.561  Otherwise, AEU/SEIA warn, developers 
face the risk of delay and additional regulatory burdens that could remove projects 
underway.   
 Industrials/Amtrak support PJM’s proposal to grandfather existing contracts, 
noting that BTMG customers operate under diverse agreements, some of which renew 
year to year, which should be eligible for grandfathering.  Industrials/Amtrak also argue 
that grandfathering rules and status should be clear, broadly construed, and easily 
confirmed for existing BTMG customers to ensure stability and regulatory certainty.562 
 AEU/SEIA argue that PJM’s proposal is unjust and unreasonable because it is not 
clear as to whether grandfathering status applies to the site itself or the generator asset.  
AEU/SEIA suggest that grandfathering the generation while allowing these existing 
customers to pursue additional BTMG below the materiality threshold is a logical 
extension of PJM’s observation that additions below the materiality threshold would have 
little or no impact.  AEU/SEIA argue that clarifying that customers with grandfathered 
BTMG have a “clean slate” to pursue additional BTMG up to the materiality threshold 
would also allow existing customers to help address PJM’s resource adequacy and 
infrastructure needs.  AEU/SEIA contend that many existing customers have neither the 
desire nor the economic incentive to pursue co-location and that, for smaller projects, 
PJM’s full interconnection process will be too costly and complex.563  Eastman similarly 
requests that the Commission require PJM’s grandfathering provision to apply to BTMG 
facilities rather than the service agreement.  Otherwise, Eastman argues, a BTMG facility 
could lose its grandfathered status if the relevant service agreement is modified because, 
for example, the facility was modified to become more efficient.564 
 Industrials/Amtrak argue that most BTMG differs from the large loads that the 
Commission addressed in the December Order.  Specifically, Industrials/Amtrak argue 
that BTMG is not new, is not the cause of the changed circumstances, and does not 
present the reliability risks posed by large, inverter-based loads.565  Further, 
Industrials/Amtrak contend, new large loads differ from BTMG in that new large loads 
do not have substantial cogeneration, do not generally operate large motors that can help 
 
561 AEU/SEIA Limited Protest of Compliance Filing at 7-8. 
562 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 10, 39. 
563 AEU/SEIA Limited Protest of Compliance Filing at 9-11. 
564 Eastman Protest and Comments on Compliance Filing at 7. 
565 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 6-7, 
13; see also Energy Artisans Protest of Compliance Filing at 1.

Docket No. EL25-49-002, et al. 
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with stability on the grid, can turn off and on nearly instantaneously, and can reach sizes 
well beyond traditional BTMG and the 200 MW threshold proposed by 
Industrials/Amtrak.  Industrials/Amtrak further claim the December Order “did not find 
that BTMG rules were unjust and unreasonable as used by manufacturers with 
cogeneration, other QFs (which are size limited under PURPA), or even traditional 
‘large’ loads with BTMG . . . .”566   
ii. 
Answers 
 Indicated TOs argue that PJM’s materiality threshold should be paired with 
grandfathering provisions that appropriately recognize that customers have relied on 
retail BTMG netting rules and eliminating such rules could cause financial harm.  
Indicated TOs therefore propose several additions and clarifications to PJM’s proposal.  
First, Indicated TOs argue that grandfathering treatment should extend to all projects that 
are not yet in service and would have been eligible for retail BTMG treatment, but have 
made “substantial progress towards completion.”567  Indicated TOs also argue that the 
exclusion regarding existing contracts should be construed broadly to cover a wide range 
of contracts and recognition of renewal rights in those contracts.  Indicated TOs argue 
that existing retail BTMG arrangements that have been physically in service and 
operating for a significant period of time should be grandfathered to avoid disrupting 
long-standing arrangements.568 
 BTMG Parties and Industrials/Amtrak agree with Indicated TOs that 
grandfathering should extend to projects that would have been eligible for retail BTMG 
treatment but for the imposition of the materiality threshold and have made substantial 
progress toward completion in order to protect the investment-backed expectations of 
PJM customers (and the BTMG developers) and to ensure just and reasonable rates.  
BTMG Parties and Industrials/Amtrak also argue that the existing contract exception 
should be construed broadly to cover a wide range of contracts.569  BTMG Parties also 
argue that arrangements that have been physically in service and operating for a 
significant period of time should be grandfathered.570 
 
566 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 14 
(emphasis in original). 
567 Indicated TOs April 24 Answer at 3. 
568 Id. at 3-4. 
569 BTMG Parties Answer at 2-4; Industrials/Amtrak Answer at 6-7. 
570 BTMG Parties Answer at 4.

Docket No. EL25-49-002, et al. 
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d. 
Determination 
 We find that PJM’s proposed Tariff revisions comply with the directives in the 
December Order.571   
 First, we find that PJM complies with the directive to revise its Tariff to allow 
Network Customers already using the retail BTMG netting rules to continue to do so for 
a transition period of three years from the date of issuance of the December Order.572  
AEU/SEIA and BTMG Parties express concern that such a transition period unfairly 
harms entities that were planning to finalize arrangements in order to use PJM’s retail 
BTMG netting rules.  But these parties did not seek rehearing of the Commission’s 
decision in the December Order to establish a transition period to minimize the impact on 
existing BTMG customers.  In that order, the Commission explicitly directed PJM to 
“allow Network Customers already using the BTMG rules to continue to do so for a 
transition period of three years . . . from the date of issuance of this order.”573  Thus, we 
find that AEU/SEIA’s and BTMG Parties’ arguments constitute untimely requests for 
rehearing of the December Order.574  However, even if these arguments were properly 
before us, AEU/SEIA and BTMG Parties offer no suggested transition period to 
encompass certain potential BTMG customers in a manner that would not be arbitrary.575 
 Second, we find that PJM complies with the directive to revise its Tariff to 
grandfather entities with existing contracts that effectuate a BTMG arrangement for the 
 
571 See PJM, Proposed Tariff, § I.1 Definitions R-S (Retail Behind The Meter 
Generation) (46.0.0) and § VIII.A 400, Definitions R (Retail Behind The Meter 
Generation) (7.0.0). 
572 December Order, 193 FERC ¶ 61,217 at P 223; PJM, Compliance Filing, 
attach. B (defining Retail BTMG to provide “for a transition period through                  
December 18, 2028” for Retail BTMG “used to serve a retail load served by a Network 
Customer to net load prior to December 18, 2025.”). 
573 December Order, 193 FERC ¶ 61,217 at P 223. 
574 See, e.g., Louisville Gas & Elec. Co., 185 FERC ¶ 61,120 at P 39; ISO New 
Eng. Inc., 132 FERC ¶ 61,098, at P 12 (2010) (“The Commission has held that requests 
to alter a compliance filing in a manner that differs from the order requiring the 
compliance filing constitute a collateral attack on the order requiring the compliance 
filing.”).  
575 See BTMG Parties Joint Protest of Compliance Filing at 15 (characterizing a 
“limited class of BTMG developers that were very close to finalizing their projects”).

Docket No. EL25-49-002, et al. 
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current term remaining under the existing contract.576  In response to concerns from 
AEU/SEIA and BTMG Parties, we clarify that the Tariff proposal applies to a contractual 
arrangement—for which generation used to serve retail load served by a Network 
Customer to net load is the subject—“that was in effect as of December 18, 2025.”  
Therefore, entities with projects that have contractual arrangements “in place, even if 
they are not yet fully operational” by December 18, 2025 may qualify under the Tariff 
proposal.577  In addition, in response to AEU/SEIA, we clarify that the types of 
agreements that may qualify under PJM’s proposal may include engineering, 
procurement, and construction contracts, and we encourage PJM, as it states in its 
transmittal, to explore developing language in its manuals on what other types of 
agreements may qualify.578  Moreover, in response to AEU/SEIA and Eastman, who raise 
overlapping concerns about whether grandfathering applies to the generator, we clarify 
that it does apply to the generator, as the Tariff proposal on grandfathering reflects.579  In 
further response to Eastman, parties to an existing BTMG contract could modify the 
agreement to, for example, make the facilities more efficient—provided that the 
modification is not prohibited by the existing contract and does not fundamentally alter 
the contractual arrangement that was in effect as of December 18, 2025.  And in further 
response to AEU/SEIA, we clarify that customers with BTMG within the scope of this 
grandfathering provision may also avail themselves of the new materiality threshold to 
net up to 50 MW of load served by a Network Customer because this threshold applies to 
a particular electrical location. 
3. 
QFs and Cogeneration Facilities 
a. 
PJM Compliance Filing 
 PJM proposes that the new materiality threshold should not apply to any QF over 
50 MW serving as Retail BTMG as of the date of the December Order.  PJM 
 
576 December Order, 193 FERC ¶ 61,217 at P 224; PJM, Compliance Filing, 
attach. B (defining Retail BTMG to include “any generation used to serve a retail load 
served by a Network Customer to net load if it is the subject of a contractual arrangement 
(including but not limited to a bilateral agreement or interconnection agreement) that was 
in effect as of December 18, 2025 through the end of the term of such agreement, which 
may be renewed or extended per the terms of such agreement”). 
577 AEU/SEIA Limited Protest of Compliance Filing at 7. 
578 Compliance Transmittal at 9 n.32. 
579 PJM, Compliance Filing, attach. B (defining Retail BTMG in part to include 
“any generation used to serve a retail load served by a Network Customer to net load if it 
is the subject of a contractual arrangement . . .”).

Docket No. EL25-49-002, et al. 
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acknowledges that the December Order does not reference PURPA, yet because the 
December Order was issued against the backdrop of PURPA, “PJM interprets the 
Commission’s [grandfathering] compliance directive as allowing the extension of legacy 
treatment” to such facilities.  PJM states that some of the QFs impacted by this exemption 
are cogeneration facilities that provide economic and energy efficiency benefits.580  In 
support of its proposal, PJM notes that QFs have size limitations and cogeneration QFs 
must meet efficiency requirements.581  PJM explains that BTMG with existing 
contractual arrangements or QF status have been in place without any known operational 
issues to date, and so should be allowed to continue netting under their existing 
arrangements.582 
b. 
Pleadings 
 Industrials/Amtrak argue that QFs should be eligible for retail netting for their full 
load, but the eligibility should not be linked to QF status as of the date of the order.583  
Industrials/Amtrak explain that, without retail netting, QFs may be denied the backup 
service to which they are entitled under PURPA.  Industrials/Amtrak argue that for 
cogeneration QFs, “the BTMG netting construct aligns with their efficient, reliable 
energy production configurations, matching the intent of Congress and the 
[Commission].”584  Industrials/Amtrak argue that QFs have stronger operational and 
financial incentives to operate reliably and efficiently than other generators and must 
meet certain efficiency standards.  However, Industrials/Amtrak note that many resources 
eligible to be QFs have not maintained QF status because PURPA permits the 
Commission to deem certain QFs as having sufficient market access that it removes (for 
those QFs) the utility’s obligation to purchase excess power generated by the QF.  
Industrials/Amtrak explain that many customers with QFs were required by this status 
change to secure interconnection service and market-based rate authority to sell excess 
energy into the PJM markets.585  Industrials/Amtrak argue this “history should not limit 
 
580 Compliance Transmittal at 9-10. 
581 Id. at 10 (citing 16 U.S.C. § 824a-3; 18 C.F.R. § 292.204 (2025)). 
582 Id.  
583 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 8, 17. 
584 Id. at 8. 
585 Id. at 8, 20, 22.

Docket No. EL25-49-002, et al. 
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the ability of retail customers with cogeneration facilities to avail themselves of retail 
BTMG netting for energy production behind the retail meter.”586 
 Industrials/Amtrak argue that the BTMG netting rules ensure QFs have access to 
backup power to which they are entitled by PURPA, at rates that are not based upon an 
assumption that forced outages or other reductions in electric output by all QFs on the 
system will occur simultaneously, during system peak, or both.587  Industrials/Amtrak 
contend that the FCD or NFCD transmission services would not be sufficient to replace 
netting, because the FCD transmission service is calculated on the maximum the load 
might draw from the grid when the QF would only use the system sporadically, and 
NFCD transmission service must be scheduled in advance.  Industrials/Amtrak also argue 
that these services do not align with the costs or risk profile of cogeneration QFs, such 
that, without netting, QF customers may lose their ability to manage costs even if their 
load and generation are synchronized or they never rely on transmission services, 
creating a cost-causation gap.588 
 Industrials/Amtrak argue that exempting QFs is appropriate and consistent with 
the goals of the December Order because the Commission did not address PURPA.  
Industrials/Amtrak also argue that no circumstances have changed with regards to QFs, 
which have been operating similarly for decades, and that PJM acknowledges that 
existing retail BTMG arrangements with QFs have been in place without operational 
issues.  Industrials/Amtrak further argue that QFs contribute to resource adequacy and 
reliability because some are limited in their use of the transmission system by the 
integration between the load and generation.589 
 Eastman argues that the proposed changes to BTMG netting ignore the operational 
realities of facilities like Eastman’s Kingsport facility, which uses its on-site electrical 
generation not only to provide electric power but also steam necessary for industrial 
processes at the facility.  Eastman explains that if the Kingsport facility is unable to 
generate power, it also cannot generate steam, which reduces the industrial output and the 
need for additive power from the grid.  Eastman claims that during periods of grid stress, 
the Kingsport facility is more likely to support the grid than to create operational 
 
586 Id. at 22. 
587 Id. at 19. 
588 Id. at 20-21. 
589 Id. at 17-19, 21.

Docket No. EL25-49-002, et al. 
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constraints.  Therefore, the Commission should allow BTMG facilities like the Kingsport 
facility to continue to net.590 
c. 
Answer 
 Industrials/Amtrak note that many of the customers impacted by the change in 
BTMG netting rules are QFs under PURPA, subject to efficiency standards (and for     
non-cogeneration QFs, size limits).591   
d. 
Determination 
 Consistent with our determination on rehearing,592 PJM must submit a further 
compliance filing that includes a process to exempt certain cogeneration QFs from the 
new retail BTMG netting rules if they demonstrate that they are integrated with load such 
that, when their generating facility trips offline, the load follows.  We therefore reject 
PJM’s compliance filing as it relates to QFs.  Specifically, we reject PJM’s proposal to 
exempt from the materiality threshold all QFs serving as retail BTMG as of the date of 
the December Order.593  PJM has not demonstrated that all load with BTMG that is either 
designated, or eligible to be designated, as a QF is meaningfully distinguishable from 
load with other categories of BTMG for purposes of the concerns and directives 
discussed in the December Order. 
 In the December Order, the Commission found that PJM’s retail BTMG netting 
rules could create resource adequacy and reliability risks because PJM is obligated to 
serve transmission customers using BTMG but does not consider such customers in 
transmission and resource adequacy planning.594  The Commission found that PJM’s 
existing retail BTMG netting rules do not limit the amount of qualifying load that a 
Network Customer may net by using BTMG and do not provide any protections against 
this potential transmission and resource adequacy planning problem or against the costs 
of maintaining sufficient resources to serve these loads being shifted onto other 
 
590 Eastman Protest and Comments on Compliance Filing at 5, 8. 
591 Industrials/Amtrak Answer at 3, 5-6. 
592 See supra Part IV.C.1.c.i. 
593 Compliance Transmittal at 9; PJM, Proposed Tariff, § I.1 Definitions R-S 
(Retail Behind The Meter Generation) (46.0.0) and § VIII.A 400, Definitions R (Retail 
Behind The Meter Generation) (7.0.0). 
594 December Order, 193 FERC ¶ 61,217 at P 186.

Docket No. EL25-49-002, et al. 
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customers.595  The Commission did not distinguish in its determination between load 
served by QFs that are BTMG and load served by other categories of BTMG. 
 PJM argues that some QFs may have economic benefits and are energy efficient, 
but PJM does not demonstrate that loads served by QFs that are BTMG do not cause the 
concerns the Commission discussed in the December Order.596  Nor does PJM 
demonstrate why these loads are not similarly situated to other loads served by other 
categories of BTMG.   
 PJM also notes that QFs have size limitations and cogeneration QFs must meet 
efficiency requirements.597  However, the Commission in the December Order directed a 
materiality threshold because netting a smaller amount of load does not raise the same 
level of resource adequacy and reliability concerns as netting above the threshold.598  
PJM does not demonstrate why the materiality threshold should apply differently to load 
served by QFs that are BTMG and load served by other categories of BTMG.  Further, 
efficiency requirements are not unique to QFs—other generators may have efficiency 
requirements for other reasons or meet similar efficiency targets on their own.  PJM has 
not demonstrated why such requirements are a meaningful consideration in whether to 
apply disparate treatment to load served by QFs that are BTMG and load served by other 
categories of BTMG.  Industrials/Amtrak similarly argue that QFs contribute to resource 
adequacy and reliability because some are limited in their use of the transmission system 
due to the integration between the load and generation.599  However, as 
Industrials/Amtrak acknowledge, this is only true of some QFs, and above we have 
recognized that a particular subgroup, cogeneration QFs, warrant different treatment. 
 Industrials/Amtrak also argue that it is not clear whether QFs will have access to 
the FCD or NFCD transmission services.600  As discussed supra, Eligible Customers 
taking transmission service on behalf of Co-Located Loads, as well as Eligible Customers 
taking transmission service on behalf of a load with BTMG, may elect to take FCD 
 
595 Id.  
596 See Compliance Transmittal at 10 (broadly asserting that BTMG arrangements 
with QF status have been netting within PJM without known operational issues to date). 
597 Compliance Transmittal at 10 (citing 16 U.S.C. § 824a-3; 18 C.F.R. § 292.204). 
598 December Order, 193 FERC ¶ 61,217 at P 221. 
599 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 18-19, 
21. 
600 Id. at 20.

Docket No. EL25-49-002, et al. 
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and/or NFCD transmission services.601  While we acknowledge that Industrials/Amtrak 
also argue that these new transmission services will not replace netting,602 our 
determination herein to allow Eligible Customers taking transmission service on behalf of 
loads with BTMG to take transmission service based on contract demand rather than 
NITS should they so choose could help such Eligible Customers to manage costs if they 
infrequently rely on transmission service or can reserve needed transmission service in 
advance (such as when the QF that serves them is on a planned maintenance outage).  
 Industrials/Amtrak argue that without retail netting, QFs may be denied access to 
backup service at rates that are not based upon an assumption that forced outages or other 
reductions in electric output by all QFs on the system will occur simultaneously, during 
system peak, or both, as required by PURPA.  Under the Commission’s PURPA 
regulations, the rates at which a host utility provides backup service must be just and 
reasonable and (1) shall not be based upon an assumption (unless supported by factual 
data) that forced outages or other reductions in output by all QFs on an electric utility’s 
system will occur simultaneously, or during system peak, or both; and (2) shall consider 
the extent to which scheduled outages of the QF can be usefully coordinated with 
scheduled outages of the utility’s facilities.603  The Commission’s directive in the 
December Order to PJM to revise its Retail BTMG netting rules implicates the terms of 
the Tariff for the provision of transmission service, specifically NITS, not back-up 
service.  Therefore, Industrials’/Amtrak’s concern regarding backup service appears to 
conflate rates for sales of back-up power and rates for transmission service, rendering the 
concern misplaced.  As is already the case elsewhere, such as in Midcontinent 
Independent System Operator, Inc. (MISO),604 NITS transmission rates in PJM, going 
forward, will be based on gross demand during the system peak.  Because this directive 
from the December Order has no bearing on the rates at which a host utility provides 
backup service to QFs, it necessarily does not conflict with the requirement in the 
Commission’s PURPA regulations that the rates for such backup service not assume all 
QFs are on forced outage.   
 
601 See supra Part IV.B.3.c. 
602 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 20. 
603 18 C.F.R. § 292.305(c). 
604 See Midwest Indep. Transmission Sys. Operator, Inc., 106 FERC ¶ 61,073,            
at P 26 (2004) (“[MISO]’s proposal to base Network Service charges for delivery of 
station power on the basis of coincident-peak output is not consistent with its OATT or 
with Commission precedent.  Accordingly, [MISO] should include load served by 
behind-the-meter generation, including station power load met through                                 
on-site self-supply, in Network Load when it charges for Network Service.”).

Docket No. EL25-49-002, et al. 
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 With respect to Eastman’s arguments, Eastman appears to reference a 
cogeneration facility, which uses its on-site electrical generation to provide not only 
electric power but also steam necessary for industrial processes at the facility.605  Because 
we set aside, in part, the December Order and find that certain cogeneration QFs should 
be exempted from the replacement rate upon a demonstration that they do not present the 
reliability or resource adequacy concerns discussed in the December Order, Eastman’s 
concern appears to be addressed.606   
B. 
Transmission Service 
1. 
December Order 
 The Commission directed PJM to modify its Tariff to require that the Eligible 
Customer taking transmission service on behalf of a Co-Located Load takes one of three 
transmission services:  (1) NITS or Interim NITS, (2) a new FCD transmission service, or 
(3) a new NFCD transmission service.607  The December Order set many of the terms and 
conditions of these services for paper hearing procedures.608  
 The December Order stated that Interim NITS must allow an Eligible Customer 
that has requested NITS on behalf of a Co-Located Load to take non-firm transmission 
service that can be interrupted until the Network Upgrades necessary to provide NITS are 
complete and the Co-Located Load can be designated as Network Load.609  The 
Commission also found that this service should be temporary, available only to Eligible 
Customers that have requested NITS on behalf of Co-Located Loads that cannot yet be 
reliably served with NITS and only until the necessary Network Upgrades are completed 
and the Co-Located Load is designated as Network Load.  The December Order further 
stated that Interim NITS would be optional for an Eligible Customer seeking NITS on 
behalf of a Co-Located Load and only available to the extent PJM determines that it can 
provide some level of interim service reliably.  The Commission found that Eligible 
Customers should pay the NITS rate for this service, as well as ancillary services charges 
and charges for black start service, but they will not be charged for generation capacity 
because, as interruptible loads, capacity will not be procured on their behalf until such 
time as the Network Upgrades are in place to serve them.  The Commission clarified that 
 
605 Eastman Protest and Comments on Compliance Filing at 5. 
606 See supra Part IV.C.1.c.i.c. 
607 December Order, 193 FERC ¶ 61,217 at P 193. 
608 Id. P 194. 
609 Id. P 200.

Docket No. EL25-49-002, et al. 
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Interim NITS may not be combined with the FCD transmission service or NFCD 
transmission service. 
 With respect to FCD and NFCD transmission services, the Commission found 
these services should be permanent transmission services available to Eligible Customers 
taking transmission service on behalf of Co-Located Load.610  The December Order 
provided that the Co-Located Load must be able and willing to prevent or limit its energy 
withdrawals and must be separately metered from the associated generator.  The 
December Order also stated that Eligible Customers taking transmission service on behalf 
of Co-Located Loads may take a combination of FCD transmission service and NFCD 
transmission service, but that Eligible Customers taking transmission service on behalf of 
Co-Located Loads that will not withdraw energy from the transmission system must take 
NFCD transmission service at 0 MW.  The Commission also found that Eligible 
Customers taking either service on behalf of Co-Located Load would be charged for 
regulation and black start services based on gross demand, rather than the reserved 
amount of transmission service.611 
 The Commission found that FCD transmission service should have the same 
reservation and curtailment priority as existing firm transmission services at the level of 
the contract demand and be charged for transmission, ancillary services, and capacity 
based on the contract demand, with the exception of regulation and black start services.612  
The Commission explained that PJM would only have an obligation to plan for the 
Network Upgrades necessary to serve Eligible Customers taking this new FCD 
transmission service on behalf of Co-Located Loads at their contract demand, and that 
PJM would procure capacity for these customers and should charge them based on their 
contract demand.613  The Commission further found that FCD transmission service 
should have a minimum term of one year and that PJM should propose an anti-toggling 
mechanism for Eligible Customers switching between FCD and NFCD transmission 
services.614 
 With respect to NFCD transmission service, the Commission found the service 
should be available during normal operation and curtailed during emergency operations, 
similar to existing non-firm transmission service options.  The Commission found the 
 
610 Id. P 206. 
611 Id. PP 209, 216. 
612 Id. PP 208-209. 
613 Id. P 210. 
614 Id. P 213.

Docket No. EL25-49-002, et al. 
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service should be available for terms ranging from one hour to one month and charged 
based on as-reserved contract demand.615  The December Order clarified that PJM should 
not include NFCD transmission service loads in its transmission or resource adequacy 
planning.616 
2. 
PJM Compliance Filing 
 PJM clarifies that the compliance filing only includes the organizational Tariff 
changes needed to implement the Commission’s compliance directives regarding creating 
new transmission services and that the majority of the changes will be determined 
through the paper hearing.617  First, PJM submits several “shell” Tariff sheets, including a 
new Part XI governing the new transmission services, new Attachment F-3A for the 
service agreement for Eligible Customers taking NITS or Interim NITS on behalf of a 
Co-Located Load, and Attachment F-4 for the service agreement for Eligible Customers 
taking FCD transmission service or NFCD transmission service on behalf of a                       
Co-Located Load.618  PJM states that it will file the full text of these sections upon the 
Commission’s decision following the conclusion of the paper hearing.619 
 PJM states that it further proposes modifications to Tariff Part III, governing 
NITS, to clarify that an Eligible Customer taking transmission service on behalf of               
Co-Located Load must take a transmission service or take steps to disconnect the load 
from the transmission system.620  PJM also proposes new language clarifying that an 
Eligible Customer taking transmission service on behalf of a Co-Located Load may not 
take NITS or Interim NITS at the same time as FCD or NFCD transmission service.621  
Finally, PJM proposes that Co-Located Load that is not served by an Eligible Customer 
 
615 Id. PP 215-216. 
616 Id. P 218. 
617 Compliance Transmittal at 18-19. 
618 Id. at 19-21. 
619 Id. at 21. 
620 Id. at 22. 
621 Id. at 22-23.

Docket No. EL25-49-002, et al. 
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taking transmission service on its behalf “must take all necessary steps to disconnect 
from the Transmission System.”622 
3. 
Pleadings 
 EDFps supports PJM’s proposed framework for the new transmission services.623  
Constellation requests modifications to PJM’s proposed Tariff revisions for Interim 
NITS, including:  (1) replacing a load’s “option to seek” Interim NITS with an “option to 
take”; (2) revising section 28.1 of the Tariff to clarify that Interim NITS is available to 
Eligible Customers taking service on behalf of Co-Located Load; and (3) revising  
section 29.1 of the Tariff to clarify that the required conditions to receive NITS also 
apply to Interim NITS.624 
 Crusoe argues that PJM’s proposal in the paper hearing does not answer critical 
questions such as how the initial contract demand quantity is determined, whether 
contract demand quantities can be adjusted as Co-Located Load grows in phases, or how 
PTPS interacts with Co-Location Arrangements where both generation and load sit on the 
developer’s side of the Point of Change in Ownership.625 
 Crusoe supports Interim NITS as a workable, near-term solution to allow load to 
operate on the transmission system while a Co-Located Generator and/or retail BTMG is 
still being built and interconnected.626  Crusoe claims, however, that PJM’s proposed 
approach appears to treat a new Co-Located Generator as equivalent to a Network 
Resource prior to it receiving such status.  On that basis, Crusoe speculates that PJM may 
intend to prevent a Co-Located Generator or retail BTMG from supplying energy to              
Co-Located Load during a grid curtailment event if that load is being served via Interim 
NITS.  Crusoe contends that this prohibition would create a disincentive to large load 
customers using Interim NITS as an option for speedy interconnection.   
 DCC similarly alleges that PJM’s proposal to prohibit customers from relying on a 
Co-Located Generator during curtailment events makes the proposal unworkable and 
without practical value.  DCC also requests that PJM define the trigger, scope, and 
sequence of Interim NITS curtailment with respect to the operational limits identified in 
 
622 PJM, Proposed Tariff, Part III (NITS) (4.0.0). 
623 EDFps Comments on Compliance Filing at 8. 
624 Constellation Protest and Comments on Compliance Filing at 18-19. 
625 Crusoe Comments on Compliance Filing at 8. 
626 Id. at 6.

Docket No. EL25-49-002, et al. 
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the study and should not be able to curtail load for unrelated, broader resource adequacy 
concerns.627 
 Joint Parties argue that the Commission should reject PJM’s proposed Tariff 
revisions that preclude retail loads served by BTMG from taking the new transmission 
services and otherwise limit eligibility for the new transmission services to load that is 
connecting to a generator with interconnection rights.  Joint Parties argue that these retail 
loads are similarly situated to Co-Located Loads in their willingness and ability to limit 
their energy withdrawals from the transmission system under certain conditions.628  
 DCC argues that PJM’s proposal does not provide clear timelines for customers to 
be transitioned from Interim NITS to NITS.629  DCC expresses concern that, without 
clear timelines, Interim NITS could persist indefinitely, creating uncertainty for 
customers making long-term investments. 
4. 
Answers 
 Indicated TOs argue that the Commission should reject requests to reject or defer 
action on PJM’s proposal to limit the new transmission services to Co-Located Load, 
because, Indicated TOs contend, the December Order limited such services to Eligible 
Customers taking transmission service on behalf of Co-Located Load.  Indicated TOs 
argue that there is no evidence in the record to support that load-only customers should 
be entitled to use the new transmission services, which Indicated TOs explain are tied to 
generator-specific attributes that load-only customers do not share, such as an associated 
generator, separate metering from the generator, and the ability and willingness to 
prevent or limit withdrawals through the Co-Location Arrangement itself.630 
 Indicated TOs state they do not oppose the requested clarification that Interim 
NITS customers be permitted to continue serving on-site load with a Co-Located 
Generator during a curtailment event, provided that PJM implements safeguards to ensure 
that any such operation does not result in unreserved use of the transmission system or 
otherwise compromise reliability.631 
 
627 DCC Comments on Compliance Filing at 6-7. 
628 Joint Parties Protest of Compliance Filing at 10. 
629 DCC Comments on Compliance Filing at 8. 
630 Indicated TOs April 24 Answer at 6-7. 
631 Id. at 7-8.

Docket No. EL25-49-002, et al. 
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 BTMG Parties argue that the record contains ample evidence to support extending 
new transmission service eligibility to all customers willing and able to limit withdrawals 
from the grid, including load-only customers served by BMTG or otherwise able to 
consume flexibly.632  BTMG Parties contest Indicated TOs’ claim that there is absolutely 
no evidence in the record, noting that the Commission relied on Antora’s comments 
explaining that its thermal battery technology provides for an inherently flexible,                   
low-load factor load, whether or not co-located with generation.633  BTMG Parties argue 
that the ability to inject to the grid is not required to enable a load to limit withdrawals 
from the transmission system, and that the Commission should require PJM to tailor new 
transmission service eligibility more closely to the Commission’s justification in issuing 
the Co-Location Order, namely the willingness and ability to limit withdrawals from the 
transmission system under specified circumstances.634  BTMG Parties contend that if a 
load is able to meet technology-neutral technical requirements to demonstrate reliable 
curtailment eligibility, it should be allowed to take the new transmission services. 
5. 
Determination 
 We accept PJM’s compliance filing with respect to outlining new transmission 
services in the Tariff, noting that, as discussed above in Part IV.B.3, we set aside, in part, 
the December Order and direct PJM to submit further compliance to revise its Tariff to 
extend the three new transmission services set forth in the December Order to Eligible 
Customers taking service on behalf of load with BTMG that are willing and able to limit 
their energy withdrawals from the transmission system under certain conditions.635  We 
find that PJM complies with the directive in the December Order to modify its Tariff to 
require that an Eligible Customer taking transmission service on behalf of Co-Located 
Load takes one of three transmission services:  (1) NITS or Interim NITS, (2) a new FCD 
 
632 BTMG Parties Answer at 8.  
633 Id. at 5-6 (citing December Order, 193 FERC ¶ 61,217 at P 199). 
634 Id. at 8-9. 
635 Specifically, we accept Proposed Tariff, § III.28.1 (Scope of Service) (2.0.0); 
§ III.29.1 (Conditions Precedent for Receiving Service) (4.0.0); § III.29.2 (Application 
Procedures) (4.0.0); § III.31.6 (Annual Load and Resource Information Update) (4.0.0); 
Part XI (Transmission Services Available for Eligible Customers Taking Service on 
Behalf of Co-Located Loads) (0.0.0); attach. F-3A (Service Agreement for Regional 
Network Integration Transmission Service And/or Interim Regional Network Integration 
Transmission Service (For Co-Located Load)) (0.0.0); and attach. F-4 (Service 
Agreement For Contract Demand Transmission Service (For Co-Located Load)) (0.0.0).

Docket No. EL25-49-002, et al. 
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transmission service, or (3) a new NFCD transmission service.636  We acknowledge 
PJM’s statement that it filed on compliance only a limited number of the changes directed 
in the December Order, given the number of issues set to be resolved through the paper 
hearing.   
 However, we reject the Tariff provisions proposing that Co-Located Load that is 
not served by an Eligible Customer taking transmission service on its behalf “must take 
all necessary steps to disconnect from the Transmission System.”637  We find this 
provision duplicative of PJM’s proposed changes to Part VIII, Subpart B,                        
section 403(A)(1)(r)(iv), which specify that “[t]o the extent that a Project Developer 
seeks to serve Co-Located Load using its generating facility but not identify an Eligible 
Customer, then the Project Developer must terminate its generating facility’s 
interconnection to the Transmission System and serve the Co-Located Load fully 
islanded from the Transmission System.” 
 We reject Constellation’s request to direct PJM to modify its proposed tariff 
language such that a load has an “option to take” Interim NITS instead of an “option to 
seek” Interim NITS.638  We acknowledge, as Constellation notes, that the December 
Order stated that “[t]his new interim, non-firm transmission service must allow an 
Eligible Customer that has requested NITS on behalf of a Co-Located Load to take             
non-firm transmission service that can be interrupted until the Network Upgrades 
necessary to provide NITS are complete . . . .”639  However, the December Order also 
stated that Interim NITS “would only be available to the extent PJM determines that it 
can provide some level of interim service reliably.”640  We accept PJM’s proposal and 
clarify that Interim NITS is an option but not a right, as it is available to an Eligible 
Customer taking transmission service on behalf of Co-Located Load only to the extent 
that PJM determines it can be provided reliably.  Constellation appears to request that the 
Commission require PJM to provide Interim NITS regardless of this reliability limitation, 
which would not be just and reasonable or consistent with the December Order.  We 
reject Constellation’s other requested clarifications on the required conditions to receive 
Interim NITS as not required for PJM to comply with the December Order.  Further, 
because PJM proposes to create a new Tariff section governing Interim NITS, 
 
636 December Order, 193 FERC ¶ 61,217 at P 193. 
637 PJM, Proposed Tariff, Part III (General) (4.0.0). 
638 Constellation Protest and Comments on Compliance Filing at 18-19. 
639 December Order, 193 FERC ¶ 61,217 at P 200. 
640 Id.

Docket No. EL25-49-002, et al. 
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Constellation has not shown why it is necessary to add details regarding Interim NITS to 
the existing Tariff sections addressing NITS.641 
 In its comments on the compliance filing, Crusoe makes several misplaced 
arguments about the illustrative tariff PJM submitted in the paper hearing.642  Crusoe 
argues that PJM’s illustrative tariff does not explain how the initial contract demand 
quantity is determined.  It is not clear what Crusoe means, given that the purpose of FCD 
and NFCD transmission services is to allow an Eligible Customer taking service on 
behalf of Co-Located Load to request a specific contracted amount of transmission 
service.643  The initial level of transmission service will thus be determined in the first 
instance by the requesting Eligible Customer.  PJM will evaluate those requests pursuant 
to its study process, which we address below.644  Crusoe also argues that PJM does not 
explain how PTPS interacts with Co-Location Arrangements where both the generator 
and load sit on the Interconnection Customer’s side of the Point of Change in Ownership.  
However, this arrangement appears to refer to PJM’s proposed change to the definition of 
Co-Located Load, which we reject herein.645   
 Crusoe’s request for clarification as to how phased-in load will be treated under 
FCD and NFCD transmission services is addressed below in Part VI.A.2.  Crusoe and 
DCC also make arguments about curtailment rules or procedures for Eligible Customers 
taking Interim NITS on behalf of Co-Located Load, and that issue is addressed below in 
Part VI.G.  Finally, comments urging the Commission to reject PJM’s compliance filing 
for failing to make the new transmission services available to Eligible Customers on 
behalf of non-Co-Located Loads are untimely requests for rehearing.  These commenters 
argue for a modification of the December Order, not that PJM has failed to comply with 
it.646  However, we address related arguments on rehearing of the December Order above 
in Parts IV.B.3 and IV.C.1.b.ii. 
 
641 Compliance Transmittal at 19-20. 
642 Crusoe Comments on Compliance Filing at 8.  To accompany its initial brief on 
paper hearing, PJM submitted an illustrative tariff with proposed rates, terms, and 
conditions for the three new transmission services.   
643 See December Order, 193 FERC ¶ 61,217 at PP 208, 216. 
644 See infra Part VI.A.3.  
645 See infra Part V.D.5.a. 
646 See, e.g., ISO New Eng. Inc., 132 FERC ¶ 61,098 at P 12 (“The Commission 
has held that requests to alter a compliance filing in a manner that differs from the order

Docket No. EL25-49-002, et al. 
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 Finally, we note that DCC’s concerns regarding the terms and conditions of 
Interim NITS are misplaced arguments about the illustrative tariff PJM submitted in the 
paper hearing and are discussed in Part VI.H. 
C. 
Necessary Studies 
1. 
December Order 
 The Commission directed PJM to revise the Tariff to clarify that an existing 
Interconnection Customer seeking to modify its ISA or GIA to allow its generator to 
serve Co-Located Load, including to reflect any reduction in its CIRs, must follow the 
Necessary Study process to effectuate such Co-Location Arrangement.647  In addition, the 
Commission directed PJM to add to the Tariff a description of the scope of the analysis 
that it will perform as part of the Necessary Study process when an Interconnection 
Customer seeks to use its existing generator to serve Co-Located Load, consistent with 
PJM’s discussion of how it conducts necessary studies associated with Interconnection 
Customers seeking to amend their ISAs or GIAs to use existing generators to serve              
Co-Located Load, including to reflect any reduction in CIRs.  The Commission found 
that PJM must include a description of the information that the Interconnection Customer 
must provide about the Co-Located Load for the purposes of the Necessary Study, and 
that the Necessary Study process must assess any special protection scheme that is part of 
a Co-Location Arrangement.648 
 The Commission directed PJM to revise the Tariff to indicate that the 
Interconnection Customer will be responsible for the costs of any modifications or 
Network Upgrades that are needed as a result of PJM’s study of the change to the ISA or 
GIA to allow the existing generator to serve Co-Located Load, including to reflect any 
reduction in CIRs, inclusive of all necessary Network Upgrades.649  The Commission 
found that the Tariff should make clear that an existing generator may not commence 
service to a Co-Located Load until all required Network Upgrades, special protection 
schemes, and metering are in service.650  Finally, the Commission clarified that an 
existing generator may not begin serving Co-Located Load that is not Network Load until 
 
requiring the compliance filing constitute a collateral attack on the order requiring the 
compliance filing.”).  
647 December Order, 193 FERC ¶ 61,217 at P 226. 
648 Id. P 227. 
649 Id. P 228. 
650 Id.

Docket No. EL25-49-002, et al. 
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it has delisted its CIRs for the portion of the generator to be designated to serve any                
Co-Located Load that is not receiving NITS.651 
2. 
PJM Compliance Filing 
 PJM states that it proposes changes to Parts III and VIII of the Tariff to comply 
with the Commission’s directives regarding the Necessary Study process for existing 
Interconnection Customers, including clarifying that customers must enter into a 
Necessary Study Agreement with PJM.652  PJM also proposes to require customers to 
provide PJM with all information needed to perform the Necessary Studies, which PJM 
proposes to detail in the PJM manuals.653  PJM states that a Project Developer may not 
make changes to its facilities until it has completed the Necessary Study process and the 
amended GIA is effective.  PJM proposes that the Tariff state that Necessary Studies to 
be performed include thermal, short circuit, and stability studies under various seasonal 
and load conditions, as detailed in the PJM manuals, and assess any necessary control 
technologies and protection systems required.  Lastly, PJM states that the Tariff will 
require the Project Developer to be responsible for the cost of any modifications or 
Network Upgrades necessary as a result of an Interconnection Customer’s decision to 
serve the Co-Located Load.654 
 PJM clarifies that these changes apply to all existing interconnection customers, 
regardless of whether they have effective interconnection agreements issued pursuant to 
Parts IV, VI, VII, or VIII of the Tariff.655  PJM states that, should an interconnection 
customer not have a three-party interconnection agreement involving PJM, the customer 
would need to first convert to a three-party agreement before following the Necessary 
Study process. 
3. 
Pleadings 
 A number of parties have concerns with PJM’s compliance filing.  Several parties 
protest PJM’s compliance filing and urge the Commission to require PJM to establish 
 
651 Id. P 230. 
652 Compliance Transmittal at 24-25. 
653 Id. at 25 (citing December Order, 193 FERC ¶ 61,217 at P 227). 
654 Id. at 25-28. 
655 Id. at 24-25.

Docket No. EL25-49-002, et al. 
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deadlines to complete the Necessary Study process.656  Constellation urges the 
Commission to direct PJM to detail the specific provisions in the PJM manuals to which 
the proposed Tariff language refers because it does not specify whether PJM is proposing 
to use the existing Necessary Study process or a new process, and the existing 
requirements set forth in PJM Manual 14C do not specifically reference the studies to be 
performed.  Crusoe and Constellation urge the Commission to direct PJM to revise the 
proposed Tariff’s scope of the analysis to explicitly relate to reliability impacts only, 
rather than impacts generally.657  Crusoe contends that PJM should create a clear, 
published standard for what triggers the Necessary Study process. 
 Energy Artisans argue that PJM’s proposed Necessary Study requirements will 
force industrial users to fund thermal, short circuit, and stability studies and bear the costs 
of Network Upgrades, control technologies and protection systems, and redundant 
metering equipment identified during these studies.  Energy Artisans allege that these 
requirements will force many industrial facilities to cease operations, which will lead to 
higher Network Loads and exacerbate resource adequacy issues in PJM.658   
 Vistra and Constellation request that PJM clarify how the proposed Tariff 
revisions describing the Necessary Study process would apply to interconnection 
customers who have already submitted requests and are undergoing studies.  
Constellation and Vistra assert that Co-Location Arrangements will face significant 
delays if they must reenter the Necessary Study process.659  Vistra maintains that PJM’s 
failure to include a transition mechanism is an unjustified departure from the 
Commission’s approach to interconnection reform, in which the Commission has 
regularly required transition mechanisms to avoid disruption and stranded investments.660  
Constellation proposes to clarify that Project Developers with existing requests for 
Necessary Studies for Co-Location Arrangements will be allowed to rely on the results of 
those studies to the extent relevant in light of the transmission service the Eligible 
 
656 Constellation Protest and Comments on Compliance Filing at 12, 17; DCC 
Comments on Compliance Filing at 7; Crusoe Comments on Compliance Filing at 9. 
657 Constellation Protest and Comments on Compliance Filing at 12-14; Crusoe 
Comments on Compliance Filing at 9. 
658 Energy Artisans Protest of Compliance Filing at 1-2. 
659 Constellation Protest and Comments on Compliance Filing at 15; Vistra Protest 
of Compliance Filing at 4, 6-8. 
660 Vistra Protest of Compliance Filing at 4-5.

Docket No. EL25-49-002, et al. 
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Customer plans to request on behalf of the Co-Located Load.661  Constellation and Vistra 
argue that requiring interconnection customers to restart the process would be 
inconsistent with the filed-rate doctrine and rule against retroactive ratemaking and 
would effectively penalize parties for failing to comply with rules that did not exist at the 
time they acted.662   
 Vistra contends that PJM neither justifies its proposal to require interconnection 
customers with older interconnection agreements to enter into the new pro forma GIA 
nor shows how this proposal is consistent with the Commission’s directives.  Vistra 
suggests that this proposal is unrelated to the Commission’s compliance directives and 
requests clarity about when the interconnection customer needs to enter into the new GIA 
in the Necessary Study process.  Vistra also asserts that PJM’s proposal could result in 
disputes about whether and how provisions in the updated pro forma GIA apply to older 
generators, disrupting long-standing Commission precedent.  Separately, Vistra indicates 
that, because PJM locates Necessary Study revisions in Part VIII, which applies to New 
Service Requests on or after October 1, 2021, it is unclear whether interconnection 
customers that entered the interconnection process before that date may use the 
Necessary Study process.663 
 Joint Parties argue that PJM should be required to clarify that an existing 
interconnection customer can nominate a joint withdrawal limit in the Necessary Study 
process.664  Joint Parties argue that this clarification is necessary to realize the December 
Order’s stated intent of ensuring that Co-Located Loads do not pay for services that they 
do not use and do not trigger Network Upgrades that they do not need.665  Joint Parties 
argue that PJM’s proposed Tariff revisions appear to remain silent as to how it will treat 
energy withdrawals in studying Co-Located Load interconnection requests.  Joint Parties 
state that they seek modest clarifications from PJM that, to the extent PJM performs 
interconnection study steps involving withdrawal assumptions for Co-Located Loads, an 
energy storage interconnection customer will be able to specify limits to the injection and 
 
661 Constellation Protest and Comments on Compliance Filing at 14-15. 
662 Id. at 15; Vistra Protest of Compliance Filing at 4, 6. 
663 Vistra Protest of Compliance Filing at 14-16. 
664 Joint Parties Protest of Compliance Filing at 4-6.  See also Earthjustice Reply 
Brief at 22. 
665 Joint Parties Protest of Compliance Filing at 4-5.

Docket No. EL25-49-002, et al. 
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withdrawal rights reflecting the proposed integration of the storage and Co-Located Load 
facilities.666   
 Parties argue that PJM’s proposal for delisting CIRs may be unjust, unreasonable, 
unduly discriminatory, or inconsistent with the Commission’s directives in the             
December Order.  Vistra claims that PJM’s proposal would require existing generators to 
provide PJM with the amount of reduction to CIRs to facilitate the Co-Located Load 
configuration, which Vistra argues is vague and potentially overbroad because it could be 
read to require that generators include in their CIR reduction any portion of a facility that 
will ever provide power to a Co-Located Load.  Vistra and DCC express concern that 
PJM’s proposal could require generators to delist more CIRs than necessary.667  Vistra 
further contends that allowing secondary units to provide occasional, interruptible service 
to Co-Located Load and to retain their CIRs would be consistent with the Tariff.  Vistra 
and Constellation argue that capacity resources that serve Co-Located Load on an 
interruptible basis should not be required to delist CIRs.668  Vistra presents an additional 
concern with PJM’s proposal for reducing CIRs, namely, that PJM fails to explain how it 
will assess the impact of the reduction of CIRs.669  Vistra alleges that because PJM’s 
proposal is vague on this point, PJM could, for example, improperly incorporate resource 
adequacy considerations into its Necessary Study process.  
4. 
Determination 
 We find that PJM’s proposed revisions to its Necessary Study process partially 
comply with the directives set forth in the December Order and therefore accept the 
Tariff revisions in part, reject them in part, and direct a further compliance filing as 
discussed below. 
 We accept PJM’s proposed revisions to Part VIII, Subpart A, section 401 and             
Part IX, Subpart G of the Tariff to comply with the directives in the December Order by: 
(1) adding a description of the scope of the analysis that it will perform as part of the 
Necessary Study process when an Interconnection Customer seeks to use its existing 
generator to serve Co-Located Load; (2) requiring the Interconnection Customer to be 
responsible for the costs of any modifications or Network Upgrades that are needed as a 
 
666 Id. at 5. 
667 Vistra Protest of Compliance Filing at 8-10; DCC Comments on Compliance 
Filing at 7. 
668 Vistra Protest of Compliance Filing at 11; Constellation Protest and Comments 
on Compliance Filing at 19. 
669 Vistra Protest of Compliance Filing at 12.

Docket No. EL25-49-002, et al. 
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result of PJM’s study of the change to the ISA or GIA to allow the existing generator to 
serve Co-Located Load, including to reflect any reduction in CIRs, inclusive of all 
necessary Network Upgrades; and (3) clarifying that an existing generator may not 
commence service to a Co-Located Load until all required Network Upgrades, special 
protection schemes, and metering are in service.670  We also accept PJM’s proposed 
revisions to Part IX, Subpart A, Form of Application and Studies Agreement to facilitate 
PJM’s collection of the information necessary to perform requested Necessary Studies.671  
However, with respect to Constellation’s argument that PJM’s proposed Tariff revisions 
may lack clarity, we direct PJM to specify in its compliance filing what types of 
additional detail about the studies will be available in the PJM manuals.   
 We also note in response to Constellation that, per the December Order, PJM’s 
proposal seeks to clarify the existing Necessary Study process, not create a new one.672  
While parties request that the Commission establish deadlines for the Necessary Study 
process, we note the December Order did not include any such requirement, and our 
review of these proposed Tariff revisions is limited to whether PJM complies with the 
directives in the December Order.673  In response to parties’ requests regarding the trigger 
and scope of the Necessary Study process, we note that the Commission in the December 
Order directed PJM to clarify its study procedures for an Interconnection Customer that 
will use its generator to serve Co-Located Load but did not otherwise direct changes to 
the trigger or scope of the Necessary Study process.  Per the Tariff, the scope of the 
Necessary Study is to determine whether planned modifications to an Interconnection 
Customer’s facilities “will have a permanent material impact on the Transmission System 
and to identify the additions, modifications, or replacements to the Transmission System, 
 
670 December Order, 193 FERC ¶ 61,217 at PP 227-228.  We also accept the 
conforming edit to the definition of Necessary Study in Proposed Tariff, § VII.A 300, 
Definitions N (3.0.0) and § VIII.A 400, Definitions N (4.0.0). 
671 Compliance Transmittal at 27; PJM, Proposed Tariff, pt. IX, subpt. A, (Form of 
Application and Studies Agreement) (4.0.0). 
672 See Compliance Transmittal at 25 (“The thrust of PJM’s proposed revisions 
require any Existing Interconnection Customer that seeks to serve Co-Located Load to 
follow a clarified necessary study process detailed in Part VIII of the Tariff and the 
related Form of Necessary Study Agreement set forth in Tariff, Part IX, Subpart G.”). 
673 See, e.g., PJM Interconnection LLC, 119 FERC ¶ 61,179, at P 12 (2007) (“The 
purpose of a compliance filing is to make the directed changes and the Commission’s 
focus in reviewing them is whether they comply with the Commission’s previously stated 
directives.”) (citing AES Huntington Beach, LLC, 111 FERC ¶ 61,079, at P 60 & n.25 
(2005)).

Docket No. EL25-49-002, et al. 
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if any, that are necessary, in accordance with Good Utility Practice, and/or to maintain 
compliance with Applicable Laws and Regulations or Applicable Standards, to 
accommodate the planned modifications.”674  Regarding Joint Parties’ requests regarding 
study processes for Co-Located Loads paired with electric storage resources, we note that 
the December Order did not address or otherwise direct changes as to any generator 
interconnection study procedures for such resources.  
 We reject in part PJM’s proposed revisions to Part III of its Tariff regarding the 
requirement for Interconnection Customers with effective ISAs pursuant to Part VI of the 
Tariff or effective GIAs pursuant to Part VII of the Tariff to enter into a new GIA 
pursuant to Part VIII of the Tariff and the pro forma GIA in Part IX, Subpart B.  We 
agree with Vistra that such a requirement is inconsistent with the Commission’s 
recognition in the December Order that existing Interconnection Customers that seek to 
modify their ISAs or GIAs must follow the Necessary Study process to effectuate a              
Co-Location Arrangement.675  Interconnection Customers with effective ISAs or GIAs 
must be able to modify those agreements and undergo the Necessary Study process 
without entering into new GIAs.   
 We also agree with protesters that PJM’s proposed revisions lack clarity with 
respect to how they apply to Interconnection Customers that have already executed 
Necessary Study Agreements and for which PJM has already completed Necessary 
Studies.676  The Commission found in the December Order that the Necessary Study 
process lacked sufficient clarity and directed PJM to add the scope of the analysis it 
performs as part of the Necessary Study process to its Tariff.677  However, the 
Commission did not direct changes to the scope of the study, and PJM does not otherwise 
demonstrate why Interconnection Customers seeking to serve Co-Located Load cannot 
 
674 PJM, Intra-PJM Tariffs, pt. VIII.A, § 400 (Definitions N) (2.0.0) (definition of 
Necessary Study). 
675 December Order, 193 FERC ¶ 61,217 at P 226 (“[W]e direct PJM to submit, 
within 60 days of the date of issuance of this order, a compliance filing to revise the 
Tariff to clarify that an existing Interconnection Customer seeking to modify its ISA or 
GIA to allow its generating facility to serve Co-Located Load, including to reflect any 
reduction in its CIRs, must follow the necessary study process to effectuate such          
Co-Location Arrangement.”) (emphasis added). 
676 Constellation Protest and Comments on Compliance Filing at 15; Vistra Protest 
of Compliance Filing at 4, 6. 
677 December Order, 193 FERC ¶ 61,217 at P 227.

Docket No. EL25-49-002, et al. 
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rely on the results of Necessary Studies that have already been performed if the scope of 
the study has not changed.   
 For these reasons, we direct PJM to submit a compliance filing within 60 days of 
the date of issuance of this order to remove the requirement for Interconnection 
Customers with existing ISAs pursuant to Part VI of the Tariff and GIAs pursuant to          
Part VII of the Tariff to enter into a new pro forma GIA.  We recognize that removing the 
requirement for Interconnection Customers with existing ISAs pursuant to Part VI of the 
Tariff and GIAs pursuant to Part VII of the Tariff to enter into a new pro forma GIA will 
necessitate duplicating the appropriate Necessary Study Tariff provisions (Part VIII, 
Subpart A, section 401.H.3) in those Tariff sections, and therefore we direct PJM to 
include these Tariff revisions in its compliance filing.  We find that this directive will 
ensure that Interconnection Customers with effective ISAs or GIAs will not be required 
to enter into new GIAs if they seek to modify their ISA or GIA to allow their generator to 
serve Co-Located Load.   
 We also direct PJM to explain in its compliance filing how its changes ensure the 
prohibition on Interconnection Customers serving Co-Located Loads from existing 
generators until all required Network Upgrades, necessary control technologies and/or 
protection systems, and metering identified as necessary are complete and in service, 
applies to Interconnection Customers with currently effective GIAs, ISAs, and Necessary 
Study Agreements, in addition to Interconnection Customers seeking new Necessary 
Study Agreements and GIAs. 
 In response to Constellation’s request that the Commission clarify that 
Interconnection Customers with existing requests for Necessary Studies for Co-Location 
Arrangements may rely on the results of those studies to the extent relevant in light of the 
transmission service the associated Eligible Customer plans to request on behalf of the 
Co-Located Load, we clarify that the studies applicable to a transmission service request 
for one of the new transmission services are distinct from the Necessary Study process, 
which studies the modification of a generator interconnection.  If an Eligible Customer 
seeks to take one of the new transmission services on behalf of Co-Located Load, it must 
request transmission service and follow the appropriate transmission service study 
procedures as directed in this order. 
 With respect to Energy Artisans’ argument that requiring industrial users to bear 
the costs of modifications or Network Upgrades will force industrial facilities to cease 
operations and exacerbate resource adequacy issues in PJM, we dismiss this argument as 
an untimely request for rehearing of the December Order’s finding that PJM’s existing 
retail BTMG netting rules were no longer just and reasonable.678  We reiterate that the 
 
678 Id. P 221; see supra P 232 & n.585.

Docket No. EL25-49-002, et al. 
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requirement to be responsible for costs of modifications or Network Upgrades applies 
only to Interconnection Customers that seek to modify their ISA or GIA to allow their 
generator to serve Co-Located Load, and this is a clarification of existing Tariff 
provisions in the pro forma ISA and GIA, as explained above.679  Interconnection 
Customers may choose to maintain their current ISAs or GIAs with no modifications, and 
Interconnection Customers who do not wish to bear these costs may choose not to pursue 
Co-Location Arrangements.   
 Consistent with our above discussion, we disagree with Vistra and Constellation 
that capacity resources should not have to reduce their CIRs to serve Co-Located Load.680  
We also reject without prejudice PJM’s proposed Tariff, Part IX, Subpart G, Form of 
Necessary Studies Agreement, because PJM has proposed changes to the Cost 
Responsibility section without explanation.681   
D. 
Other 
1. 
December Order 
a. 
Definition of Co-Located Load 
 In the December Order, the Commission directed PJM to adopt the definition of 
Co-Located Load specified in the order:  “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 to the 
PJM Transmission System.”682 
b. 
Generation Interconnection Procedures, pro forma GIA, 
and Common Service Provisions 
 The Commission also directed PJM to revise its Tariff, VIII, Subpart B,              
section 403 - Application Rules to add to the list of requirements for a New Service 
 
679 Tariff, Intra-PJM Tariffs, OATT, Attachment O, Appendix 2, § 3.4(b) 
Modification Costs (0.0.0); id., Part IX.B, Appendix 2, § 3.4(b) Modification Costs 
(2.0.0). 
680 See supra Part IV.C.2.a.iii. 
681 PJM, Proposed Tariff, pt. IX, subpt. G (Form of Necessary Studies Agreement) 
(3.0.0), § 15 (Cost Responsibility).  Specifically, PJM proposes to raise the initial deposit 
for the Necessary Studies from $25,000 to $50,000. 
682 December Order, 193 FERC ¶ 61,217 at P 164.

Docket No. EL25-49-002, et al. 
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Request that an Interconnection Customer who will use its generator to serve Co-Located 
Load must specify an Eligible Customer who will take transmission service on behalf of 
the Co-Located Load.683  The Commission further directed PJM to submit revisions to 
the generation interconnection procedures to specify any operational procedures or data 
exchange requirements that PJM deems necessary for Co-Location Arrangements to 
remedy the Tariff deficiencies, such as unique operational procedures and data exchange 
requirements.684  The Commission noted that these revisions would establish a 
requirement in the Tariff for the Eligible Customer to be charged for transmission and 
ancillary services that the Eligible Customer must take on behalf of the Co-Located Load.  
The Commission clarified that, should an Interconnection Customer wish to serve                  
Co-Located Load using its generator but not identify an Eligible Customer, then the 
Interconnection Customer may take steps to terminate its generator’s interconnection to 
the PJM transmission system and serve the Co-Located Load fully islanded from PJM’s 
transmission system.685 
 The Commission also directed revisions to the Tariff, Part IX, Subpart B GIA to 
specify that an Interconnection Customer that will use its generator to serve Co-Located 
Load must specify an Eligible Customer that will take transmission service on behalf of 
the Co-Located Load.686  The Commission directed PJM to add a new provision to Part I, 
Common Service Provisions, of the Tariff that requires Interconnection Customers with 
ISAs or GIAs executed, or requested to be filed unexecuted, prior to the effective date of 
the revised generation interconnection procedures and pro forma GIA directed in this 
order that wish to add Co-Located Load or are currently serving Co-Located Load to 
publicly notify PJM of that addition and identify the Eligible Customer that will take 
transmission service on behalf of that Co-Located Load.   
2. 
PJM Compliance Filing 
a. 
Definition of Co-Located Load 
 On April 16, 2026, the Commission issued an order rejecting the portion of PJM’s 
first compliance filing proposing to define Co-Located Load in a manner that deviated 
 
683 Id. P 188.  
684 Id. P 188 & n.405. 
685 Id. P 189. 
686 Id. P 190.

Docket No. EL25-49-002, et al. 
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from the December Order, without sufficient explanation, by replacing the term “Point of 
Interconnection” with “Point of Change in Ownership.”687 
 In the instant filing, PJM states that it proposes modifying the definition of                  
Co-Located Load directed by the Commission in the same manner as proposed in PJM’s 
first compliance filing.688  PJM states that changing “Point of Interconnection” to “Point 
of Change in Ownership” is consistent with or superior to the December Order’s directive 
because it provides additional clarity to interconnection parties, is easier to administer, 
and reduces litigation potential.689  PJM further explains “[w]hile Point of Change in 
Ownership describes where a developer’s portion of the Interconnection Facilities 
connect to the Transmission Owner’s portion of the Interconnection Facilities, Point of 
Interconnection is a technical and physical term about ‘where’ those Interconnection 
Facilities connect to the PJM Transmission System.”690  PJM states that the Commission 
has broad authority to establish the replacement rate under FPA section 206 and that “one 
stakeholder’s conditional protest in Docket No. ER26-1088 offers another alternative for 
the Commission to consider in reliance on this Commission authority.”691  PJM explains 
that “Point of Change in Ownership” will reduce litigation because parties “know what 
interconnection facilities they own and can plan the connection of Co-Located Load to 
such facilities accordingly” but that the protest in Docket No. ER26-1088 “does not 
appear inconsistent with recognizing the principle that Co-Located Loads should only 
interconnect to a Project Developer’s portion of the Interconnection Facilities.”692  PJM 
notes that under the GIP, the Project Developer’s Interconnection Facilities are the 
Interconnection Facilities between a Generating Facility and the Point of Change in 
Ownership, and include the facilities and equipment and any modification to those 
facilities and equipment that are necessary to physically and electrically interconnect the 
Generating Facility.693 
 
687 PJM Interconnection, L.L.C., 195 FERC ¶ 61,030 (2026). 
688 Compliance Transmittal at 31 (citing PJM, Transmittal, Docket                                  
No. ER26-1088-000, at 3 n.14 (filed Jan. 20, 2026)). 
689 Id. at 31-32. 
690 Id. at 32. 
691 Id. at 33. 
692 Id. at 33-34. 
693 Id. at 34-35.

Docket No. EL25-49-002, et al. 
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b. 
Generation Interconnection Procedures, pro forma GIA, 
and Common Service Provisions 
 PJM states that it proposes the prescriptive clarifications directed in the December 
Order.  PJM explains that the proposed Tariff revisions comply by:  (1) adding to the list 
of requirements for a New Service Request that an Interconnection Customer who will 
use its generating facility to serve Co-Located Load must specify an Eligible Customer 
who will take transmission service on behalf of the Co-Located Load,694 (2) explaining 
that if an Interconnection Customer wants to serve Co-Located Load but not identify an 
Eligible Customer, then it may take steps to terminate its generating facility’s 
interconnection and serve the Co-Located Load fully islanded from PJM’s transmission 
system,695 (3) explaining that these requirements apply to all Interconnection Customers 
requesting to interconnect generating facilities to serve Co-Located Load,696 (4) creating 
a new schedule in the pro forma GIA in the form of a placeholder to specify operational 
procedures or data exchange requirements as may be required,697 and (5) revising the             
pro forma GIA to reflect the requirement to specify an Eligible Customer that will take 
transmission service on behalf of the Co-Located Load.698  
 In addition, PJM states that it complies with the requirement to add a transition 
mechanism for existing customers that wish to add Co-Located Load by including the 
transition mechanism in (1) the definition of Co-Located Generating Facility in Part I of 
the Tariff, (2) Part III (NITS), and (3) the definition of Co-Located Generating Facility699 
 
694 Id. at 28 (citing PJM, Proposed Tariff, pt. VIII, subpt. B, § 403 (4.0.0),             
§ 403(1)(r)). 
695 Id. at 29 (citing PJM, Proposed Tariff, pt. VIII, subpt. B, § 403 (4.0.0),             
§ 403 (1)(r); Proposed Tariff, Part III (NITS) (4.0.0)). 
696 Id. (citing PJM, Proposed Tariff, pt. VIII, subpt. B, § 403 (4.0.0), § 403(1)(r); 
Proposed Tariff, Part III (NITS) (4.0.0)). 
697 Id. (citing PJM, Proposed Tariff, pt. IX.B (GIA), (0.0.0), Schedule O).  
698 Id. (citing PJM, Proposed Tariff, pt. IX.B (GIA), (0.0.0), Schedule O). 
699 PJM proposes the following definition of a Co-Located Generating Facility:  
“an existing or planned Generating Facility that is physically connected to a Co-Located 
Load.  Any Generation Project Developer with an effective Service Agreement that plans 
to use a Generating Facility to serve Co-Located Load must provide PJM and the 
Transmission Owner with advance written notice to begin the Necessary Studies process 
provided in Tariff, § VIII.A 401(H)(3)(b).  If such a Generation Project Developer has an 
effective Interconnection Service Agreement pursuant to Tariff, Part VI or a Generation 
Interconnection Agreement pursuant to Tariff, Part VII, such agreement must be

Docket No. EL25-49-002, et al. 
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in Part VIII, Subpart A, section 400 of the Tariff.  PJM asserts that these proposed 
revisions to the Tariff are “superior to or consistent with the Commission’s directive 
because it promotes tariff readability and usability.”700   
c. 
Definition of Non-Retail BTMG 
 PJM states that it is also seeking to avoid any inadvertent changes to the 
substantive rules pertaining to Non-Retail BTMG.701  For this reason, PJM proposes to 
add clarifying language in Tariff, Part III, section 34.3 providing that “The daily load of a 
Network Customer does not include load served by operating Non-Retail Behind The 
Meter Generation.”702  PJM states that this insertion preserves the status quo on this issue 
for Non-Retail BTMG.   
3. 
Pleadings 
a. 
Definition of Co-Located Load 
 Constellation urges the Commission to reject PJM’s proposal to replace the term  
“Point of Interconnection” in the definition of Co-Located Load with the “Point of 
Change in Ownership.”703  Constellation argues that changing the specific definition of 
Co-Located Load already approved by the Commission in the December Order is outside 
the scope of compliance.  Constellation asserts that Point of Change in Ownership is not a 
defined physical point and may lead to delays or discrimination against certain                       
Co-Location Arrangements.  Constellation states that, alternatively, if the Commission 
accepts PJM’s proposed definition of Co-Located Load, it should (1) direct PJM to revise 
its Tariff to provide that PJM will determine the Point of Change in Ownership if parties 
cannot agree; (2) establish deadlines for parties to mutually agree to, or for PJM to 
determine, the location for Point of Change in Ownership; (3) ensure that the location 
selected for the Point of Change in Ownership does not eliminate the load from being   
Co-Located Load unless the Project Developer and Co-Located Load desire it; and               
 
superseded by a Generation Interconnection Agreement pursuant to Tariff, Part VIII and 
the pro forma GIA in Part IX, Subpart B.”  PJM, Proposed Tariff, § VII.A 300 
(Definitions C) (4.0.0); § VIII.A 400, Definitions C (4.0.0). 
700 Compliance Transmittal at 29-30. 
701 Id. at 16. 
702 Id. 
703 Constellation Protest and Comments on Compliance Filing at 2.

Docket No. EL25-49-002, et al. 
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(4) not tolerate any discrimination or delay and use its enforcement authority or other 
mechanisms to ensure non-discriminatory open access.704 
 Constellation asserts that recent experience has borne out the concern raised in its 
initial protest that PJM’s deviation from the Commission’s definition of Co-Located 
Load will allow transmission owners to effectively block Co-Location Arrangements.705  
Constellation states that a transmission owner recently notified Constellation that it 
would not study Constellation’s proposed design for a Co-Location Arrangement unless 
Constellation agreed to transfer ownership of certain facilities to the transmission owner, 
which would mean that the load would no longer be on the generator’s side of the Point 
of Change in Ownership.706  Constellation argues that, by conditioning the load’s 
interconnection on the transmission owner’s ownership of those facilities, the 
transmission owner would prohibit Constellation’s ability to host Co-Located Load at the 
site and limit the ability of the Co-Located Load to access the transmission services 
adopted in the December Order.  
 Vistra requests that the Commission reject PJM’s use of “Point of Change in 
Ownership” in its proposed definition of Co-Located Load.707  Vistra argues that PJM’s 
proposed revision to the definition of Co-Located Load creates uncertainty and an 
opportunity for transmission owners to unduly discriminate against certain customers.  
Vistra requests that, if the Commission accepts PJM’s proposed definition, then the 
Commission should direct further compliance to prevent undue discrimination.708  
 Energy Artisans oppose PJM’s definition of Co-Located Load and its use of Point 
of Change in Ownership rather than Point of Interconnection as arbitrary and a pretext for 
cost shifting.709  Energy Artisans allege that the definition “is strategically designed to 
shrink the legal definition of the facility boundary, thereby capturing more load for               
grid-service billing and excluding it from the BTMG actual use category.”710  
 
704 Id. at 3-5, 7-8. 
705 Constellation Supplemental Protest of Compliance Filing at 2. 
706 Id. at 3. 
707 Vistra Protest of Compliance Filing at 17. 
708 Id. at 18-19. 
709 Energy Artisans Protest of Compliance Filing at 2. 
710 Id.

Docket No. EL25-49-002, et al. 
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b. 
Generation Interconnection Procedures, pro forma GIA, 
and Common Service Provisions 
 Invenergy argues that PJM proposes to continue operating a bifurcated study 
process in which there is no requirement for generator interconnection and transmission 
service request studies to be conducted in concert, on similar time frames, or using 
similar study assumptions.  As a result, Invenergy contends that distinct studies may 
identify duplicative or unnecessary Network Upgrades.  Invenergy requests that the 
Commission and PJM clarify how the definition of Eligible Customer applies to                   
co-located generators and co-located loads.711   
 Constellation urges the Commission to direct PJM to revise its proposed definition 
of Co-Located Generating Facility to clarify that the definition only applies to the portion 
of the facility serving and physically connected to the Co-Located Load.712 
c. 
Definition of Non-Retail BTMG 
 AMP argues that PJM’s proposed revision to the definition of Non-Retail BTMG 
could be construed as preventing generating units that are merely eligible for application 
of the Non-Retail BTMG rules from participating in Co-Located Load configurations.  
Specifically, AMP asserts that the use of the word “qualifies” in the proposed definition 
of Non-Retail BTMG may exclude generation from participating in Co-Located Load 
configurations even if the generator is not engaged in netting.  AMP argues that this 
apparently unintentional exclusion would restrict Co-Located Load from accessing 
service from a broad set of PJM generators.  AMP avers that revising the Non-Retail 
BTMG definition is unnecessary and outside the scope of the Commission’s compliance 
directives.  AMP urges the Commission to reject the proposed definition of Non-Retail 
BTMG or, alternatively, revise the definition to specify that the exclusion applies to 
generators both qualifying as Non-Retail BTMG and being used for netting under the 
Tariff.713 
d. 
Timing with Planned Reliability Backstop Auction 
 The Maryland OPC urges the Commission to defer action on PJM’s proposed 
revisions until PJM announces details regarding its planned reliability backstop auction, 
including specifics on how the reliability backstop auction will interact with Co-Location 
Arrangements to ensure that new Co-Located Loads pay the costs of any new capacity.  
 
711 Invenergy Comments on Compliance Filing at 3, 6. 
712 Constellation Protest and Comments on Compliance Filing at 17.  
713 AMP Limited Protest of Compliance Filing at 3, 5-8.

Docket No. EL25-49-002, et al. 
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The Maryland OPC argues that the proposed Tariff revisions fail to explain how 
increased capacity costs of allowing existing generators to serve Co-Located Load, as 
opposed to new generators, will be paid by Co-Located Load and not by existing 
ratepayers.714   
4. 
Answers 
 In response to Invenergy, Indicated TOs argue that the Commission should not 
mandate a combined interconnection and transmission study process for Co-Located 
Loads and Co-Located Generators.  Indicated TOs contend this goes beyond the issues 
the Commission set for hearing, as well as the compliance directed, in the December 
Order.  Indicated TOs argue that PJM’s proposed coordinated study approach is just and 
reasonable.715 
 Exelon argues that Constellation’s motion for supplemental protest should be 
denied because it suggests that Constellation’s experience with one transmission owner 
implies a universal policy.  Exelon states that it is not attempting to prevent large loads, 
co-located or otherwise, and their load serving entities from receiving transmission 
service in Exelon’s territories.  Exelon also argues that whether a transmission owner 
owns certain equipment does not necessarily inform where the Project Developer’s 
interconnection facilities connect to the transmission owner’s interconnection facilities.716 
5. 
Determination 
a. 
Definition of Co-Located Load 
 As in the Commission’s order addressing PJM’s first compliance filing with the 
December Order, we reject PJM’s proposed change to the definition of Co-Located 
Load.717  We note that no party, including PJM, sought rehearing or clarification of this 
directive, let alone the definition, in response to the December Order.  Even here, PJM 
does not allege that the definition of Co-Located Load set out in the December Order is 
unjust and unreasonable.  Rather, PJM proposes to deviate from this definition by 
replacing the term “Point of Interconnection” with “Point of Change in Ownership” 
 
714 Maryland OPC Protest of Compliance Filing at 10-11. 
715 Indicated TOs April 24 Answer at 4-5. 
716 Exelon Answer at 1, 5-6. 
717 PJM Interconnection, L.L.C., 195 FERC ¶ 61,030; PJM, Proposed Tariff,                         
§ I.1 Definitions C-D (Co-Located Load) (46.0.0); § VII.A 300, Definitions C                      
(Co-Located Load) (4.0.0); § VIII.A 400, Definitions C (Co-Located Load) (4.0.0).

Docket No. EL25-49-002, et al. 
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without sufficient explanation as to how this proposed deviation complies with the 
Commission’s directive in the December Order.718   
 Accordingly, we direct PJM to file, within 60 days of the date of issuance of this 
order, a compliance filing that revises the Tariff’s definition of Co-Located Load to use 
“Point of Interconnection” instead of “Point of Change in Ownership,” consistent with 
the Commission’s directive in the December Order.   
b. 
Generation Interconnection Procedures, pro forma GIA, 
and Common Service Provisions 
 We accept the following of PJM’s proposed revisions to establish rules for 
Interconnection Customers serving Co-Located Load as complying with the December 
Order:  (1) adding to the list of requirements for a New Service Request that an 
Interconnection Customer who will use its generator to serve Co-Located Load must 
specify an Eligible Customer who will take transmission service on behalf of the               
Co-Located Load;719 (2) establishing a new schedule in the pro forma GIA that serves as 
a placeholder for specifying any operational procedures or data exchange requirements 
that PJM deems necessary for Co-Location Arrangements;720 (3) applying these 
requirements to all Interconnection Customers requesting to interconnect their generators 
to the transmission system and seeking to use those facilities to serve Co-Located 
Load;721 (4) clarifying that to the extent that an Interconnection Customer wishes to serve 
Co-Located Load using its generator but not identify an Eligible Customer, then the 
Interconnection Customer may take steps to terminate its generator’s interconnection to 
the PJM transmission system and serve the Co-Located Load fully islanded from PJM’s 
 
718 See, e.g., PJM Interconnection LLC, 119 FERC ¶ 61,179 at P 12 (“The purpose 
of a compliance filing is to make the directed changes and the Commission’s focus in 
reviewing them is whether they comply with the Commission’s previously stated 
directives.”) (citing AES Huntington Beach, LLC, 111 FERC ¶ 61,079 at P 60 & n.25). 
719 See December Order, 193 FERC ¶ 61,217 at P 188; PJM, Proposed Tariff,                 
pt. VIII, subpt. B, 403 (4.0.0), § 403(1)(r).   
720 See December Order, 193 FERC ¶ 61,217 at P 188; PJM, Proposed Tariff,              
Part IX.B, Schedule O (0.0.0).  PJM explains that it proposes to add a new schedule in the 
pro forma GIA in the form of a placeholder for such information as the case may require.  
Compliance Transmittal at 29.  We also accept conforming changes to Tariff, Part IX.B, 
GIA Appendices and Schedules. 
721 See December Order, 193 FERC ¶ 61,217 at P 189; PJM, Proposed Tariff,                
pt. VIII, subpt.B, 403 (4.0.0), § 403(1)(r).

Docket No. EL25-49-002, et al. 
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transmission system;722 and (5) revising the pro forma GIA to specify that an 
Interconnection Customer that will use its generator to serve Co-Located Load must 
specify an Eligible Customer that will take transmission service on behalf of the             
Co-Located Load.723 
 However, we reject PJM’s proposed revisions to comply with the Commission’s 
directive in the December Order to require Interconnection Customers with ISAs or GIAs 
executed (or requested to be filed unexecuted) prior to the effective date of the revised 
generation interconnection procedures and pro forma GIA directed in that order that wish 
to add Co-Located Load or are currently serving Co-Located Load to publicly notify PJM 
of that addition and identify the Eligible Customer that will take transmission service on 
behalf of that Co-Located Load.724  Consistent with our discussion above in Part V.C.4, 
we agree with protesters that PJM’s proposed revisions here go beyond the directives in 
the December Order by requiring Interconnection Customers with existing ISAs or GIAs 
that are currently serving Co-Located Load or wish to add Co-Located Load (and have 
executed Necessary Study Agreements) to initiate a new Necessary Study process and 
enter into a new GIA—which the December Order did not require.725  Therefore, while 
we appreciate PJM’s intent to promote Tariff readability and usability, we find that 
PJM’s language in the definition of Co-Located Generating Facility does not comply with 
the December Order, consistent with our findings regarding the same language in Part III 
of the Tariff.726  We further find that PJM has failed to include a general provision in the 
Tariff to comply with the Commission’s directive in the December Order to require 
Interconnection Customers with ISAs or GIAs executed (or requested to be filed 
unexecuted) prior to the effective date of the revised generation interconnection 
procedures and pro forma GIA directed in that order that wish to add Co-Located Load or 
are currently serving Co-Located Load to publicly notify PJM of that addition and 
 
722 See December Order, 193 FERC ¶ 61,217 at P 189; PJM, Proposed Tariff,        
pt. VIII, subpt. B, § 403 (4.0.0), § 403(1)(r).   
723 See December Order, 193 FERC ¶ 61,217 at P 190; PJM, Proposed Tariff,           
pt. IX (GIA), subpt. B, Schedule O (0.0.0). 
724 See December Order, 193 FERC ¶ 61,217 at P 191; PJM, Part III (NITS) 
(4.0.0); § VII.A 300, Definitions C (Co-Located Generating Facility) (4.0.0); § VIII.A 
400, Definitions C (Co-Located Generating Facility) (4.0.0).  We note that the definition 
of Co-Located Generating Facility in § I.1 Definitions C-D does not include the language 
that we are rejecting here. 
725 See, e.g., Vistra Protest of Compliance Filing at 4, 14.  
726 See supra Part V.C.4.

Docket No. EL25-49-002, et al. 
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identify the Eligible Customer that will take transmission service on behalf of that              
Co-Located Load, separate from the Necessary Study process. 
 Therefore, we direct PJM to submit a compliance filing within 60 days of the date 
of issuance of this order to:  (1) revise the definition of Co-Located Generating Facility to 
remove the following requirement:  “If such a Generation Project Developer has an 
effective Interconnection Service Agreement pursuant to Tariff, Part VI or a Generation 
Interconnection Agreement pursuant to Tariff, Part VII, such agreement must be 
superseded by a Generation Interconnection Agreement pursuant to Tariff, Part VIII and 
the pro forma GIA in Part IX, Subpart B,” and (2) add to Part III a requirement that 
Interconnection Customers with ISAs or GIAs executed (or requested to be filed 
unexecuted) prior to the effective date of the revised generation interconnection 
procedures and pro forma GIA directed in December Order that wish to add Co-Located 
Load or are currently serving Co-Located Load publicly notify PJM of that addition and 
identify the Eligible Customer that will take transmission service on behalf of that              
Co-Located Load. 
 We disagree with Constellation that PJM’s proposed definition of Co-Located 
Generating Facility should only apply to the portion of the facility that is serving                  
Co-Located Load.  Constellation claims that the definition does not recognize that the 
entire facility may not serve the Co-Located Load, but Constellation has not identified 
any substantive concern with that outcome.  We find the proposed definition is broad 
enough to capture both scenarios.  Further, PJM’s proposed Tariff language recognizes 
this possibility elsewhere, such as, for example, Part IX, Subpart A Form of Application 
and Studies Agreement, section 2, which leaves a space for the Interconnection Customer 
to list both the Co-Located Load and any requested CIRs. 
 With respect to Invenergy’s request that PJM perform generator interconnection 
and transmission service request studies in concert, we note that the December Order did 
not direct PJM to create such a new study process.  Thus, we find that Invenergy’s 
request is beyond the scope of this proceeding. 
c. 
Definition of Non-Retail BTMG 
 We agree with AMP that PJM’s proposed revisions to the definition of Non-Retail 
BTMG may inadvertently prevent generators that could merely qualify as Non-Retail 
BTMG from participating in Co-Location Arrangements, regardless of whether the 
generator is being used to net.  As PJM recognizes, the December Order “did not direct 
any changes to Non-Retail BTMG rules.”727  PJM did not provide any justification for its 
proposed changes to the definition of Non-Retail BTMG, nor did the Commission direct 
 
727 Compliance Transmittal at 7.

Docket No. EL25-49-002, et al. 
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any changes to PJM’s rules for Non-Retail BTMG in the December Order.728  Therefore, 
we reject PJM’s proposed revisions to the definition of Non-Retail BTMG and direct 
PJM to file, within 60 days of the date of issuance of this order, a compliance filing to 
revise its Tariff to remove the proposed changes, consistent with the December Order’s 
determination.729 
d. 
Timing with Planned Reliability Backstop Auction 
 As discussed below, we decline Maryland OPC’s request that the Commission 
defer action.730  We find that Maryland OPC’s concerns about PJM’s capacity market are 
beyond the scope of this compliance proceeding, which pertains solely to PJM’s 
compliance with the Commission’s directives in the December Order.   
E. 
Effective Date 
1. 
PJM Compliance Filing 
 PJM requests a placeholder effective date of 12/31/9998 because PJM cannot 
implement the Tariff changes until the Commission sets the terms and conditions of the 
new transmission services in the paper hearing.731  PJM states that it will submit a                         
clean-up filing proposing an effective date after the Commission issues an order on the 
paper hearing.732 
2. 
Effective Date Pleadings 
 Though Vistra says it will address PJM’s proposed June 1, 2029 effective date in 
its paper hearing brief, Vistra argues in its protest of the compliance filing that PJM has 
not shown that its proposed effective date is just and reasonable.733  Vistra alleges that the 
three-year forward capacity market schedule cannot justify a delay in the provision of 
non-capacity-backed transmission service.  Vistra also contends that the forecasts for the 
 
728 December Order, 193 FERC ¶ 61,217 at P 222 (“We clarify we do not direct 
PJM to change its rules for non-retail BTMG.”). 
729 PJM, Proposed Tariff, § I.1 Definitions L-M-N (Non-Retail Behind The Meter 
Generation) (52.0.0). 
730 See supra Part VI.K.2. 
731 Compliance Transmittal at 35. 
732 Id. at 35-36. 
733 Vistra Protest of Compliance Filing at 7.

Docket No. EL25-49-002, et al. 
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2027/2028 and 2028/2029 Base Residual Auctions (BRA) include the new large loads 
likely to come online in that timeframe, undermining PJM’s position that the capacity 
market schedule should delay the provision of firm transmission service.  Vistra also 
argues that PJM has not explained why it will take until 2029 to update its software to 
accommodate the new curtailment logic. 
 DCC argues that PJM’s effective date should be earlier than June 1, 2029.734  DCC 
argues that PJM should work with stakeholders to implement workable solutions in a 
timely manner that ensures the transmission services can meet the immediate need within 
the PJM region. 
3. 
Determination 
 As discussed below in Part VI.J, we direct PJM to submit, within 60 days of the 
date of issuance of this order, a further compliance filing providing additional 
information on the effective date.  
VI. 
Paper Hearing 
 The Commission directed PJM to modify its Tariff to require that the Eligible 
Customer taking transmission service on behalf of a Co-Located Load takes one of three 
transmission services:  (1) NITS or Interim NITS, (2) FCD transmission service, or                 
(3) NFCD transmission service.735  With respect to the new transmission services that the 
Commission required, the Commission established paper hearing procedures to determine 
the appropriate rates, terms, and conditions of those transmission services.736  PJM did 
not file tariff revisions in eTariff, but rather, chose to submit illustrative tariff revisions 
that mirror the arguments PJM filed in its initial brief as part of that brief.  The illustrative 
tariff is not filed as a rate with the Commission, but we consider it as part of the record in 
response to the paper hearing as we establish the replacement rate set forth below.  As 
discussed in detail below, as the replacement rate, we direct PJM to submit within                       
60 days of the date of issuance of this order, a compliance filing revising its Tariff to 
include rates, terms, and conditions for the new transmission services consistent with our 
findings in the below sections.  
 
734 DCC Comments on Compliance Filing at 7. 
735 December Order, 193 FERC ¶ 61,217 at P 193. 
736 Id. PP 194, 203, 207, 219.

Docket No. EL25-49-002, et al. 
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A. 
Rates, Terms, and Conditions for Firm and Non-Firm Contract 
Demand Transmission Service 
1. 
December Order 
 With respect to FCD transmission service and NFCD transmission service, the 
Commission found in the December Order that these transmission services should be 
permanent transmission services available to Eligible Customers taking transmission 
service on behalf of Co-Located Load.737  The Commission further stated that for the 
Eligible Customer taking transmission service on behalf of a Co-Located Load to be 
eligible for these new transmission services, the Co-Located Load must be able and 
willing to prevent or limit its energy withdrawals and must be separately metered from 
the associated generator.738  The Commission also stated that Eligible Customers taking 
transmission service on behalf of Co-Located Loads may take a combination of FCD 
transmission service and NFCD transmission service, but that Eligible Customers taking 
transmission service on behalf of Co-Located Loads that will not withdraw energy from 
the transmission system must take NFCD transmission service at 0 MW.739  The 
Commission also found that Eligible Customers taking either transmission service on 
behalf of Co-Located Loads would be charged for regulation and black start services 
based on gross demand, rather than the reserved amount of transmission service.740 
 The Commission found that FCD transmission service should have the same 
reservation and curtailment priority as existing firm transmission services at the level of 
the contract demand and be charged for transmission, ancillary services, and capacity 
based on the contract demand, with the exception of regulation and black start services.741  
With respect to NFCD transmission service, the Commission found that the service 
should be available during normal operations and curtailed during emergency operations, 
similar to existing non-firm transmission service options.742   
 
737 Id. P 206. 
738 Id.  
739 Id.  
740 Id. PP 209, 216. 
741 Id. PP 208-209. 
742 Id. P 215.

Docket No. EL25-49-002, et al. 
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2. 
Nature of FCD and NFCD Transmission Services 
a. 
Initial Briefs 
 PJM proposes to define FCD transmission service as the transfer of capacity and 
energy for an Eligible Customer on behalf of a designated Co-Located Load, up to a 
defined, pre-determined MW level of transmission service as requested by the Eligible 
Customer and confirmed by PJM, using capacity and energy procured by PJM.743  PJM 
proposes to define NFCD transmission service as a service offering the transmission of 
energy for an Eligible Customer on behalf of a designated Co-Located Load, on an                 
as-available basis, up to a defined, pre-determined MW level of transmission service as 
requested by the Eligible Customer and confirmed by PJM, using energy procured by 
PJM.744   
 PJM states that it has conceptualized the FCD and NFCD transmission services 
based on two key principles:  (1) the services are designed to serve loads willing and able 
to control their withdrawals from the transmission system, and (2) the services are 
designed to allow PJM to maintain system reliability.745  PJM explains that, to maintain 
reliability, any portion of the gross demand of the Co-Located Load not served by the      
Co-Located Generator must be covered by FCD transmission service.  PJM also states 
that, to ensure reliability, PJM’s studies of the transmission service requests for the                      
Co-Located Load must capture the effects of any unscheduled energy withdrawals and 
validate that such events would not jeopardize system reliability.746  PJM then asserts 
that, if the Co-Located Load’s gross demand is not covered by FCD transmission service, 
then the Eligible Customer must cover the remaining gross demand by applying for 
NFCD transmission service.  PJM further states that an Eligible Customer taking service 
on behalf of a Co-Located Load must request NFCD transmission service equal to the 
MW level of the Co-Located Generating Facility dedicated to serving the Co-Located 
Load, so that the customer is eligible to obtain NFCD transmission service if the                   
Co-Located Generating Facility is on outage.747  PJM states that it anticipates that, in 
practice, requests for NFCD transmission service will be at the MW level that the                   
Co-Located Generating Facility has dedicated to serving the Co-Located Load.  PJM 
states that the Eligible Customer may then, on any given day, reserve NFCD transmission 
 
743 PJM Initial Brief at 13. 
744 Id. at 30. 
745 Id. at 6. 
746 Id. at 6-7. 
747 Id. at 9, 16.

Docket No. EL25-49-002, et al. 
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service up to the amount specified in the Service Agreement, but only when PJM has 
determined there is available transmission capacity.  If there is not sufficient capacity to 
grant the request for NFCD transmission service, PJM explains the Eligible Customer 
may apply for FCD transmission service for the necessary amount, or NITS to serve the 
entire Co-Located Load.748  PJM maintains that its approach provides flexibility, 
allowing Eligible Customers to mix and match FCD and NFCD transmission services, so 
long as the combination of the two services covers the entire gross demand of the                  
Co-Located Load.749 
 PJM argues that, to prevent FCD and NFCD transmission services from adversely 
impacting system reliability, it is crucial for the Eligible Customer to show and prove its 
ability to limit withdrawals from the system.  PJM maintains that, for FCD transmission 
service to properly function, it is essential that any NFCD transmission service for the 
same Co-Located Load has in place necessary control technologies and/or protective 
systems approved by PJM and that can effectively limit withdrawals from the 
transmission system that serve the Co-Located Load.750  PJM proposes to require Eligible 
Customers taking NFCD transmission service to work with PJM and the affected 
Transmission Owners to establish necessary control technologies and protection systems 
for each Service Agreement to ensure reliability.751 
 PJM explains that FCD transmission service will have priority over NFCD 
transmission service and equal priority, at the level of the contract demand, with other 
firm transmission services, including NITS.  PJM proposes that NFCD transmission 
service be curtailed before FCD transmission service and NITS, as discussed further 
below, and proposes to curtail NFCD transmission service prior to dispatching Pre-
Emergency Load Response Program resources or in response to a transfer capability 
shortage.752   
 
748 Id. at 32-33. 
749 Id. at 11. 
750 Id. at 15, 31. 
751 Id. at 34-35. 
752 Id. at 15, 34.

Docket No. EL25-49-002, et al. 
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b. 
Response Briefs 
 Indicated TOs support PJM’s proposal to require Eligible Customers taking 
service on behalf of Co-Located Load to take a combination of FCD and NFCD 
transmission services equivalent to the entire gross demand of the Co-Located Load.753   
 However, a number of parties protest PJM’s proposed requirement that NFCD 
transmission service be available only when the Co-Located Generating Facility is on an 
outage.754  Parties argue that the December Order does not impose such a limit on this 
transmission service and that PJM provides no justification for the change.755  AEU/SEIA 
contend that the December Order required that NFCD transmission service be available 
“as needed during normal, non-emergency system operating conditions,” and that, while 
it cited the use of NFCD transmission service during an outage as one potential use case, 
the December Order did not impose the limitation described in PJM’s proposed Tariff 
revisions.756  AEU/SEIA claim that the practical consequences of this limitation are 
significant, particularly for Co-Located Loads served by resources with variable or 
intermittent output profiles, which may require supplemental grid withdrawals during any 
period in which the Co-Located Generator’s output is constrained, reduced, or otherwise 
insufficient to meet the full gross demand of the Co-Located Load.  AEU/SEIA argue 
that this gap in the availability of NFCD transmission service will force many 
transmission customers to take NITS.   
 AEU/SEIA contend that PJM attempts to justify this restriction on operational and 
planning complexity grounds, but argues that the Commission considered these 
objections before the December Order and nonetheless required PJM to provide NFCD 
transmission service.757  AEU/SEIA also contend that this restriction cannot be justified 
on resource adequacy or reliability grounds, because NFCD transmission service is 
 
753 Indicated TOs Response Brief at 4; Industrials/Amtrak Response Brief at 24. 
754 Joint Co-Location Developers Response Brief at 6-13; AEU/SEIA Response 
Brief at 5; Vistra Response Brief at 25; DCC Response Brief at 4; Constellation Response 
Brief at 10. 
755 Vistra Response Brief at 26; AEU/SEIA Response Brief at 5-6; Joint                     
Co-Location Developers Response Brief at 7; DCC Response Brief at 5; Constellation 
Response Brief at 10. 
756 AEU/SEIA Response Brief at 6-8 (citing December Order, 193 FERC ¶ 61,217 
at PP 214-215); Joint Co-Location Developers Response Brief at 6-7. 
757 AEU/SEIA Response Brief at 8-10 (citing PJM March 24, 2025 Response                  
at 13-15).

Docket No. EL25-49-002, et al. 
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designed to be curtailed before firm transmission services and is available only when 
transmission capacity exists.  AEU/SEIA therefore request that the Commission direct 
PJM to revise and file Tariff revisions that remove the outage-only limitation and allow 
for the use of NFCD transmission service on an as-available basis during normal,                  
non-emergency system operating conditions and subject to available transmission 
capacity and appropriate curtailment priority.  
 Joint Co-Location Developers argue that PJM’s proposal undermines economic 
efficiency, restricts competition, may threaten reliability for other customers, and is 
unclear as applied to partial outages.758  Joint Co-Location Developers maintain that 
PJM’s proposal is inconsistent with its other transmission service offerings, such as 
PTPS, which is not designed based on whether generation is on an outage.  Joint                    
Co-Location Developers add that PJM’s Interim NITS proposal shows PJM’s ability to 
offer non-firm service during normal conditions without the need to request a reservation.  
 DCC argues that PJM’s proposal effectively confines NFCD transmission service 
to a narrow, outage-only function and prohibits its use to address foreseeable and 
manageable transmission constraints.  DCC argues that PJM has not demonstrated why 
NFCD transmission service that is (a) requested in advance, (b) subject to PJM approval, 
(c) fully curtailable, and (d) supported by required protection and control mechanisms, 
may appropriately be used to address generator outages but may not be used to address 
temporary transmission constraints.759   
 Constellation also criticizes PJM’s view that this proposal is needed to avoid 
overuse and responds that the Commission indicated that penalty charges should solve 
that concern.760 
 Constellation also protests PJM’s proposal to require FCD transmission service for 
any portion of the Co-Located Load not served by the Co-Located Generating Facility.  
Constellation argues that the Commission established no such requirement, nor did the 
Commission require that Eligible Customers take FCD transmission service along with 
NFCD transmission service.761   
 
758 Joint Co-Location Developers Response Brief at 8-11. 
759 DCC Response Brief at 5.  
760 Constellation Response Brief at 11-12. 
761 Id. at 10, 12.

Docket No. EL25-49-002, et al. 
- 161 - 
 DCC argues that PJM’s proposal does not provide a workable pathway for phased 
development or load ramping.762  DCC argues that PJM’s proposal requires that gross 
load and generation configurations be specified upfront and treats material changes in 
those configurations as requiring new applications and studies while prohibiting the 
mixing of NITS and Contract Demand transmission services for the same load.  DCC 
argues that, while PJM has acknowledged limited flexibility in certain circumstances, it 
does not provide a clear or workable pathway for customers to (a) ramp load over time, 
(b) transition between service constructs, or (c) seek to align transmission service with 
phased project development.  DCC argues that the absence of a defined ramping 
framework introduces uncertainty, increases the risk of delay, and may require repeated 
study cycles that are not aligned with project timelines.  DCC argues that the 
Commission should require PJM to establish clear rules and processes that enable 
incremental load additions without triggering unnecessary re-study or requiring 
customers to fundamentally restructure their service arrangements.763 
 Market Monitor argues that the assumption underlying NFCD transmission 
service, that load pays for transmission only when it needs transmission, is untenable.764  
Market Monitor states that although NFCD transmission service can only be a standby 
service, the equivalent availability factor of generators in PJM demonstrates that NFCD 
transmission service would have to be used regularly.  Market Monitor argues that if all 
or a significant part of data center users wanted to use NFCD transmission service, the 
system would become unmanageable and the service would not be available consistently, 
making it meaningless.  Market Monitor asserts that there can be no such service as 
NFCD transmission service that is fully consistent with maintaining a reliable PJM 
transmission system, and all transmission customers should pay for full NITS service.  
c. 
Reply Briefs 
 PJM argues that its proposal to limit NFCD transmission service to circumstances 
where the Co-Located Generator is on outage is just and reasonable, consistent with the 
December Order, and otherwise appropriate.  PJM argues that, if customers could take 
unlimited NFCD transmission service, that would be tantamount to offering Interim NITS 
permanently.765  PJM next argues that the Commission stated in the December Order that 
NFCD transmission service would be available “as needed” for customers able to limit 
withdrawals, which suggests the Commission did not intend for this service to be used on 
 
762 DCC Response Brief at 6.  
763 Id. at 6-7. 
764 Market Monitor Response Brief at 5-6. 
765 PJM Reply Brief at 6-7.

Docket No. EL25-49-002, et al. 
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an everyday basis.766  Moreover, PJM argues, its proposal is appropriate given the 
inherent risks to the transmission system and operational complexities associated with 
providing this service continuously, given the limited time period the non-firm service 
will be required.  PJM asserts that the transmission system is not planned and designed to 
accommodate these non-firm services under North American Electric Reliability 
Corporation (NERC) reliability standards.   
 PJM maintains that several aspects of NFCD transmission service are challenging 
from a reliability perspective, given the range of requirements of NERC reliability 
standards.  PJM alleges that the nature of NFCD transmission service dictates that PJM 
will not include this service in PJM’s long-term transmission planning and the system 
will not be evaluated for potential Corrective Action Plans, nor will PJM have procured 
capacity to serve this load.767  PJM also claims that, because NFCD transmission service 
relies on transmission capacity that is not currently used, PJM is unlikely to be in a 
position to provide this service during peaks or other times when the system is operating 
under stressed conditions.  PJM argues that, from a transmission planning perspective, 
NFCD transmission service increases the operational risk of System Operating Limit and 
Interconnection Reliability Operating Limit (SOL/IROL) exceedances by operating the 
system with a reduced margin for contingency to accommodate high-volume loads.768  
PJM contends that this operation increases the risk of an emergency occurring if 
unexpected conditions occur.  PJM argues that providing NFCD transmission service will 
almost inevitably require significant adjustments to PJM’s Operating Plan to mitigate 
exceedances of SOLs/IROLs each time service is provided due to the nature of the 
service.  PJM maintains that, by definition, NFCD transmission service involves a 
customer drawing large quantities of power over transmission facilities that were not 
designed to serve that load and thus will almost certainly necessitate flowing power over 
various facilities near system limits.769 
 Indicated TOs support PJM’s proposals to restrict the use of NFCD transmission 
service to periods when on-site generation is on outage and claim that the Commission 
did not intend for this service to be a substitute for FCD transmission service or NITS for 
the portion of on-site load that will not be served by on-site generation.  Indicated TOs 
argue that there is no compelling reason for NFCD transmission service to be available 
 
766 Id. at 7 (quoting December Order, 193 FERC ¶ 61,217 at P 215). 
767 Id. at 9-10. 
768 Id. at 11-12. 
769 Id. at 12-13.

Docket No. EL25-49-002, et al. 
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during non-outage conditions.770  Indicated TOs claim that limiting the use of NFCD 
transmission service is necessary to ensure the reliable operation of the PJM transmission 
system, particularly because of the increasing use of special protection schemes, remedial 
action schemes, and other control technologies and protective systems.  Indicated TOs 
recommend that PJM clarify in the Tariff that an “outage” for these purposes is limited to 
periods where a generator is offline due to a breakdown or maintenance issues and does 
not cover other instances when a generator is not operating.771   
 Joint Co-Location Developers urge the Commission to reject PJM’s attempt to 
limit the availability of NFCD transmission service and require PJM to establish a NFCD 
transmission service product available during normal system conditions as required by 
the December Order.772  Joint Co-Location Developers contend that the workable                
non-firm transmission service offerings that are broadly available are fully consistent 
with reliable system operation, as demonstrated in other regions that are rapidly moving 
to implement non-firm transmission service offerings.773  Joint Co-Location Developers 
argue that limiting the scope of NFCD transmission service scheduling to generator 
outages, as PJM proposes, will increase reliance on simple withdrawal-limiting protection 
systems rather than decrease it because it will increase the frequency with which a 
customer will not be authorized to withdraw.774  Joint Co-Location Developers explain 
that this is because withdrawal-limiting protection systems are only active when the 
customer cannot withdraw, i.e., because no transmission service has been scheduled.  
Joint Co-Location Developers argue that PJM should limit the arming of remedial action 
schemes, or avoid installing them in the first place, and instead maximize use of                    
pre-contingency NFCD transmission service curtailment through scheduling, which is 
similar to how Southwest Power Pool, Inc. (SPP) and Electric Reliability Council of 
Texas (ERCOT) envision curtailment under the non-firm transmission services that they 
are developing.775 
 In response to DCC’s concerns about phasing in Co-Located Load, PJM maintains 
that its proposal provides a workable pathway for phased development or load 
 
770 Indicated TOs Reply Brief at 3-4. 
771 Id. at 5-6. 
772 Joint Co-Location Developers Reply Brief at 10-11. 
773 Id. at 1.  
774 Id. at 7.  
775 Id. at 8.

Docket No. EL25-49-002, et al. 
- 164 - 
ramping.776  PJM argues that the obvious path for Co-Located Load that increases over 
time is NITS, a transmission service designed to accommodate load growth.  If an 
Eligible Customer elects Contract Demand transmission service, any change to the 
contracted amount would require a new service request.  PJM adds that the Eligible 
Customer could elect to request Interim NITS or FCD transmission service for their full 
load amount ahead of time and use that capacity as their demand increases up to the 
applied for service level.  PJM explains that the Commission directed PJM to offer FCD 
and NFCD transmission services as an alternative to NITS; thus, it is reasonable for this 
new service to not accommodate load growth as NITS does. 
d. 
Answer 
 Geronimo Power asserts that PJM’s proposed restrictions on NFCD transmission 
service are inconsistent with the December Order and should be rejected.777  In response 
to PJM’s and Indicated TOs’ concerns with making this service more broadly available, 
Geronimo Power argues that PJM does not need to expand its transmission system or 
otherwise change its operations to accommodate this load; rather, it merely needs to 
allow such load to take transmission service when it is available.778  Geronimo Power 
argues that the effect of PJM’s proposal will be to severely limit co-location opportunities 
in PJM, because large loads will need to either co-locate with a resource that can be 
called upon at all times or to take NITS or FCD transmission service that will result in the 
same inefficient and costly grid buildout that the December Order sought to avoid.779 
e. 
Determination 
 As discussed below, we find that PJM’s proposal does not comply with the 
Commission’s directives in the December Order and would fundamentally alter the 
nature of the FCD and NFCD transmission services that the Commission directed PJM to 
develop.  PJM proposes to require that the Eligible Customer taking transmission service 
on behalf of a Co-Located Load must take sufficient transmission service to account for 
the entire gross demand of the Co-Located Load.780  PJM states that an Eligible Customer 
taking service on behalf of a Co-Located Load must request NFCD transmission service 
equal to the MW level of the Co-Located Generator dedicated to serving the Co-Located 
 
776 PJM Reply Brief at 37-38. 
777 Geronimo Power May 21 Answer at 4.   
778 Id. at 6. 
779 Id. at 7. 
780 PJM Initial Brief at 6, 9.

Docket No. EL25-49-002, et al. 
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Load, so that the customer is eligible to obtain NFCD transmission service if the          
Co-Located Generator is on outage.781  PJM also explains that any portion of the gross 
demand of the Co-Located Load not served by the Co-Located Generator must be 
covered by FCD transmission service.782  This proposal would tie the amount of FCD and 
NFCD transmission services that an Eligible Customer can request to the size of the      
Co-Located Generator, rather than allowing the Eligible Customer to select any amount, 
including 0 MW for NFCD transmission service, as the Commission directed.  
Specifically, the December Order stated that Eligible Customers on behalf of Co-Located 
Loads would be able to take a combination of FCD and NFCD transmission services, but 
that “Eligible Customers taking transmission service on behalf of Co-Located Loads that 
will not withdraw energy from the transmission system must take [NFCD] transmission 
service at 0 MW.”783  PJM’s proposal would do the opposite.  An Eligible Customer 
taking transmission service on behalf of a Co-Located Load that wished to be served 
entirely by the Co-Located Generator, and not withdraw any energy from the 
transmission system, would be required under PJM’s proposal to request NFCD 
transmission service at a level of contract demand equal to the Co-Located Load’s gross 
load.784  Moreover, contrary to PJM’s proposal, nothing in the December Order would 
require an Eligible Customer taking transmission service on behalf of a Co-Located Load 
to take FCD transmission service at a level of contract demand that reflects the amount of 
load not served by the Co-Located Generator (or, for that matter, to take FCD 
transmission service at all).  In short, the December Order does not link the level of 
contract demand for either FCD or NFCD transmission service that an Eligible Customer 
may take on behalf of a Co-Located Load to the size of the Co-Located Generator or the 
size of the Co-Located Load.   
 Taken together, PJM’s proposed new conditions on FCD and NFCD transmission 
services mean that if PJM determines as a result of studies that it cannot accommodate a 
request for NFCD transmission service, the Eligible Customer will be required to request 
and take a firm transmission service (FCD transmission service or NITS) on behalf of the 
Co-Located Load instead.  In the December Order, the Commission directed PJM to 
implement FCD and NFCD transmission services in response to a finding that the Tariff 
is unjust and unreasonable because it does not include transmission services that reflect 
Eligible Customers taking service on behalf of Co-Located Loads that are willing and 
able to limit their energy withdrawals from the transmission system under certain 
 
781 Id. at 9, 16. 
782 Id. at 6-7. 
783 December Order, 193 FERC ¶ 61,217 at P 206. 
784 PJM Initial Brief at 9.

Docket No. EL25-49-002, et al. 
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conditions.785  PJM’s proposal does not address this finding and proposes to create FCD 
and NFCD transmission services that continue to fail to recognize this flexibility.  
Moreover, requiring an Eligible Customer seeking to take transmission service on behalf 
of a Co-Located Load to take FCD transmission service or NITS instead of NFCD 
transmission service when it does not seek to take firm transmission service would be 
inconsistent with the Commission’s finding in the December Order that the lack of the 
required new transmission services could result in unnecessary, costly, and inefficient 
Network Upgrades, increasing Network Upgrade costs.786  While we recognize that PJM 
may determine that there is insufficient available transmission capacity to fulfill a request 
for NFCD transmission service,787 in that scenario, the Eligible Customer seeking to take 
that service on behalf of a Co-Located Load should then be able to decide whether it 
would prefer to request FCD transmission service or NITS to serve the load – in which 
case it may be responsible for Network Upgrade costs – or to take 0 MW of NFCD 
transmission service and thus have no contractual right to withdraw power from the 
transmission system.   
 PJM’s proposal is also inconsistent with the December Order in that PJM proposes 
to limit the amount of NFCD transmission service that may be reserved by an Eligible 
Customer to a MW level equivalent to the amount of the Co-Located Generator that is on 
outage.788  The December Order did not require such a restriction and instead 
contemplated that NFCD transmission service would be available during “normal” 
operations when there is sufficient available transmission capacity,789 providing Eligible 
Customers seeking to take transmission service on behalf of Co-Located Loads the 
 
785 December Order, 193 FERC ¶ 61,217 at P 193. 
786 See id. P 177 (“[F]or Eligible Customers taking service on behalf of              
Co-Located Loads that do not reserve transmission or take energy from the transmission 
system but which receive only regulation and black start services, or that otherwise are 
willing and able to limit their energy withdrawals from the transmission system, 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.”). 
787 See id. P 215 (stating that reservations for NFCD transmission service “would 
be available only when there is available transmission capacity, similar to existing                
non-firm transmission service options in the Tariff”). 
788 PJM Initial Brief at 32. 
789 December Order, 193 FERC ¶ 61,217 at PP 214-215.

Docket No. EL25-49-002, et al. 
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flexibility to request to reserve any amount of NFCD transmission service, regardless of 
whether the Co-Located Generator was on outage.  The Commission’s reference to 
NFCD transmission service and generator outages was an example and not a threshold 
requirement for an Eligible Customer to use this service.790  Regardless, because the 
Commission contemplated that the service would be available during normal operations 
when there is sufficient available transmission capacity, Eligible Customers seeking to 
take NFCD transmission service on behalf of Co-Located Loads must be permitted to 
request such service on an everyday basis.  Further, contrary to the December Order, 
PJM’s proposal to allow Eligible Customers taking transmission service on behalf of              
Co-Located Loads to take NFCD transmission service only when the Co-Located 
Generator is on outage fails to 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 because it removes the option to 
take NFCD transmission service instead of FCD transmission service for portions of the 
Co-Located Load that are not served by the Co-Located Generator.   
 PJM argues that these changes to NFCD transmission service are necessary for 
reliability, to ensure all load is studied.  We disagree.  Co-Located Load is, as defined in 
the December Order, behind the Point of Interconnection of an interconnected generator, 
and PJM would already know the size of the generator and any Co-Located Load from 
the interconnection process (or Necessary Study), and possibly the transmission service 
application process.  While the portion of load for which the Eligible Customer does not 
request transmission service would not be modeled by PJM in a transmission service 
request as withdrawing energy from the transmission system, this outcome is appropriate 
because the Eligible Customer is not intending to withdraw energy from the transmission 
system.  However, the potential impact of the Co-Located Load on the reliability of the 
transmission system will still be studied as part of the Necessary Study process for the 
generator interconnection modification, or as part of a New Service Request.  PJM 
already conducts dynamic studies for Co-Located Load, which evaluate all applicable 
NERC, PJM, and transmission owner-specific contingencies and criteria, consistent with 
PJM’s responsibilities to ensure system reliability.791  These studies utilize a composite 
load model that includes power electronics, cooling, and lighting loads, and the impact of 
the facility during this study is dependent on the physical parameters of the facility and 
 
790 See id. P 214 (“Eligible Customers taking service on behalf of such loads may, 
however, still seek to withdraw energy from the transmission system from time to time 
when transmission capacity is available and not needed by firm customers.  For example, 
an Eligible Customer could seek a transmission reservation for a Co-Located Load in 
advance for the duration of an expected outage of the associated generator.”) (emphasis 
added). 
791 PJM March 24, 2025 Response at 53.

Docket No. EL25-49-002, et al. 
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its control behavior, not the level or type of transmission service taken.792  This model is 
a complete model of the facility.793  As such, PJM, as it currently does, will know the full 
impact of factors unrelated to the contract demand of the Co-Located Load, including 
impacts on stability margins, short circuit limits, power quality and harmonic distortion, 
voltage flicker, interaction of active power electronic controls with the system (e.g., 
mitigation of oscillatory behavior), impact of STATCOMs or other reactive 
compensation devices, and cyclical demand ramps in the sub-synchronous frequency 
range.  PJM provides no explanation why this data already available to them is 
insufficient to fully study a Co-Located Load absent changes to NFCD transmission 
service. 
 PJM also argues that providing NFCD transmission service will require 
adjustments to PJM’s Operating Plan to mitigate exceedances of SOLs/IROLs each time 
service is provided due to the nature of the service.  While serving load using NFCD 
transmission service may reduce operating margins on the transmission system, PJM has 
presented no evidence that changes to PJM’s Operating Plan will be regularly needed.  
However, should PJM find, based on operating experience in implementing the NFCD 
transmission service, that significant and frequent manual adjustments are necessary, 
PJM may consider filing an FPA section 205 filing to adjust the curtailment priority of 
NFCD transmission service.   
 PJM also argues that, by definition, NFCD transmission service involves a 
customer drawing large quantities of power over transmission facilities that were not 
designed to serve that load and thus will almost certainly necessitate flowing power over 
various facilities near system limits.  While we acknowledge that NFCD transmission 
service is designed to use available transmission capacity that is not needed by firm 
transmission customers, we find that PJM’s assertion that providing such service will 
necessitate flowing power over various transmission facilities near system limits is 
speculative.  In any case, as the Commission stated in the December Order, 
“[r]eservations under this service would be available only where there is available 
transmission capacity, similar to existing non-firm transmission service options in the 
 
792 Id.  We note that NERC has recommended use of the Power Electronic 
Reconnecting and Ceasing (PERC1) model, which is a different model than the current  
model PJM utilizes.  However, the general principles are the same.  See NERC, Essential 
Action to Industry:  Computational Load Modeling, Studies, Instrumentation, 
Commissioning, Operations, Protection, and Control at 3 (2026), 
https://www.nerc.com/globalassets/programs/bpsa/alerts/level-3-computational-load-
alert.pdf. 
793 See, e.g., PJM, PJM Dynamic Model Development Guidelines for 
Interconnection Analysis § 6, PJM Dynamic Model Development Guidelines.

Docket No. EL25-49-002, et al. 
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Tariff.”794  And consistent with the Commission’s findings in establishing non-firm 
transmission service under its pro forma Open Access Transmission Tariff, providing 
non-firm transmission service increases efficiency by allowing customers to use lumpy 
transmission investment on an as-available basis and may reduce the costs for firm 
transmission service customers by allowing NFCD transmission service customers to 
offset the costs of that investment.795  However, we note that if PJM determines that there 
may be increased operational risks associated with providing NFCD transmission service, 
it may address those risks by increasing the transmission reliability margin that it uses 
when studying and determining whether to grant requests for NFCD transmission service.  
 We recognize that the new FCD and NFCD transmission services represent a 
significant change in how transmission service has been historically offered in PJM.  We 
also recognize that significant changes to PJM’s software may be necessary to integrate 
the FCD and NFCD transmission services, including to potentially automate some 
processes that are currently handled manually by operators with respect to curtailing    
non-firm transmission services.  However, the Commission directed the new FCD and 
NFCD transmission services as the replacement rate after finding PJM’s existing Tariff 
unjust and unreasonable.  We therefore direct PJM to submit a compliance filing within 
60 days of the issuance of this order proposing Tariff revisions to permit Eligible 
Customers to elect to take FCD transmission service or NFCD transmission service 
without the limitations that PJM proposes (i.e., (1) the requirement that the Eligible 
Customer taking transmission service on behalf of a Co-Located Load must take 
sufficient transmission service to account for the entire gross demand of the Co-Located 
Load, (2) the requirement for an Eligible Customer taking transmission service on behalf 
of a Co-Located Load to take FCD transmission service at a level of contract demand that 
reflects the amount of load not served by the Co-Located Generator, (3) the requirement 
that an Eligible Customer taking service on behalf of a Co-Located Load must request 
NFCD transmission service equal to the MW level of the Co-Located Generating Facility 
dedicated to serving the Co-Located Load if that portion of the Co-Located Load is not 
covered by FCD transmission service, and (4) the restriction on the use of NFCD 
transmission service to only those circumstances where the Co-Located Generator is on 
outage).  Consistent with our determination above to extend the three new transmission 
services set forth in the December Order to Eligible Customers taking service on behalf 
of load with BTMG that are willing and able to limit their energy withdrawals from the 
 
794 December Order, 193 FERC ¶ 61,217 at P 215. 
795 Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,272 (finding “non-firm 
transmission prices should reflect the interruptibility of the service and should promote 
efficient use of the transmission system”).

Docket No. EL25-49-002, et al. 
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transmission system under certain conditions, we further direct PJM to reflect this change 
in its compliance filing. 
 With respect to DCC’s argument that PJM’s proposal does not provide a workable 
pathway for phased development or load ramping,796 we disagree.  Because FCD 
transmission service is based on a reserved amount of contract demand and does not 
account for load growth in the way that NITS does, Eligible Customers seeking to 
increase the amount of load for which they are taking transmission service over time 
should be required to submit new transmission service requests for any increases in 
contract demand.  As an alternative, they may request a level of contract demand in their 
initial transmission service request that reflects their planned total load, even though they 
may not need the full level of contract demand immediately.  To the extent that neither of 
these options work for a particular Eligible Customer taking transmission service on 
behalf of a Co-Located Load, that Eligible Customer should consider taking NITS, which 
accommodates load growth over time, as PJM suggests.797   
 DCC also argues that PJM prohibits the mixing of NITS and FCD or NFCD 
transmission service for the same load.798  However, in the December Order, the 
Commission explicitly stated that NITS cannot be combined with any of the new 
transmission services.799  As such, we find that DCC’s argument is an untimely request 
for rehearing of the December Order and dismiss it.800   
 With respect to DCC’s argument that Eligible Customers serving Co-Located 
Load should be able to transition between transmission services,801 we note that Eligible 
Customers taking transmission service on behalf of Co-Located Load that wish to 
transition from one transmission service to another may do so through the same process 
 
796 DCC Response Brief at 6. 
797 PJM Reply Brief at 37-38. 
798 DCC Response Brief at 6. 
799 December Order, 193 FERC ¶ 61,217 at P 195 n.408 (“Eligible Customers 
taking NITS on behalf of Co-Located Load may not combine NITS with any of the other 
transmission services discussed herein.”). 
800 See, e.g., ISO New Eng. Inc., 132 FERC ¶ 61,098 at P 12 (“The Commission 
has held that requests to alter a compliance filing in a manner that differs from the order 
requiring the compliance filing constitute a collateral attack on the order requiring the 
compliance filing.”). 
801 DCC Response Brief at 6.

Docket No. EL25-49-002, et al. 
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as any other party requesting new transmission service, with the exception of the                  
anti-toggling procedures discussed below in Part VI.E. 
 Finally, with respect to Market Monitor’s argument that NFCD transmission 
service is untenable, we dismiss this argument as an untimely request for rehearing of the 
December Order.  We disagree that NFCD transmission service is untenable if it is not 
available constantly; to the contrary, NFCD transmission service is designed to be       
non-firm and as-available, meaning that it will sometimes be unavailable or curtailed.  It 
is possible that if, for example, a significant number of Eligible Customers taking 
transmission service on behalf of Co-Located Loads were to switch to NFCD 
transmission service, it would be frequently curtailed, but that is the nature of non-firm, 
as opposed to firm, transmission service.  Eligible Customers taking transmission service 
on behalf of Co-Located Loads that do not wish to be curtailed should consider 
requesting a firm transmission service instead. 
3. 
Study Process 
a. 
Initial Briefs 
 PJM states that it will coordinate with the affected transmission owner to complete 
studies, obtain relevant data, and identify any necessary enhancements to the 
transmission system to accommodate the requested level of service.802  PJM also states 
that, during the study period, it may perform other studies.   
 PJM proposes that it notify the affected transmission owner of an application for 
FCD transmission service to allow for coordination to study the potential impacts of 
providing this service on the transmission owner’s system.803  PJM states that it will 
determine any necessary studies to provide the requested transmission service.  If studies 
are needed, PJM explains, it will provide an application and studies agreement to the 
Eligible Customer in which the Eligible Customer will agree to reimburse PJM for study 
costs.  PJM also states that it will consider the results of any transmission owner studies. 
 PJM proposes that, upon receiving a service request, it will coordinate with the 
affected transmission owner to complete necessary studies to determine whether, and at 
what level, NFCD transmission service can be reliably provided.804  PJM proposes that it 
and the affected transmission owner will determine whether additional studies are 
required to assess the NFCD transmission service request, and if so, which studies are 
 
802 PJM Initial Brief at 17-18. 
803 Id. at 24. 
804 Id. at 32-33.

Docket No. EL25-49-002, et al. 
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appropriate.  PJM proposes that it will provide a written explanation if it determines that 
none or only a portion of the requested service can be reliably provided.   
b. 
Response Briefs  
 Indicated TOs support PJM’s proposed study processes for FCD transmission 
service and state that it appropriately recognizes the role of transmission owners in 
evaluating load interconnection requests.805  Indicated TOs argue, however, that the 
Tariff should specify that load integration studies should be completed first and inform 
the determination of whether additional studies are necessary for purposes of an Eligible 
Customer’s request for transmission service on behalf of a Co-Located Load and the 
interconnection of any on-site generation.  Indicated TOs contend that this requirement 
would maximize the speed and efficiency of the overall process and avoid potential 
duplication of effort and expense as between PJM and the PJM transmission owners.  
 Indicated TOs state that PJM appears to contemplate that an Eligible Customer’s 
initial application for NFCD transmission service would serve as a “holding” request and 
that the actual reservation and use of the service would require the Eligible Customer to 
make a request and PJM to determine whether or not the requested amount of service is 
available.806  Indicated TOs further state that the available amount of NFCD transmission 
service presumably would serve as the basis for determining the relevant charge to the 
Eligible Customer.  Indicated TOs request that PJM confirm these understandings and 
add appropriate Tariff language.  Indicated TOs also request that PJM clarify whether the 
study process set forth in section 710.3 of the illustrative tariff provisions is intended to 
cover only the initial service study or also subsequent determinations as to specific 
reservation requests.  Generally, Indicated TOs argue that more detail should be provided 
as to the process for evaluating and granting requests for NFCD transmission service, 
including the timelines associated with such requests, particularly with respect to forced 
rather than planned outages.807  Indicated TOs also contend that PJM should specify in 
Tariff language that NFCD transmission service will be available for periods from one 
month to one hour in duration. 
 Several parties argue that PJM’s proposed study process is unjust and 
unreasonable.808  Constellation argues that PJM fails to sufficiently describe its proposed 
study procedures for the three new services.  Vistra similarly argues that PJM’s study 
 
805 Indicated TOs Response Brief at 5-7. 
806 Id. at 4. 
807 Id. at 4-5. 
808 Vistra Response Brief at 31, 33-35; Constellation Response Brief at 14-15.

Docket No. EL25-49-002, et al. 
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process provides too much discretion to PJM and transmission owners to determine 
whether studies are required, which studies to conduct, the timeline for doing so, and how 
to prioritize different requests.  First, Vistra asserts that PJM does not propose a 
mechanism to assign customers a queue position based on the submission of a complete 
application.  Vistra also charges that PJM reserves to itself full discretion to determine 
whether studies must be conducted and what analyses those studies will involve, and 
alleges that the proposed tariff does not appear to limit the results of PJM’s analysis of 
transmission service requests to the results of duly conducted studies because it states that 
PJM will “consider” the results of the study procedures.809  Vistra and Constellation also 
argue that PJM provides no timelines or deadlines for processing transmission service 
requests.  Vistra also argues that PJM provides itself total discretion to set study fees with 
no parameters for setting those fees.  Vistra and Constellation express concern that the 
discretion in PJM’s proposal creates a risk of undue discrimination.  Vistra and 
Constellation argue that PJM’s proposal violates the Commission’s rule of reason policy 
because the information missing from the tariff proposal significantly affects rates, is 
readily susceptible of specification, and is not so readily understood as to render 
recitation superfluous.810  Vistra also contends that PJM’s proposal is unclear on what it 
means to ensure that non-firm transmission service can be provided “reliably,” and 
requests that PJM articulate the standard.811 
c. 
Reply Briefs 
 PJM maintains that its illustrative tariff contains an appropriate amount of detail 
on the study process and states that it will work with stakeholders to develop 
implementation details to be set forth in the PJM manuals.812  PJM avers that the 
illustrative tariff provides more than enough detail to satisfy the Commission’s rule of 
reason policy.  PJM alleges that its proposal builds on its existing processes for studying 
requests for new transmission service requests.  PJM contends that its evaluation of firm 
transmission service requests will require and follow similar study procedures to what is 
now required for NITS.  For non-firm transmission service requests, PJM asserts that the 
study approach could differ widely for each request and will depend on a number of 
factors.   
 PJM explains that, currently, the transmission owners study in the first instance all 
requests to connect new load to the transmission system.  PJM states that, for each zone, 
 
809 Vistra Response Brief at 33-34 (citing PJM, Initial Brief, attach. A § 702.3). 
810 Id. at 36-37, 53; Constellation Response Brief at 15-18. 
811 Vistra Response Brief at 39. 
812 PJM Reply Brief at 22-23, 26, 32.

Docket No. EL25-49-002, et al. 
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the transmission owner studies the integration of the requested load and identifies 
upgrades.  PJM says that it then performs a “do no harm” analysis of how those 
transmission owner-identified upgrades would affect the regional transmission system.  
PJM notes that NITS can then be provided consistent with the in-service date of the 
identified upgrades.813  PJM contends that the allocation of responsibilities between the 
transmission owners and PJM in the current study process follows the division of rights 
recently affirmed by the Commission and courts, i.e., transmission owners’ reservation of 
rights over local transmission planning and PJM’s responsibility for the regional 
transmission system.814  PJM claims that it maintains this division of rights in the 
illustrative tariff provisions. 
 PJM also rejects protesters’ arguments that its proposal affords PJM and the 
transmission owners inappropriate discretion.  PJM argues that it seeks no more 
discretion than it currently has under its existing study processes.  PJM argues that its 
evaluation of the transmission system to determine whether it can reliably provide the 
requested transmission service requires an exercise of engineering judgment, which 
inherently entails a reasonable exercise of discretion.815   
 PJM argues that reliability reviews inherently require PJM to make judgment calls 
as the transmission provider and a NERC-designated Reliability Coordinator, and the 
flexibility to determine whether new transmission facilities are reasonably likely to be       
in-service fits squarely within PJM’s expertise.  PJM asserts that protesters’ concerns 
about the level of detail generally concern the transmission owner’s load integration 
studies, which PJM argues does not inherently implicate the Commission’s jurisdiction 
under the FPA.816  In response to concerns about study timelines, PJM contends that its 
evaluation of any transmission service request is dependent on the load integration 
studies performed by the applicable transmission owner.817  PJM asserts that it does not 
 
813 Id. at 24. 
814 Id. at 24 & n.68 (citing PJM Interconnection, L.L.C., 172 FERC ¶ 61,136, 
order on reh’g, 173 FERC ¶ 61,225, at P 19 (2020), aff’d sub nom. Am. Mun. Power, Inc. 
v. FERC, 86 F.4th 922 (D.C. Cir. 2023); PJM Interconnection, L.L.C., 173 FERC                     
¶ 61,242 (2020), order on reh’g, 176 FERC ¶ 61,053 (2021), aff’d sub nom. Am. Mun. 
Power, Inc., 86 F.4th 922; Monongahela Power Co., 164 FERC ¶ 61,217, at P 14 (2018); 
Appalachian Power Co., 170 FERC ¶ 61,196, at P 59 (2020)). 
815 Id. at 25-26.  
816 Id. at 34. 
817 Id. at 28.

Docket No. EL25-49-002, et al. 
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have authority to dictate timelines to transmission owners to complete their studies, given 
that load integration studies are a matter of local transmission planning.   
 PJM also alleges that concerns that PJM will reject transmission service requests 
without basis are unfounded.818  PJM maintains that it will generally grant requests for 
NITS and FCD transmission service, and PJM will grant Interim NITS requests 
consistent with the results of any study/studies.  As to NFCD transmission service, PJM 
explains that, if it denies a request in whole or in part, PJM will provide a written 
explanation to the customer of PJM’s reasoning for the denial, which could form the 
basis for any complaint to the Commission. 
 Moreover, PJM argues that the illustrative tariff puts all parties on sufficient notice 
as to how PJM will determine whether it can provide the requested transmission service 
and the study procedures to arrive at that determination.819  PJM asserts that the 
illustrative tariff provides the standard to which PJM will evaluate the requests—whether 
the requested level of service can be provided reliably.   
 Indicated TOs concede that more detail regarding the study processes for the new 
transmission services could be helpful, but they argue that commenters’ concerns as to 
the potential for delays and undue discrimination are overstated.  Indicated TOs contend 
that it is appropriate and consistent with the Commission’s rule of reason to reference the 
need to incorporate each transmission owner’s technical requirements in the Tariff while 
omitting the details.  Indicated TOs do not oppose making explicit in the Tariff that the 
studies referred to are those that the transmission owners will conduct to integrate large 
load facilities.  Indicated TOs reject claims that they will use their role in the study 
process to delay or deny Co-Location Arrangements or discriminate against Co-Located 
Load.820 
 Constellation requests that the Commission deter delays and potential disputes by 
(1) establishing deadlines for studies and other transmission owner approvals or 
consultation requirements, and (2) require PJM’s and transmission owners’ standards, 
requirements, guidance, and practices on Co-Location Arrangements to be on file with 
the Commission on a standalone basis or reflected in the Tariff.821 
 
818 Id.  
819 Id. at 30. 
820 Indicated TOs Reply Brief at 9-11. 
821 Constellation Reply Brief at 11-12.

Docket No. EL25-49-002, et al. 
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 PJM argues that Vistra oversimplifies the provision of non-firm transmission 
service.822  PJM states that it is not the case that the transmission system has significantly 
underutilized capacity to provide the envisioned services.  PJM alleges that it needs to 
carefully identify and manage operational risk instead of spontaneously managing                     
non-firm load under an increasingly stressed system.  Constellation also argues that PJM 
should clarify how it will determine the future and real-time availability of NFCD 
transmission service, which should be based on when transmission capacity is available 
and not needed by firm customers, consistent with the December Order.823 
d. 
Answers 
 Constellation argues that the Commission has jurisdiction to regulate load 
integration studies in connection with jurisdictional transmission service.824  
Constellation contends that the Commission should exercise jurisdiction over the load 
integration studies needed to provide jurisdictional transmission service and direct that 
these studies be on file, including study deadlines and violations to be studied.825 
 Indicated TOs argue that transmission owner processes for studying the integration 
of new retail loads do not implicate the Commission’s jurisdiction, even though such 
studies will be used as an input in PJM’s process for studying applications for the new 
transmission services.826  Indicated TOs point out that, even as to studies for 
Commission-jurisdictional services, the Commission does not require transmission 
providers to file studies.827  Indicated TOs maintain that, if an Eligible Customer disputes 
the outcome of PJM’s study process for the new transmission services, the customer can 
seek redress through the Commission.   
e. 
Determination 
 We find that PJM’s proposal regarding study procedures for FCD and NFCD 
transmission services is not sufficiently detailed to be just and reasonable, and we direct 
 
822 PJM Reply Brief at 35-36. 
823 Constellation Reply Brief at 18 (citing December Order, 193 FERC ¶ 61,217                
at P 214). 
824 Id. at 6. 
825 Id. at 7. 
826 Indicated TOs May 28 Answer at 8. 
827 Id. at 9.

Docket No. EL25-49-002, et al. 
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PJM to file, as the replacement rate, more detailed study procedures that mirror the 
existing study procedures for transmission service on compliance.828  First, with respect 
to FCD transmission service, we agree with parties on briefing that PJM’s proposal is 
vague and unclear.  We direct PJM to file Tariff revisions on compliance to study 
requests for FCD transmission service using the same process PJM uses for new service 
requests for NITS, i.e., the cluster study process.829  This requirement is just and 
reasonable because it will treat new firm transmission service requests similarly.   
 PJM contends that its proposal “has built on its existing processes for studying 
requests for new transmission services . . . with additional processes necessary to study 
the novel aspects of Interim NITS and [FCD and NFCD] Transmission Services.”830  
PJM also states that “[e]valuation of firm service requests will require and follow similar 
study procedures to what is now required for NITS.”831  However, PJM’s proposal is 
lacking in detail.  It is not clear whether PJM proposes to study requests for FCD 
transmission service serially or through its existing cluster study process.832   
 Regardless, we find that it is just and reasonable to study requests for FCD 
transmission service through PJM’s existing cluster study process, and we direct PJM to 
file Tariff revisions on compliance consistent with this directive.  We find a serial study 
process for new FCD transmission service requests, rather than a cluster study as for new 
NITS requests, would provide disparate treatment to FCD transmission service requests.  
PJM also does not address a timeline for its study process, meaning FCD transmission 
service requests could be studied more quickly or more slowly than requests in the new 
services queue.  PJM does not provide a reason for this difference or any explanation as 
to why such requests should not be studied in the normal cluster process for new service 
requests.  Further, studying such requests as part of the established cluster study process 
 
828 We discuss PJM’s proposed study procedures for Interim NITS below in                  
Part VI.H. 
829 PJM, Intra-PJM Tariffs, OATT, § III.32.3 Initial Study Procedures (3.0.0) (“A 
request for service for which a Phase I System Impact Study is required is subject to the 
System Impact Study Procedures, as set forth in Tariff, Part VII or Tariff, Part VIII, as 
applicable.”). 
830 PJM Reply Brief at 23. 
831 Id. at 26. 
832 See PJM, Initial Brief, attach. A, § 712.1 (“After receiving the Application for 
Firm Contract Demand Transmission Service, the Transmission Provider shall determine, 
in accordance with the PJM Manuals, any necessary studies for reliably providing the 
requested Firm Contract Demand Transmission Service.”).

Docket No. EL25-49-002, et al. 
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would address many of the concerns in the record because it would ensure Eligible 
Customers have more detail, transparency, and certainty regarding the study process, 
which is the primary concern of the protesters.833  Thus, we direct PJM to submit a 
compliance filing within 60 days of the date of issuance of this order to revise its Tariff to 
provide that it will study FCD transmission service requests using its existing process for 
studying firm transmission service requests.  Consistent with our determination above to 
extend the three new transmission services set forth in the December Order to Eligible 
Customers taking service on behalf of load with BTMG that are willing and able to limit 
their energy withdrawals from the transmission system under certain conditions, we 
further direct PJM to reflect this change in its compliance filing. 
 With respect to NFCD transmission service, we agree with parties arguing that 
PJM’s proposal lacks specificity.  PJM argues that “the study approach could differ 
widely for each request, given the different nature of the risks involved, as the system 
would be operated on an as-conditions-permit basis.”834  The lack of detail creates a level 
of discretion that is not just and reasonable; while some amount of discretion is likely 
necessary to ensure PJM is able to perform any additional studies necessary to maintain 
reliability, Eligible Customers must have some understanding of the study process PJM 
will use to evaluate transmission service requests.  Therefore, we direct PJM to submit a 
compliance filing within 60 days of the date of issuance of this order that revises its 
Tariff to include study procedures for NFCD transmission service requests.  We note that 
the Tariff includes detailed procedures for the study of Non-Firm PTPS, which serve as a 
useful reference.  In particular, the Tariff provides that, following receipt of a tendered 
schedule, PJM will make a determination on a non-discriminatory basis of available 
transfer capability for PTPS requests, based on a specific methodology detailed in Tariff, 
Attachment C.835  No party has shown why a similar process should not apply for NFCD 
transmission service, and PJM has not demonstrated that having so little detail in the 
Tariff regarding the process for studying requests for NFCD transmission service is just 
and reasonable.  PJM’s compliance filing must also include details about the term length 
of NFCD transmission service, including the minimum term.  Consistent with our 
determination above to extend the three new transmission services set forth in the 
December Order to Eligible Customers taking service on behalf of load with BTMG that 
 
833 See PJM, Intra-PJM Tariffs, pt. VIII, § 404 (1.0.0) (providing overview of 
system impact studies, including scope of studies). 
834 PJM Reply Brief at 26. 
835 See PJM, Intra-PJM Tariffs, OATT, §§ II.15.2, II.18.4; id. attach. C 
(Methodology to Assess Available Transfer Capability).

Docket No. EL25-49-002, et al. 
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are willing and able to limit their energy withdrawals from the transmission system under 
certain conditions, we further direct PJM to reflect this change in its compliance filing. 
 Indicated TOs request that the Tariff specify that transmission owner load 
integration studies will be completed first and thereby inform what additional studies are 
necessary.  However, it is not clear from the record what these studies entail, as these 
studies are not defined in either the Tariff or any of PJM’s manuals, or how transmission 
owners will study the load.  For example, the record indicates that Indicated TOs view a 
load integration study for Co-Located Load as potentially analyzing “(i) what, if any, 
upgrades are needed to accommodate the physical gross load amount behind the point of 
interconnection.”836  To the extent PJM intends to permit transmission owners to study 
Co-Located Load as if it were native load with NITS, that would not be just and 
reasonable for FCD and NFCD transmission services.  We therefore direct PJM to 
specify in a compliance filing, which it must submit within 60 days of the date of 
issuance of this order, how transmission owners shall participate in PJM’s study process 
for Eligible Loads for FCD and NFCD transmission services and specify in detail the 
related roles and responsibilities of PJM and the transmission owners in such studies.  We 
decline at this time to adopt Indicated TOs’ requests to incorporate further revisions to 
the Tariff related to load integration studies.837 
4. 
Rates and Charges 
a. 
Initial Briefs 
 Indicated TOs propose that the rate for the FCD transmission service be based on 
the zonal NITS rates and underlying NITS revenue requirements.838  Indicated TOs argue 
that Eligible Customers taking FCD transmission service on behalf of Co-Located Load 
and Network Customers should be charged the same rate because the level of service 
provided to both is the same for all relevant purposes.  For example, Indicated TOs argue 
that both services are firm transmission services for which PJM procures capacity for the 
customers.  Indicated TOs argue that it would be unjust and unreasonable and unduly 
discriminatory to charge FCD transmission service customers a rate lower than the NITS 
rate as it would subsidize FCD transmission service customers at the expense of Network 
Customers.  Indicated TOs contend that it is appropriate to use the single peak coincident 
demand to calculate the FCD transmission service rate because it is an annual service.  
 
836 Indicated TOs Initial Brief at 25-26 (emphasis added). 
837 Indicated TOs Response Brief at 13, 16, 19. 
838 Indicated TOs Initial Brief at 6, 8-9.

Docket No. EL25-49-002, et al. 
- 180 - 
 Indicated TOs propose that NFCD transmission service pay a charge for the 
reserved contract demand amount multiplied by a zonal NFCD transmission service rate 
determined based on the specific term of service.839  Indicated TOs propose to use the 
same FCD transmission service rate for purposes of establishing the maximum rate for 
NFCD transmission service.  Indicated TOs argue that it is just and reasonable to use the 
same maximum rate for FCD and NFCD transmission services, because the Commission 
has permitted pricing Non-Firm PTPS at the rate used for Firm PTPS and because the 
Commission provides flexibility to arrange and schedule NFCD transmission service.  
Indicated TOs allege that NFCD transmission service is superior to Non-Firm PTPS 
because PJM will re-dispatch generation prior to curtailing NFCD transmission service.  
Indicated TOs propose to consider on a going-forward basis whether a discount is 
appropriate for NFCD transmission service based on system conditions and use patterns.   
 In addition to these charges, PJM proposes to assess, for FCD transmission 
service:  (1) administrative service charges, (2) ancillary service charges, (3) black start 
service charges based on gross demand, (4) regulation charges based on gross demand, 
and (5) any redispatch costs.  PJM contends that these are standard charges associated 
with use of the transmission system above transmission service rates.840  For NFCD 
transmission service, PJM also proposes to assess certain charges within its authority:   
(1) administrative charges, (2) ancillary services charges, (3) any redispatch costs,                    
(4) regulation charges based on gross demand, and (5) black start service charges based 
on gross demand.841   
b. 
Response Briefs 
 Several parties argue that it is just and reasonable to charge the same rate for FCD 
transmission service and NITS.842  NOVEC explains that Eligible Customers are 
receiving a service commensurate with NITS and should therefore pay a cost 
commensurate with NITS in recognition of the Commission’s cost causation principles.  
Market Monitor asserts that if customers have the option to convert from FCD 
transmission service to NITS in the future, and given the long timelines in transmission 
planning and the extreme lumpiness of transmission investments, PJM must plan as if all 
 
839 Id. at 10, 11-13. 
840 PJM Initial Brief at 27. 
841 Id. at 36-37. 
842 ODEC Response Brief at 8; NOVEC Response Brief at 6-7; Market Monitor 
Response Brief at 3-4.

Docket No. EL25-49-002, et al. 
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Eligible Customers taking the new contract demand transmission services are Network 
Customers.  
 Some parties also agree that it is just and reasonable to use the FCD transmission 
service rate as the maximum rate for NFCD transmission service.843  NOVEC argues that 
NFCD transmission service is a network-type service that bears a resemblance to NITS.  
NOVEC notes that because an Eligible Customer only purchases NFCD transmission 
service when reserved, transmission costs for an Eligible Customer are lower than firm 
rates.  
 Other parties disagree that the proposed rate for NFCD transmission service is just 
and reasonable.844  Vistra alleges that Indicated TOs fail to justify not offering a 
discounted rate for NFCD transmission service when such a discount exists for Non-Firm 
PTPS.  Vistra contends that the benefit of re-dispatching generation prior to curtailment 
does not justify charging a substantially higher rate for a service that is otherwise inferior.  
Vistra also argues that Indicated TOs’ proposal is unjust and unreasonable and unduly 
discriminatory because it would create cost shifts between classes of transmission 
customers, where Eligible Customers taking NFCD transmission service on behalf of    
Co-Located Load shoulder the cost of firm transmission service, despite taking non-firm 
transmission service.  
 Joint Co-Location Developers argue that pricing NFCD transmission service at the 
same rate as FCD transmission service is not consistent with cost causation principles or 
the Commission’s purpose in establishing the NFCD transmission service to avoid 
inefficient system buildout.  Joint Co-Location Developers maintain that, as compared to 
FCD transmission service, the rate for NFCD transmission service should reflect the 
lesser costs caused by and lesser benefits received by customers taking this service.845  
Joint Co-Location Developers claim that, in Order No. 888-A, the Commission explained 
that, while in some circumstances non-firm transmission rates may be set at the firm 
transmission rate level, the Commission expects that non-firm transmission rates would, 
in most instances, be priced below the price cap.846 
 Geronimo Power states that, combined with PJM’s proposed requirement that an 
Eligible Customer take NFCD transmission service for the portion of its load served by a 
 
843 ODEC Response Brief at 8; NOVEC Response Brief at 7. 
844 Vistra Response Brief at 16-17, 23-24; Joint Co-Location Developers Response 
Brief at 20; Geronimo Power Response Brief at 4.  
845 Joint Co-Location Developers Response Brief at 20-21. 
846 Id. at 22 (citing Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,272).

Docket No. EL25-49-002, et al. 
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Co-Located Generator, the implication of the Indicated Transmission Owners’ proposal 
appears to be that an Eligible Customer taking NFCD transmission service would be 
required to pay a transmission charge equivalent to the rate paid by transmission 
customers taking firm transmission service.847  Geronimo Power argues that charging 
transmission customers taking NFCD transmission service the same amount as a 
transmission customer taking FCD transmission service is unjust and unreasonable and 
inconsistent with cost causation principles because these loads will be required to pay a 
rate equivalent to customers receiving a higher level of service.  Geronimo Power asserts 
that non-firm transmission service should be, and often is, priced lower than firm 
transmission service, such as in PJM where Non-Firm PTPS customers receive a discount 
as compared to Firm PTPS customers.  Geronimo Power adds that the proposed rate 
would undermine the incentive for large load customers to reduce their reliance on the 
grid and therefore would fail to offer a rate that would encourage the efficient use of the 
transmission system, contrary to the December Order.  Further, Geronimo Power states 
that Indicated TOs should not set an unjust and unreasonable rate based on superior 
services while they wait until they gather more data to determine the extent to which such 
unjust and unreasonable rate should be reduced when charging for an inferior service.   
 ODEC agrees that it is reasonable for PJM to charge FCD and NFCD transmission 
service customers for applicable PJM administrative charges consistent with PJM’s 
charges to existing transmission customers.848   
 ODEC urges the Commission to direct further compliance filings in order to 
ensure that rates for the new FCD transmission service are just and reasonable by 
requiring the individual transmission owners to either confirm that their formula or stated 
rates and metrics reporting enable direct crediting by PJM, or provide whatever revisions 
are necessary in order to do so.849  ODEC states that this is important so that ODEC and 
other Network Customers are not subject to paying duplicative charges for the same 
revenue requirement amount.  ODEC adds that it is also important because Indicated TOs 
state that load-serving entities will submit metrics to PJM used to calculate transmission, 
capacity, and energy charges, but such metrics may not be consistent among Indicated 
TOs.  ODEC explains that, while it is a load-serving entity, as a transmission customer 
the metrics are provided to PJM by the transmission owners for the zones where ODEC 
takes transmission service. 
 Constellation seeks clarification that Indicated TOs’ proposed rate for FCD 
transmission service is equal to the applicable transmission owners’ NITS rate calculated 
 
847 Geronimo Power Response Brief at 4, 6, 7-9. 
848 ODEC Response Brief at 8; see also NOVEC Response Brief at 8. 
849 ODEC Response Brief at 8-9.

Docket No. EL25-49-002, et al. 
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using that transmission owners’ coincident peak methodology, given that different 
transmission owners use different methods.850 
 Industrials/Amtrak argue that the Commission must ensure that transmission 
owners’ calculation of individual customer and zonal transmission cost allocation is 
transparent, whether through an Attachment M-2 filing or another publicly transparent 
and accountable method.851  Industrials/Amtrak also contend that the Commission must 
provide direction on how the revenue and the billing determinants for FCD and NFCD 
transmission services and Interim NITS would be incorporated into existing transmission 
formula rates.  Similarly, Geronimo Power states that the Commission should at a 
minimum require the Indicated Transmission Owners to clarify the nature of the rates and 
billing determinants that they are proposing, including whether they intend to charge the 
NFCD transmission service charge on a MWh basis, which would be inconsistent both 
with how transmission reservation charges are historically structured and the Tariff.852   
 Industrials/Amtrak argue that neither FCD nor NFCD transmission service provide 
a cost-based back-up service for cogeneration QFs and similarly-situated retail 
customers.853  Industrials/Amtrak contend that, because it would require payment for 
service based on the contracted amount, FCD transmission service inherently assumes 
that forced outages or other reductions in electric output by all QFs will occur 
simultaneously, or during the system peak, or both, without any factual data to support 
that assumption.854  Industrials/Amtrak aver that this is not a realistic assumption for 
cogeneration QFs.  Industrials/Amtrak further argue that it would not comport with cost 
causation principles to require a FCD transmission service reservation for occasional 
back-up power needs, particularly where the history and risk of the individual unit is 
well-established or has met outside standards.  Industrials/Amtrak further argue that 
NFCD transmission service also falls short because it requires pre-scheduling with and 
approval by PJM, which is inconsistent with back-up power’s use in the event of forced 
outages, and because it is an as-available product that is subject to interruption.855  
Industrials/Amtrak argue that, if the existing netting construct is no longer available, then 
a firm transmission service must be available for QFs to meet the requirements of 
 
850 Constellation Response Brief at 31. 
851 Industrials/Amtrak Response Brief at 25-26. 
852 Geronimo Power Response Brief at 5 n.13. 
853 Industrials/Amtrak Response Brief at 16-19. 
854 Id. at 17 (citing Dauphinais Aff. ¶ 44). 
855 Id. at 18.

Docket No. EL25-49-002, et al. 
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PURPA based on actual use.  Industrials/Amtrak contend that there must be a 
transmission service that applies cost causation standards to occasional, unplanned use of 
the transmission system.   
 Industrials/Amtrak argue that cost causation principles dictate that the 
Commission should authorize cost-based back-up service for all transmission customers, 
not only QFs.856  Industrials/Amtrak explain that there are a number of facilities that 
operate on similar principles to QFs but do not maintain QF status for a variety of 
reasons.  Industrials/Amtrak argue that these facilities, too, must occasionally draw from 
the grid, including for occasional unscheduled outages.  Industrials/Amtrak argue that it 
cannot be just and reasonable or comport with cost causation principles to require 
facilities requiring only occasional back-up service to pay rates that are the same as FCD 
transmission service or gross-based NITS.  Industrials/Amtrak argue that transmission 
customers should be charged based on actual use on an hourly basis and should not be 
charged a standby fee.    
 Industrials/Amtrak explain that QFs are entitled to supplementary power, back-up 
power, maintenance power, and interruptible power pursuant to Commission 
regulations857 and that the rates for back-up power “[s]hall not be based upon an 
assumption (unless supported by factual data) that forced outages or other reductions in 
electric output by all [QFs] on an electric utility’s system will occur simultaneously, or 
during the system peak, or both.”858  Industrials/Amtrak argue the NITS BTMG netting 
construct meets the requirements of PURPA’s enacting regulations.  
c. 
Reply Briefs 
 In response to Constellation’s request for clarification, Indicated TOs clarify that 
the zonal FCD transmission service rate will be calculated using that transmission 
owner’s specific methodology applicable to Network Customers.859 
 NOVEC explains that because under PJM’s proposal a transmission customer 
would only take and pay for NFCD transmission service when the generator was 
experiencing an outage, the same rate does not equate to the same cost to the customer.860  
 
856 Id. at 20-22, 24. 
857 Industrials/Amtrak Response Brief at 14-16 (citing 18 C.F.R. § 292.305(b)). 
858 Id. at 15 (citing 18 C.F.R. § 292.305(c)(1)). 
859 Indicated TOs Reply Brief at 18 (citing Constellation Response Brief at 31). 
860 NOVEC Reply Brief at 10-13.

Docket No. EL25-49-002, et al. 
- 185 - 
NOVEC argues that NFCD transmission service does not impose fewer costs on the 
transmission system than NITS, just “imposes costs differently” and contends that the 
Commission needs to be cautious to avoid providing “co-located generators a subsidized 
low cost option to use the system whenever they need backup.”861  NOVEC argues that 
Co-Located Load in areas where PJM can accommodate a large amount of NFCD 
transmission service could end up with the best of both worlds, where they are very rarely 
curtailed but pay a subsidized rate for transmission service, with the option to switch 
from FCD transmission service or NITS if PJM can no longer accommodate the required 
level of NFCD transmission service.  
 In response to arguments from Joint Co-Location Developers and Geronimo 
Power about whether it is appropriate to establish NFCD transmission service rates based 
on FCD transmission service rates, Indicated TOs argue that transmission owners need to 
gather data on how NFCD transmission service customers are using the service and the 
effect of that utilization on the transmission system.862  Indicated TOs argue that it is not 
clear whether NFCD transmission service customers will cause the need for fewer 
Network Upgrades, and that further analysis is needed to determine whether discounts are 
appropriate.  Finally, Indicated TOs contend that Joint Co-Location Developers’ concerns 
that the proposed NFCD transmission service rate will discourage industrial development 
are exaggerated and misplaced.  NOVEC similarly argues that it is not the Commission’s 
place to subsidize certain industries at the expense of customers.863 
 In response to Vistra’s arguments about applying the rate for zonal Non-Firm 
PTPS to NFCD transmission service, Indicated TOs argue that doing so would be 
unreasonable because transmission customers have used Non-Firm PTPS exclusively to 
facilitate the delivery of specific generation to the PJM border—not for internal use.864  
NOVEC also rejects Vistra’s argument that NFCD transmission service should receive 
the same rate as Non-Firm PTPS, arguing that it would not be appropriate to allow NFCD 
transmission service the same discount as Non-Firm PTPS because the two products 
fundamentally differ.  Indicated TOs further argue that the discounted Non-Firm PTPS 
rate reflects historical use and was neither intended nor appropriate for NFCD 
transmission service because NFCD transmission service is intended to be a limited, 
supplemental service within PJM and does not facilitate the delivery of specific 
generation to specific load over a contract path.  Indicated TOs also contend that NFCD 
 
861 Id. at 12 (citing Market Monitor Response Brief at 6).  
862 Indicated TOs Reply Brief at 19-21. 
863 NOVEC Reply Brief at 14. 
864 Indicated TOs Reply Brief at 13, 18-19.

Docket No. EL25-49-002, et al. 
- 186 - 
transmission service is superior to Non-Firm PTPS because it has a superior curtailment 
priority. 
 Indicated TOs reject Vistra’s argument that Indicated TOs’ proposal to credit the 
revenues associated with NFCD transmission service to customers taking NITS and FCD 
transmission service will create unjustified cost shifts among customer classes.865  
Indicated TOs argue that these revenue credits are not subsidies but offsets that reduce 
the amount paid by firm transmission service customers, which is appropriate because 
transmission rates are designed to recover the fixed costs of building and maintaining the 
transmission system to provide service to such customers.  In the absence of such credits, 
Indicated TOs argue that the transmission owners would over-recover their revenue 
requirements.  Indicated TOs further argue that the revenue crediting mechanism is fully 
consistent with previously approved mechanisms such as section 27A, which credits 
Non-Firm PTPS revenue to Network and Firm PTPS customers.   
 Industrials/Amtrak argue that NFCD transmission service cannot provide back-up 
power because it cannot be accessed during a BTMG generation facility outage until a 
request for it is submitted to and approved by PJM.866  Industrials/Amtrak further argue 
that NFCD transmission service is also only available on an as-available basis and is 
subject to both operational and automated interruption.867  Industrials/Amtrak explain 
that, during a forced outage, a retail customer would be required to automatically curtail 
load until it submits a NFCD transmission service request and PJM approves that request. 
 Industrials/Amtrak also argue that FCD transmission service can provide 
maintenance power on a firm basis, but like back-up power, cannot do so at a cost lower 
than gross load NITS because it implicitly assumes BTMG maintenance outages cannot 
be scheduled to avoid peak periods.868 
d. 
Answer 
 Geronimo Power argues that Indicated TOs’ proposed rate for NFCD transmission 
service is unjust and unreasonable, will disincentivize Co-Located Loads from relying on 
NFCD transmission service, and lead to less efficient use of the transmission system.869  
 
865 Id. at 31-32 (citing Vistra Response Brief at 23-25). 
866 Industrials/Amtrak Reply Brief at 8. 
867 Id. at 8 n.13. 
868 Id. at 9 n.16. 
869 Geronimo Power May 21 Answer at 8.

Docket No. EL25-49-002, et al. 
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Geronimo Power asserts that Indicated TOs offer no meaningful response to the question 
of what is a just and reasonable rate for NFCD transmission service.  Geronimo Power 
argues that the mere fact that Commission policy allows PJM transmission owners to 
charge up to the firm rate in some cases does not mean that doing so here is just and 
reasonable.870  Geronimo Power avers that there should be little doubt that some form of 
discount must be applied as to NFCD transmission service. 
e. 
Determination 
 We agree with Indicated TOs that it is just and reasonable to base the rate for FCD 
transmission service on the zonal NITS rates and underlying NITS revenue 
requirements871 and direct the PJM transmission owners, as the replacement rate, to 
submit a compliance filing within 60 days of the date of issuance of this order that 
includes Tariff revisions to effectuate this proposal.  Both FCD transmission service and 
NITS will provide a similar level of firm transmission service, and PJM will plan the 
transmission system to ensure that it is able to provide both transmission services on a 
firm basis.872   
 We find unjust and unreasonable PJM’s proposal to charge Eligible Customers 
taking FCD or NFCD transmission services on behalf of Co-Located Loads for all 
ancillary services other than regulation and black start based on total quantity of MWhs 
of energy delivered to the Co-Located Load.873  In the December Order, the Commission 
found that Eligible Customers taking the new FCD transmission service on behalf of              
Co-Located Loads must be charged for ancillary services based on the contract demand, 
with the exception of regulation and black start services.874  Similarly, the Commission 
found that Eligible Customers taking the NFCD transmission service on behalf of                
Co-Located Loads must be charged for ancillary services on an as-reserved contract 
demand basis, based on the reserved contract demand amount of transmission service, 
with the exception of regulation and black start services.875   
 
870 Id. at 9. 
871 Indicated TOs Initial Brief at 6. 
872 Id. at 8-9; December Order, 193 FERC ¶ 61,217 at PP 195, 208. 
873 PJM, Initial Brief, attach. A, Subpart B, §§ 714.5 & 715.4. 
874 December Order, 193 FERC ¶ 61,217 at P 209. 
875 Id. P 216.

Docket No. EL25-49-002, et al. 
- 188 - 
 However, we find just and reasonable PJM’s proposal to charge Eligible 
Customers taking FCD and NFCD transmission services on behalf of Co-Located Loads 
for regulation and black start services based on gross demand, which is consistent with 
the Commission’s findings in the December Order.  The Commission found in the 
December Order that “Eligible Customers that take the Firm Contract Demand 
transmission service on behalf of Co-Located Loads must be charged for regulation and 
black start services based on a gross demand basis, rather than the contract demand” 
because all Co-Located Loads rely on regulation and black start services to be served 
regardless of whether they are withdrawing energy from the transmission system.876  
Likewise, the Commission found in the December Order that “Eligible Customers that 
take the Non-Firm Contract Demand transmission service on behalf of Co-Located Loads 
use and therefore should be charged for regulation and black start services based on a 
gross demand basis, rather than the reserved amount of transmission service.”877  
Therefore, and consistent with our determination above to extend the three new 
transmission services set forth in the December Order to Eligible Customers taking 
service on behalf of load with BTMG that are willing and able to limit their energy 
withdrawals from the transmission system under certain conditions, we direct PJM to 
submit a compliance filing within 60 days of the date of issuance of this order that revises 
its Tariff to:  (1) charge Eligible Customers taking FCD and/or NFCD transmission 
services on behalf of Eligible Loads for all ancillary services other than regulation and 
black start services based on their contract demand; and (2) charge Eligible Customers 
taking FCD and/or NFCD transmission services on behalf of Eligible Loads for 
regulation and black start services based on their gross load.        
 We also find just and reasonable PJM’s proposal to charge Eligible Customers 
taking FCD and/or NFCD transmission services certain administrative charges.  As PJM 
explains, these are standard charges associated with use of the transmission system above 
transmission service rates.878  For the same reason, we find just and reasonable PJM’s 
proposal to charge Eligible Customers taking FCD and/or NFCD transmission services 
redispatch costs to cover congestion-related costs, given that both of these services will 
be pool-scheduled and can be served by generators redispatched to mitigate congested 
transmission paths.  We thus direct PJM to submit a compliance filing, within 60 days of 
the date of issuance of this order, that revises its Tariff to implement these charges.  
Consistent with our determination above to extend the three new transmission services set 
forth in the December Order to Eligible Customers taking service on behalf of load with 
BTMG that are willing and able to limit their energy withdrawals from the transmission 
 
876 Id. P 209. 
877 Id. P 216.  
878 PJM Initial Brief at 27.

Docket No. EL25-49-002, et al. 
- 189 - 
system under certain conditions, we further direct PJM to reflect this change in its 
compliance filing. 
 However, we are not persuaded that Indicated TOs’ proposal to set the maximum 
rate for NFCD transmission service equal to the rate for FCD transmission service is just 
and reasonable.  In the December Order, the Commission was clear that NFCD 
transmission service would “provide an option for Eligible Customers seeking to use the 
transmission system on behalf of a Co-Located Load in this more limited manner.”879  
Further, NFCD transmission service is non-firm and curtailed prior to FCD transmission 
service and NITS.880  NFCD transmission service is therefore an inferior service to FCD 
transmission service and NITS, and we find that the just and reasonable replacement rate 
here should not charge the same maximum rate for these transmission services.  We 
acknowledge NOVEC’s argument that under PJM’s proposal, an Eligible Customer 
would only take and pay for NFCD transmission service when the generator serving it is 
experiencing an outage, so the same rate does not equate to the same cost to the Eligible 
Customer.881  However, the same rate could apply to Eligible Customers taking the same 
amount of FCD and NFCD transmission services.   
  We also find that charging the same maximum rate for both FCD and NFCD 
transmission services can undermine the benefits of the new NFCD transmission service 
for other transmission customers.  Specifically, discounting non-firm transmission 
services encourages transmission customers to use such services, which benefits all 
transmission customers by maximizing use of the existing transmission system.  These 
benefits accrue to other transmission customers in two ways.  First, the revenues related 
to NFCD transmission service will become a credit to, and thus offset, the transmission 
revenue requirement, which is the basis for the rates that firm transmission customers are 
charged.  Moreover, utilizing NFCD transmission service can avoid unnecessary Network 
Upgrades, the costs of which would likely be allocated to all firm transmission service 
customers.   
 Further, pricing NFCD transmission service at the same rate as FCD transmission 
service is not consistent with cost causation principles or the December Order’s findings.  
Specifically, the Commission found that requiring an Eligible Customer taking 
transmission service on behalf of Co-Located Load to take NITS on a gross demand basis 
would be inefficient, and could necessitate costly transmission buildout and costs paid by 
transmission customers that may not be necessary if Eligible Customers taking 
transmission service on behalf of Co-Located Loads are willing and able to limit their 
 
879 December Order, 193 FERC ¶ 61,217 at P 214 (emphasis added). 
880 See infra Part VI.G. 
881 NOVEC Reply Brief at 10.

Docket No. EL25-49-002, et al. 
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energy withdrawals from the transmission system under certain conditions and take a 
transmission service that requires fewer or less costly Network Upgrades to provide.882  
As noted above, the Commission directed the creation of NFCD transmission service, 
finding that it would provide an option for Eligible Customers taking service on behalf of 
Co-Located Loads that seek to use the transmission system in a more limited manner.883  
The December Order further found that Eligible Customers taking service on behalf of 
Co-Located Loads should be allowed to choose the transmission service that aligns with 
their use of the transmission system and therefore aligns the charges for service with the 
benefits received.884  Indicated TOs’ proposal fails to comply with the directive in the 
December Order by charging the same rate for FCD and NFCD transmission services; the 
proposal does not align the charges for transmission service with the benefits received. 
 Our finding here is also consistent with Commission precedent.  In Order No. 888, 
the Commission determined that the rate for Non-Firm PTPS “is capped at the firm 
rate.”885  In response to Order No. 888, Duquesne sought clarification that the phrase “the 
non-firm rate is capped at the firm rate” does not mean the Commission is deviating from 
its principles that non-firm transmission service must be priced in a manner that reflects 
the interruptibility of the service and is economically efficient.886  The Commission 
clarified that the Firm PTPS transmission rate represents a maximum price for non-firm 
transmission service and emphasized that “non-firm transmission prices should reflect the 
interruptibility of the service and should promote efficient use of the transmission system, 
subject to this price cap.”887  The Commission concluded that, “while in some 
circumstances non-firm transmission rates may be set at a firm transmission rate level, 
the Commission expects that non-firm transmission rates would, in most instances, be 
priced below the cap.”888 
 Thus, while the Commission recognized that the Firm PTPS transmission rate 
could be a ceiling for the Non-Firm PTPS rate, the Commission also recognized that the 
rates should vary based on the quality of the transmission service.  Our finding here is 
 
882 December Order, 193 FERC ¶ 61,217 at P 199. 
883 Id. P 214. 
884 Id. P 199. 
885 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,743. 
886 Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,272. 
887 Id. 
888 Id.

Docket No. EL25-49-002, et al. 
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consistent with Order No. 888 (i.e., that non-firm transmission service rates should 
generally be priced below firm transmission service rates).  Indicated TOs propose 
making the exception the rule and thus fail to justify that deviation.  Indicated TOs argue 
that NFCD transmission service is a superior level of service compared to Non-Firm 
PTPS.  But, even assuming that statement is correct, it does not follow that NFCD 
transmission service is therefore a similar level of service as FCD transmission service or 
NITS. 
 We recognize that Indicated TOs state that they will consider offering discounts 
for NFCD transmission service after an initial assessment period to determine whether a 
discount would encourage efficient use of the transmission system.  However, Indicated 
TOs miss the point of not only aligning the rate with the quality of the service provided, 
but also designing a rate that incentivizes efficient non-firm uses of the transmission 
system.  It is counterintuitive to expect charging the full rate to inform an analysis of 
what discounts may be appropriate.  Therefore, we find that the possibility of offering 
discounts at some undefined time in the future is not sufficient to remedy our concerns 
with their proposal.  Under that proposal, Indicated TOs would have no obligation to 
lower rates in the future and offer no transparency as to how or when that decision would 
be made; moreover, they provide no compelling explanation as to why it would be just 
and reasonable to charge for NFCD transmission service at the FCD transmission service 
rate in the interim. 
 We further disagree with NOVEC’s characterization of a lower rate for NFCD 
transmission service as subsidized; as discussed in the body of this order, we find that a 
lower rate for NFCD transmission service is just and reasonable and consistent with cost 
causation.  A lower rate for NFCD, as compared to FCD, transmission service will also, 
as NOVEC points out, incentivize transmission customers to use the service in areas 
where PJM can accommodate a large amount of NFCD transmission service.  This is 
exactly the point–Eligible Customers taking transmission service on behalf of Eligible 
Loads will be incentivized to take NFCD transmission service in areas where there is 
excess transmission capacity, and the charges recouped from those customers will offset 
the rates paid by firm transmission customers that funded the excess transmission 
capacity.  Otherwise, this transmission capacity would remain unused and firm 
transmission customers would pay more. 
 NOVEC also argues that in areas where PJM can accommodate a large amount of 
NFCD transmission service, Co-Located Load could end up with the best of both worlds, 
where they are rarely curtailed but Eligible Customers taking transmission service on 
their behalf pay a subsidized rate for transmission service, with the option to switch to 
FCD transmission service or NITS if PJM can no longer accommodate the required level

Docket No. EL25-49-002, et al. 
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of NFCD transmission service.889  We disagree that Eligible Customers could “simply 
switch” to FCD transmission service or NITS if PJM can no longer accommodate the 
requested level of NFCD transmission service.890  The process to request NITS remains 
unchanged, and we address the process to request FCD transmission service above.  But 
in either case, provision of firm transmission service will be studied, granted to the extent 
it can be done so reliably, and only available following construction of any required 
Network Upgrades.   
 With respect to Industrials/Amtrak’s argument that neither FCD nor NFCD 
transmission services provide a cost-based back-up service for cogeneration QFs and 
similarly-situated retail customers,891 this argument is substantively similar to the 
argument the same parties raised on compliance, which is addressed supra.892  
Industrials/Amtrak contend that, because it would require payment for service based on 
the contracted amount, FCD transmission service inherently assumes that forced outages 
or other reductions in electric output by all QFs will occur simultaneously, or during the 
system peak, or both, without any factual data to support that assumption.893  However, 
as noted above, this argument appears to conflate rates for sales of back-up power and 
rates for transmission service, rendering Industrials’/Amtrak’s concerns misplaced.   
 Industrials/Amtrak further argue that it would not comport with cost causation 
principles to require a FCD transmission service reservation for occasional back-up 
power needs and that NFCD transmission service will not be useful for back-up power 
because it must be requested in advance.894  Again, Industrials/Amtrak appear to conflate 
back-up power for QFs under PURPA with the subject of this proceeding, which is 
transmission service taken by Eligible Customers serving Eligible Loads.  Further, 
Industrials/Amtrak state that their concerns are for “whether retail customers can access 
cost-based . . . back-up service”895 but, with the exception of Eligible Customers that are 
retail customers taking unbundled transmission service, service available to retail 
customers is neither the subject of this proceeding nor within the Commission’s 
 
889 NOVEC Reply Brief at 12-13. 
890 Id.  
891 Industrials/Amtrak Response Brief at 16-17. 
892 See supra Part V.A.3. 
893 Industrials/Amtrak Response Brief at 17 (citing Dauphinais Aff. ¶ 44). 
894 Id. at 18. 
895 Id. at 11 (emphasis added).

Docket No. EL25-49-002, et al. 
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jurisdiction.  However, to the extent Industrials/Amtrak refer to jurisdictional wholesale 
transmission service when arguing that “examples exist of bespoke arrangements for 
industrial and institutional customers that may require firm back-up needs,”896 we 
continue to find it just and reasonable that Eligible Customers taking NITS be charged on 
a gross demand basis as explained in the December Order, with limited exceptions.897  
Network Load has the right to be served from the transmission system at any time, and 
PJM and the transmission owners incorporate Network Load into their transmission 
planning to ensure that they can fulfill their obligation to provide such service.  Thus, 
regardless of whether certain transmission customers that elect NITS to be able to take 
transmission service on demand choose to only take such service occasionally, the system 
will be planned to accommodate them at all times.  We therefore continue to find that the 
benefits of NITS align with charging for NITS based on gross demand.  We further 
reiterate that, as discussed in this order, we have set aside, in part, the December Order to 
extend the three new transmission services set forth in the December Order to Eligible 
Customers taking service on behalf of load with BTMG that are willing and able to limit 
their energy withdrawals from the transmission system under certain conditions.898   
 Therefore, we direct the PJM transmission owners to submit, within 60 days of the 
date of issuance of this order, a compliance filing with the Tariff charges for NFCD 
transmission service in accordance with this order.  Specifically, the PJM transmission 
owners must propose a lower maximum rate or non-discriminatory discounts for the 
NFCD transmission service rate.  Moreover, the PJM transmission owners must ensure 
that their proposed Tariff revisions are transparent as to how charges will be calculated 
for an individual transmission customer.  Consistent with our determination above to 
extend the three new transmission services set forth in the December Order to Eligible 
Customers taking service on behalf of load with BTMG that are willing and able to limit 
their energy withdrawals from the transmission system under certain conditions, we 
further direct the PJM transmission owners to reflect this change in their compliance 
filing.   
5. 
Other  
a. 
Initial Briefs 
 PJM states that any request for FCD and/or NFCD transmission service must 
comply with Commission regulations for new service requests, and include several items 
specific to these transmission services, such as a description of the supply characteristics 
 
896 Id. at 12. 
897 December Order, 193 FERC ¶ 61,217 at PP 186, 195. 
898 See supra Part IV.C.1.b.i.

Docket No. EL25-49-002, et al. 
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of the Co-Located Generator and the demand characteristics of the Co-Located Load.899  
Upon receiving an application, PJM will evaluate whether the requested level of Contract 
Demand transmission service can be reliably provided.  PJM then explains that the 
Eligible Customer must meet several conditions precedent, such as certifying that it is 
willing and able to limit withdrawals from the transmission system when requested by 
PJM and providing PJM with an authorization or certification from its Relevant Electric 
Retail Regulatory Authority (RERRA) affirming that the Eligible Customer is authorized 
to provide energy to the Co-Located Load.  PJM also proposes to require that certain 
facilities and necessary technical arrangements must be completed prior to 
commencement of requested service. 
 PJM next explains that, under the Service Agreement for Contract Demand 
transmission service, service is presumed to continue without expiration, and that there 
are several bases for termination.900  For example, PJM explains that service can 
terminate on 42 months’ notice prior to the commencement of a delivery year, and PJM 
argues that this is appropriate because the contract demand level under FCD transmission 
service will be accounted for in PJM’s capacity market.  PJM proposes circumstances 
whereby PJM may terminate service for cause:  (1) the Eligible Customer breaches its 
obligations, such as materially changing the Co-Location Arrangement without PJM 
studying it; or (2) the Eligible Customer is disqualified by failing to follow an operating 
instruction to curtail or shed load, or after the misoperation, on more than one occasion, 
of any necessary control technologies or required protection systems (described further 
below).  
 PJM next proposes that the Eligible Customer designate the Co-Located Load and 
the Co-Located Generator and provide the MW level of energy from the Co-Located 
Generator dedicated to serving the Co-Located Load.901  For reliability purposes, PJM 
states, the Eligible Customer must provide PJM with timely written or electronic notice 
of material changes in the demand characteristics of the Co-Located Load or the supply 
characteristics of the Co-Located Generator.  PJM maintains that necessary control 
technologies and protection systems for NFCD transmission service will be designed 
based on the specific circumstances of each Co-Location Arrangement, and PJM’s ability 
to reliably operate the system could be impaired by any material changes to the control 
technologies or protection systems.  PJM proposes to prohibit an Eligible Customer from 
using FCD transmission service for the sale of either capacity or energy to loads other 
 
899 PJM Initial Brief at 17-19. 
900 Id. at 20-22. 
901 Id. at 22-24.

Docket No. EL25-49-002, et al. 
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than the Co-Located Load designated in its Service Agreement or the transmission 
service to third parties.  
b. 
Response Briefs 
 ODEC requests clarification regarding how PJM’s requirement that an Eligible 
Customer taking transmission service on behalf of a Co-Located Load provide PJM with 
an authorization or certification from its RERRA which affirms that the Eligible 
Customer is authorized to provide energy to the Co-Located Load would apply to a 
generation and transmission electric cooperative like ODEC.902  ODEC states that it is 
unclear whether PJM intends that ODEC, as an Eligible Customer, would need to provide 
certification that ODEC’s member distribution cooperatives (which are the RERRA in 
Maryland and Delaware) have authorized ODEC to provide energy to the Co-Located 
Load.  ODEC adds that, where the state regulatory agency is the RERRA, ODEC is 
unaware of a procedure whereby it would obtain authorization from the Virginia State 
Corporation Commission to provide energy to Co-Located Loads.  
 Constellation opposes PJM’s proposal that the Eligible Customer must submit an 
authorization or certification from the RERRA affirming that the Eligible Customer is 
authorized to provide energy to the Co-Located Load.903  Constellation argues that, if the 
generator is the Eligible Customer, it is unreasonable to require that generator to go to the 
state commission for a special approval if the load is in a retail competition state.  
Constellation maintains that the Eligible Customer need only show that the load will be 
served by a transmission owner or licensed competitive retail supplier. 
 Industrials/Amtrak argue that Co-Located Load on whose behalf an Eligible 
Customer takes NFCD transmission service should have firm natural gas capacity or 
other adequate alternatives to be able to utilize the service.  Industrials/Amtrak argue this 
requirement will prevent “misuse” of NFCD transmission service “by generators who 
have the ability to operate but may want to rely on the grid when it appears to be more 
economical for that generator.”904  Industrials/Amtrak explain that, from a resource 
adequacy perspective, policies surrounding NFCD transmission service should encourage 
loads to bring their own generation. 
 Indicated TOs request that PJM add to section 710.1 of PJM’s illustrative tariff 
provisions, as a condition precedent for receiving FCD or NFCD transmission service, a 
requirement that the Eligible Customer satisfy any load-connection related requirements 
 
902 ODEC Response Brief at 6-7. 
903 Constellation Response Brief at 29. 
904 Industrials/Amtrak Response Brief at 24.

Docket No. EL25-49-002, et al. 
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imposed by the applicable PJM transmission owner.905  Indicated TOs argue that PJM 
should add language to the list of information in section 710.2 of PJM’s illustrative tariff 
provisions to be provided in an application for FCD and/or NFCD transmission service to 
the effect that the customer has met applicable load interconnection study obligations.  
Indicated TOs request that PJM add a placeholder section for listing required control 
technologies or protection systems to section 5.0 of PJM’s proposed Attachment F-4.906   
 Indicated TOs request that PJM clarify whether the use of “Delivery Point” in 
section 710.2 subsection (iii) and subclause (i) of section 710.5 is appropriate in light of 
PJM’s proposed definition of Co-Located Load, which is based on facilities located on 
the same side of the Point of Change in Ownership.907   
 Indicated TOs contend that PJM should clarify in section 711.3 of PJM’s 
illustrative tariff provisions or in PJM’s manuals what constitutes “material changes” for 
purposes of the annual information updates to be provided by Eligible Customers.908  
Indicated TOs argue that PJM should revise section 712.2 of PJM’s illustrative tariff 
provisions to require PJM to notify the affected PJM transmission owner(s) of any 
request for NFCD transmission service.  Indicated TOs argue that PJM should revise 
section 713 of PJM’s illustrative tariff provisions to require that notice of any curtailment 
be provided not only to the Eligible Customer but also to the affected PJM transmission 
owner or Electric Distribution Company.  
 Constellation recommends that, for Eligible Customers requesting transmission 
service on behalf of Co-Located Load, if the customer facilities include an existing 
generator, a certification be required that the existing generator supports the transmission 
service request.909  Constellation argues that this requirement would ensure the                      
Co-Located Load is physically connected to the facilities of the existing or planned 
Customer Facility.  Alliance promotes their framework for looking at how to responsibly 
enable large-load integration while preserving reliability, cost causation, and 
affordability.910  
 
905 Indicated TOs Response Brief at 18. 
906 Id. at 19, 24. 
907 Id. at 18-19 n.41. 
908 Id. at 20-22. 
909 Constellation Response Brief at 30. 
910 Alliance Response Brief at 2.

Docket No. EL25-49-002, et al. 
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c. 
Reply Briefs 
 In response to parties’ comments, particularly those of Indicated TOs, PJM 
proposes certain revisions to its illustrative tariff language for FCD and NFCD 
transmission services.911  Specifically, PJM notes that it proposes revisions to                 
section 711.3 to provide that the applicable transmission owner will be notified of 
material changes to Co-Located Arrangements, as well as a reference to the PJM manuals 
for further description of what would constitute a material change.  PJM further proposes 
changes to section 713.1 to provide that PJM will notify the applicable transmission 
owners of any instruction to curtail Co-Located Load.  
 Constellation urges the Commission to deny Indicated TOs’ proposal to replace 
“Delivery Point” with “Point of Change in Ownership” in PJM’s requirements for 
applications for FCD and NFCD transmission services because it would risk uncertainty 
or delays for parties in Co-Location Arrangements.912  Constellation asserts that the 
Tariff should use “Point of Interconnection,” consistent with the definition of Co-Located 
Load. 
 Since filing its initial brief, PJM states that it has determined that changes to 
Auction Revenue Rights rules must be modified to recognize that FCD transmission 
service customers will contribute towards enhancing and maintaining the transmission 
system and should have the right to request Auction Revenue Rights.913  To effectuate 
this modification, PJM proposes a revision to Operating Agreement, Schedule 1,              
section 7.4.2(d) and includes a new Operating Agreement, Schedule 1, section 7.4.2(l) to 
detail the Auction Revenue Rights rules specific to Eligible Customers taking FCD 
transmission service.914 
d. 
Determination 
 We disagree with PJM that it is just and reasonable for the replacement rate to 
require Eligible Customers requesting FCD or NFCD transmission service to provide an 
authorization or certification from its RERRA affirming that the Eligible Customer is 
authorized to provide energy to the Co-Located Load.915  PJM does not provide any 
 
911 PJM Reply Brief at 62-63. 
912 Constellation Reply Brief at 9 (citing Indicated TOs Response Brief at 19). 
913 PJM Reply Brief at 65. 
914 Id. at 65-66. 
915 PJM Initial Brief at 18-19.

Docket No. EL25-49-002, et al. 
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explanation or context for proposing this requirement, and it is not clear why an Eligible 
Customer would need to go through this extra step under the Tariff to prove it is 
authorized to serve load.  If an Eligible Customer that is not authorized to provide energy 
to load attempts to do so, that would be a matter for the RERRA’s enforcement 
mechanisms. 
 We similarly disagree with Constellation that it is necessary to require Eligible 
Customers requesting FCD or NFCD transmission service on behalf of Co-Located Load 
to include a certification from the Co-Located Generator, if it is an existing generator, to 
ensure that the Co-Located Load is physically connected to the generator’s facilities.  The 
Commission already made clear that Co-Located Load must be “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.”916  If 
an Eligible Customer attempts to request FCD or NFCD transmission service on behalf of 
a load that did not meet the definition of Co-Located Load, that should be referred to the 
Commission’s Office of Enforcement and Regulatory Accounting. 
 Industrials/Amtrak argue that Co-Located Load on whose behalf an Eligible 
Customer takes NFCD transmission service should have firm natural gas capacity or 
other adequate alternatives to be able to utilize the service.917  Industrials/Amtrak explain 
that such a requirement would “avoid misuse of the [NFCD transmission] service by 
generators who have the ability to operate but may want to rely on the grid when it 
appears to be more economical for that generator.”  The December Order contained no 
such limitation and Industrials/Amtrak have failed to justify adding it here.  Specifically, 
the December Order stated that NFCD transmission service would reflect Eligible 
Customers taking service on behalf of Co-Located Loads that may not “necessarily plan 
to withdraw energy from the transmission system on a regular basis” but “still seek to 
withdraw energy from the transmission system from time to time when transmission 
capacity is available and not needed by firm customers.”918  The December Order thus 
contemplates that NFCD transmission service would be an option for Eligible Customers 
taking transmission service on behalf of Co-Located Load, not a mandate. 
 Indicated TOs request that the Commission direct as part of the replacement rate 
requirements related to Eligible Customers satisfying requirements related to load 
 
916 December Order, 193 FERC ¶ 61,217 at P 1 & n.3; February Order, 190 FERC 
¶ 61,115 at P 3 & n.4. 
917 Industrials/Amtrak Response Brief at 24. 
918 December Order, 193 FERC ¶ 61,217 at P 214.

Docket No. EL25-49-002, et al. 
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interconnections.919  Indicated TOs have not explained why these requirements are 
necessary, and so we decline to make them a part of the replacement rate at this time.  
However, we agree with Indicated TOs’ request that PJM add a placeholder section for 
listing necessary control technologies and/or protection systems to section 5.0 of PJM’s 
proposed Attachment F-4.  
 We also find PJM’s proposal to allow FCD transmission service customers to 
request Auction Revenue Rights in stage 2 of the allocation process to be just and 
reasonable.  Given the underlying design of the FCD transmission service, we find the 
presumption that FCD transmission service customers contribute towards enhancing and 
maintaining the transmission system on par with other Firm PTPS transmission 
customers to be reasonable.  PJM’s proposal provides FCD transmission service 
customers an equivalent opportunity to request Auction Revenue Rights.  We direct PJM 
to submit a compliance filing within 60 days of the date of issuance of this order to revise 
its Tariff consistent with this replacement rate.  Consistent with our determination above 
to extend the three new transmission services set forth in the December Order to Eligible 
Customers taking service on behalf of load with BTMG that are willing and able to limit 
their energy withdrawals from the transmission system under certain conditions, we 
further direct PJM to reflect this change in its compliance filing. 
B. 
Additional Charge for Eligible Customers Taking FCD and/or NFCD 
Transmission Service 
1. 
December Order 
 As part of the paper hearing, the Commission asked the parties:  
Should the rate paid by an Eligible Customer on behalf of a 
Co-Located Load taking only the new Non-Firm Contract 
Demand transmission service that elects to not reserve any 
amount of that service for a period of time (e.g., one month) 
reflect not only charges for regulation and black start 
services, but also an additional charge given that regulation 
and black start services could not be provided without the 
transmission system?  If so, how should that additional charge 
be determined? 
 In addition, the Commission asked:  
Should the rate paid by an Eligible Customer on behalf of a 
Co-Located Load taking only a de minimis amount of the new 
 
919 Indicated TOs Response Brief at 18-19.

Docket No. EL25-49-002, et al. 
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Firm or Non-Firm Contract Demand transmission services 
reflect not only (i) charges for regulation and black start 
service and (ii) the transmission service charges for that            
de minimis amount of service, but also an additional charge 
reflecting that the Co-Location Arrangement is physically 
connected and synchronized to the PJM transmission system?  
If so, how should that additional charge be determined? 
2. 
Initial Briefs 
 Indicated TOs propose to charge a Grid Reliance Charge to Eligible Customers 
taking FCD or NFCD transmission service based on the difference between either the 
contract amount of FCD transmission service, or the reserved amount of NFCD 
transmission service, and the customer’s gross on-site load.920  Indicated TOs explain that 
the Grid Reliance Charge is designed to reflect the costs of using the transmission system 
to deliver black start and regulation services, as well as the inherent benefit that all 
customers receive through their synchronization to and reliance on the transmission 
system.  Indicated TOs state that the Grid Reliance Charge also recognizes the costs 
associated with the operations, maintenance, and other activities that Indicated TOs will 
need to perform for the transmission system and to accommodate the increased number 
of protection schemes required for Co-Location Arrangements.  Indicated TOs propose to 
calculate this charge for each zone based on an average fixed percentage of the portion of 
transmission depreciation and operations and maintenance expense associated with 
providing grid reliance services, and to apply that percentage to each transmission 
owner’s annual revenue requirement.921  Indicated TOs argue that it is appropriate to use 
annual depreciation and operations and maintenance expenses because these expenses 
best capture the portions of a transmission owner’s revenue requirement relating to the 
ongoing reliable operation of the transmission system.  Indicated TOs propose an initial 
percentage of 25.8%, subject to adjustment every five years.  
 In further justifying the Grid Reliance Charge, Indicated TOs assert that                    
Co-Located Load and its associated Co-Located Generator benefit from the existence and 
reliable operation of the transmission system because they are electrically connected to 
the transmission system, and should contribute to paying the costs of continuing to 
reliably operate the system regardless of the amount of energy withdrawn.  Indicated TOs 
contend that a large Co-Location Arrangement with zero MW of FCD or NFCD 
transmission service still depends on the grid for the delivery of various ancillary services 
and a suite of synchronization support services, such as stable frequency, inertia, stability 
 
920 Indicated TOs Initial Brief at 14. 
921 Id. at 14-16.

Docket No. EL25-49-002, et al. 
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services, fault current capability, and ride-through and protection coordination.  Indicated 
TOs argue that the Commission has long recognized that an integrated transmission 
system provides broad reliability benefits to all customers of the system, and this 
recognition has guided Commission decisions on ratemaking and cost allocation.922 
 Indicated TOs maintain that their proposed methodology for the Grid Reliance 
Charge is a just and reasonable way to estimate with an appropriate level of precision the 
benefits to Co-Located Load from relying on the grid while ensuring this charge can be 
fairly and efficiently implemented.923  Indicated TOs state that they have included 
detailed testimony on the proposed methodology, and they highlight that the allocator is 
based on costs included in transmission plant and transmission operations and 
maintenance FERC accounts.924  Indicated TOs contend that their proposal is 
conservative in a number of respects, for example, they exclude amortization and general 
plant depreciation, as well as administrative and general expenses.  Indicated TOs explain 
that the allocator will be multiplied by each transmission owner’s rate for NITS and FCD 
transmission service, resulting in an “unadjusted” Grid Reliance Charge rate.  Indicated 
TOs further explain that they propose to multiply this unadjusted rate by a ratio that 
accounts for the difference between the demand used to account for the NITS and FCD 
transmission service rate and the gross load for Eligible Customers on behalf of                       
Co-Located Load, resulting in the final Grid Reliance Charge for each zone.  Indicated 
TOs propose to update the allocation percentage every five years to ensure rate stability 
and avoid the allocators becoming stale.  Indicated TOs propose to apply the revenues 
from the Grid Reliance Charge as credits to NITS and FCD transmission service 
customers in the relevant zone to avoid double recovery or inappropriate cost shifts.  
3. 
Response Briefs 
a. 
Basis for an Additional Charge 
 ODEC and NOVEC support Indicated TOs’ proposal for a Grid Reliance Charge 
to be applied to customers taking FCD and NFCD transmission service.925  ODEC argues 
such a charge ensures that Co-Located Loads pay their “fair share” of costs that are 
commensurate with the benefits Co-Located Loads receive from the transmission system, 
including the costs associated with delivery of black start and regulation services.  
 
922 Id. at 15-16 (citing W. Mass. Elec. Co. v. FERC, 165 F.3d 922, 927 (D.C. Cir. 
1999)). 
923 Id. at 16. 
924 Id. at 16-18. 
925 ODEC Response Brief at 10; NOVEC Response Brief at 9.

Docket No. EL25-49-002, et al. 
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NOVEC similarly asserts that Co‑Located Load depends on the transmission system to 
deliver black start and regulation services, the charges for which a delivery component is 
not included.  NOVEC argues that without the Grid Reliance Charge, a Co-Located Load 
that reserved no FCD or NFCD transmission service would be a free rider, as it would 
benefit from the payments of existing transmission customers to maintain the 
transmission system without making any contribution towards it.  
 Geronimo Power argues that Indicated TOs have not demonstrated that their 
proposed Grid Reliance Charge reflects Co-Located Loads’ actual impact on or benefits 
from interconnection with the transmission system and is consistent with cost causation 
principles.926  Further, Geronimo Power states that Indicated TOs have failed to 
demonstrate that there is a separate delivery component to black start and regulation 
services and that, if there were such a component, Indicated TOs have not explained why 
it would not be unduly discriminatory to apply it only to Co-Located Loads.   
 Vistra argues that Indicated TOs fail to address the nuances in the Commission’s 
paper hearing questions on additional charges or the actual ways that NFCD transmission 
service customers might rely on the grid.927  Vistra asserts that the Commission’s 
questions illustrate that customers could use NFCD transmission service in different ways 
but transmission owners would impose the same charge regardless.  Vistra maintains that, 
while Indicated TOs argue that Co-Located Loads are all synchronized to the grid, 
synchronization is not, itself, a service.  Vistra alleges that, in contrast to the 
Commission’s long-standing policy that transmission providers offer and price ancillary 
services separately, Indicated TOs create a new service for what appears to be an 
undefined ancillary service (i.e., grid reliance) to cover a suite of synchronization support 
services.  Vistra argues that it is not consistent with cost causation principles to impose 
the same grid reliance charge for very different types of grid reliance.  Vistra contends 
that the Commission did not prejudge whether or when a grid reliance charge is necessary 
and that the Commission could conclude no such charge is necessary for customers 
taking zero MWs or a de minimis amount of the new transmission services.  
 Industrials/Amtrak argue that, as an as-available service, there should be no 
standby fee charging NFCD transmission service customers for access to the transmission 
system that is not guaranteed.  Instead, Industrials/Amtrak contend that customers should 
be charged based on actual use on an hourly basis.928 
 
926 Geronimo Power Response Brief at 10-11, 13-14. 
927 Vistra Response Brief at 19-21.  
928 Industrials/Amtrak Response Brief at 24.

Docket No. EL25-49-002, et al. 
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b. 
Methodology for Determining Additional Charge 
 NOVEC states that the proposed Grid Reliance Charge is just and reasonable 
because it is limited to depreciation and operations and maintenance, and conservatively 
excludes a return on rate base and associated income taxes.929  NOVEC also notes that 
because revenues earned from the Grid Reliance Charge are returned to NITS and FCD 
transmission service customers as a revenue credit, the structure avoids any risk of double 
recovery. 
 Alliance argues that the additional charge question is important and should be 
resolved in a way that protects other customers from unjustified cost shifts.930  Alliance 
takes no position on a specific dollar figure; instead, it recommends that any additional 
charge reflect the contributions of load that have efficient operations or verified load 
flexibility through reductions in their cost obligations.    
 Regarding Indicated TOs’ argument that the Grid Reliance Charge will also cover 
costs associated with the protection schemes for Co-Located Load, Geronimo Power 
argues there is no reason to believe transmission owners will bear any such costs that 
could not be addressed in interconnection agreements.931 
 Vistra argues that, even if some charge is appropriate, Indicated TOs have not 
justified their proposed rate.932  Vistra contends that it is unreasonable to propose that a 
customer that never takes transmission service receives benefits approximating 25.8% of 
the transmission owners’ revenue requirement.  Vistra highlights that only 0.5% of PJM’s 
monthly total billings are related to black start and regulation charges and that, to the 
extent an NFCD transmission service customer never reserves transmission service relies 
on the transmission system, that reliance is for the sole purpose of receiving black start 
and regulation service.  As such, Vistra argues, the percentage of PJM’s total monthly 
billings that relates to black start and regulation charges is a reasonable proxy for the 
amount of transmission system costs that are associated with use of the grid to deliver 
black start and regulation service.  
 Vistra also contends that Indicated TOs’ proposal conflicts with the Commission’s 
transmission pricing policy because it disincentivizes efficiency and focuses on 
reallocating a large share of sunk costs.  Moreover, Vistra contends, Indicated TOs’ 
 
929 NOVEC Response Brief at 10. 
930 Alliance Response Brief at 4.  
931 Geronimo Power Response Brief at 14. 
932 Vistra Response Brief at 21-23.

Docket No. EL25-49-002, et al. 
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proposal would create significant and unjustified cost shifts between NFCD transmission 
service customers and Network Customers.933  Vistra suggests it is not clear what 
transmission owners, which are major Network Customers, will do with the bill credits 
and that it is not a foregone conclusion that they will pass savings onto retail customers.  
 Constellation contends that Indicated TOs’ proposed Grid Reliance Charge rests 
on an unsound methodology that violates cost causation principles.934  Constellation 
requests that the charge be recalculated based on the “minimum system” method.  
Constellation asserts that Indicated TOs both exclude reasonable costs and include 
unreasonable costs in the grid reliance capability operations and maintenance and provide 
very little justification for their proposal.  Moreover, Constellation argues that Indicated 
TOs inappropriately include full depreciation costs for a variety of transmission 
components that are sized to meet actual peak demand requirements of the PJM system, 
even though customers paying the Grid Reliance Charge do not withdraw energy from 
the PJM system.  In support of the minimum system method, Constellation argues it is 
designed to calculate the set of costs that a Co-Located Load that benefits from the 
existence of wires but imposes no demand on the grid should share.  Constellation 
explains that its method involves determining the minimum size of all electricity system 
components that could be used by the utility to recreate its system and connect each 
customer to the grid, and then applying this fraction to each transmission owners’ NITS 
rate.   
4. 
Reply Briefs 
a. 
Basis for an Additional Charge 
 Indicated TOs contend that being connected to the grid provides obvious benefits 
in terms of the ability to access resources that are not co-located with load.935  Indicated 
TOs further argue that being connected to the grid includes benefits like delivering 
ancillary services and essential reliability services, such as frequency support, inertia, 
voltage stability, fault current capability, ride-through and protections coordination, and 
providing sufficient short-circuit capability.  Indicated TOs state that they are unaware of 
any existing or proposed Co-Located Load customers that are choosing to island their 
load and on-site generation, and they infer from that fact that Co-Located Loads should 
 
933 Id. at 23-25. 
934 Constellation Response Brief at 25-28. 
935 Indicated TOs Reply Brief at 22 (citing Joint Blazunas/Schafer/Hammer 
Rebuttal Test. at 16); see also Joint Blazunas/Schafer/Hammer Rebuttal Test. at 31.

Docket No. EL25-49-002, et al. 
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share in the basic costs of operating and maintaining the grid upon which they rely.936  
Indicated TOs further argue that an additional charge is appropriate because ancillary 
services such as black start and regulation provide no value without the ability to access 
the transmission system to obtain them.937 
b. 
Methodology for Determining Additional Charge 
 Indicated TOs defend their proposed methodology, arguing that it produces a more 
conservative result focused on recovery of the costs necessary to support the ongoing 
reliable operation of the transmission system, rather than a return on investment.938  
Indicated TOs criticize Constellation’s proposal to use the “minimum system” method, 
arguing that it is not used at the transmission level and lacks any correlation between the 
benefits Co-Located Load receives and the electrical connection of customers.  Indicated 
TOs also reject Vistra’s proposed methodology, arguing that Vistra draws no connection 
between the percentage of billed revenue for regulation and black start and the costs of 
the transmission system to deliver those services and the benefits associated with grid 
connection.  
 NOVEC argues that Constellation’s minimum system proposal is not cost-aligned 
with the use of black start service or regulation service because black start service relies 
on the existence and durability of the transmission system in a way that Constellation’s 
minimum system methodology does not capture.939  NOVEC further argues that the ratio 
method advanced by Vistra arbitrarily confuses the cost of black start and regulation 
services with the cost of the transmission infrastructure necessary for customers to 
receive them.  
 Joint Co-Location Developers argue that the proposed Grid Reliance Charge is 
derived from an unsound methodology that violates cost causation principles.940  Joint 
Co-Location Developers argue that the Commission should direct the PJM transmission 
 
936 Indicated TOs Reply Brief at 22. 
937 Id. at 22-23. 
938 Id. at 24, 26-27, 29. 
939 NOVEC Reply Brief at 23, 26.  
940 Joint Co-Location Developers Reply Brief at 3 (citing Constellation Response 
Brief at 25; Geronimo Power Response Brief at 9-15; Vistra Response Brief at 18-23).

Docket No. EL25-49-002, et al. 
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owners to adopt the alternate cost calculation framework proposed by Constellation, 
which follows the Commission’s cost causation principles.941 
 Industrials/Amtrak argue that the proposed Grid Reliance Charge fails to reflect 
how different customers actually rely on the transmission system and would result in 
customers that take little or no energy from the grid subsidizing traditional network 
customers, violating cost causation principles.942  Industrials/Amtrak argue that NFCD 
transmission service should not be charged a standby fee such as the Grid Reliance 
Charge, as NFCD transmission service does not provide any guaranteed availability.   
5. 
Answers 
 Constellation contends that Indicated TOs’ proposal would force customers that do 
not impose demand on the transmission system to pay for transmission components sized 
to serve peak load, while also arbitrarily excluding costs related to rate of return and 
taxes.943  Constellation defends its proposed minimum system methodology. 
 Geronimo Power asserts that, while it does not oppose the concept of a grid 
reliance charge, Indicated TOs continue to fail to show that it is necessary and reflects 
Co-Located Loads’ actual grid impact or the transmission service they will receive.944  
Geronimo Power argues that Indicated TOs’ proposal to assess a charge for the delivery 
of black start and regulation service when other customers are not required to pay a 
separate delivery charge is unjust, unreasonable, and unduly discriminatory or 
preferential.945  Geronimo Power maintains that Indicated TOs have not demonstrated 
that the purported synchronization benefits will accrue to the same degree for Co-Located 
Load that is being primarily supplied by on-site generation.946 
 Indicated TOs respond to Constellation’s argument that the Indicated TOs’ 
proposed charge is based on the cost of the transmission system to serve peak demand 
rather than to delivery ancillary services, arguing that the purpose of the Grid Reliance 
 
941 Id. at 4 (citing Constellation Response Brief, attach. 1, (Testimony of Zachary 
Ming), at 14-15). 
942 Industrials/Amtrak Reply Brief at 11-12, 14. 
943 Constellation May 11 Answer at 11-12. 
944 Geronimo Power May 21 Answer at 10. 
945 Id. at 11. 
946 Id. at 12.

Docket No. EL25-49-002, et al. 
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Charge is not only to recover costs to deliver ancillary services, but to ensure Co-Located 
Load customers pay their fair share of the transmission system as it exists and the 
associated benefits that it provides to all interconnected customers, including essential 
reliability services.947  Indicated TOs maintain that their proposed charge does so by 
calculating the annual depreciation and operations and maintenance expenses that 
constitute a reasonable proxy for the costs of providing those benefits.  Indicated TOs 
assert that Constellation’s minimum system method is only appropriate for and applicable 
to distribution level service. 
6. 
Determination 
 In the December Order, the Commission sought briefing on whether the 
Commission should establish an additional charge for Eligible Customers on behalf of a 
Co-Located Load that elects to not reserve any amount of transmission service or only a 
de minimis amount of transmission service.948  In response, parties submitted briefs 
addressing a range of issues, including, among others:  (1) what potential benefits 
Eligible Customers that are synchronized to the transmission system might receive when 
not drawing energy from the transmission system; (2) whether those potential benefits 
warrant an additional charge or are adequately addressed through any transmission 
service charges that the Eligible Customer is already responsible for; and (3) proposed 
rates for such a charge and whether those proposed rates are consistent with cost 
causation principles.   
 We have considered that record and conclude that it does not adequately 
substantiate the need for an additional charge at this time or how such a charge should be 
calculated and assessed.  In particular, the record contains insufficient description of the 
potential nature or magnitude of the cited benefits or the potential costs that transmission 
providers or owners may incur when providing these benefits to Eligible Customers on 
behalf of Co-Located Loads.  For example, Indicated TOs state that, even where an 
Eligible Customer has requested FCD or NFCD transmission service for 0 MW, a large 
Co-Location Arrangement will still depend on the transmission system for a suite of 
synchronization support services, such as stable frequency, inertia, stability services 
(damping, angle stability), fault current capability, and ride-through and protection 
coordination.949  However, beyond briefly listing such benefits, the record lacks 
specificity regarding what these services are, what costs they involve, and how they 
 
947 Indicated TOs May 28 Answer at 11. 
948 December Order, 193 FERC ¶ 61,217 at P 219, questions 3 and 4. 
949 Indicated TOs Initial Brief at 15.

Docket No. EL25-49-002, et al. 
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benefit Eligible Customers on behalf of Co-Located Loads.  Accordingly, we decline to 
establish an additional charge at this time.  
 Nonetheless, we recognize that the new transmission services created in this 
proceeding could raise novel questions regarding application of cost causation principles, 
particularly if, in practice, many Eligible Customers taking the new transmission services 
on behalf of Eligible Load elect to take a de minimis or not reserve any amount of 
transmission service.  We believe that experience with the actual use of these new 
transmission services will improve our understanding of any potential issues and inform 
whether future action is needed.  To the extent parties identify such issues resulting from 
how Eligible Customers on behalf of Eligible Load use the new transmission services, 
they may submit filings under FPA section 205 or complaints under FPA section 206, as 
appropriate, and the Commission will consider the records before us at that time. 
C. 
Interconnection Requirements and Operational Practices for 
Necessary Control Technologies and/or Protection Systems 
1. 
Initial Briefs 
 PJM states that NERC has established reliability standard requirements for the 
various forms of control technologies that may be relied upon for grid stability to which 
Eligible Customers are expected to adhere.950  PJM explains that the PJM manuals and, 
as applicable, NERC reliability standards will contain the interconnection requirements 
and operational practices needed for necessary control technologies and protection 
systems to maintain system reliability if a Co-Located Load or Co-Located Generator 
trips offline.  PJM asserts that the NERC reliability standards form baseline 
interconnection requirements and operational practices, and the PJM manuals provide 
additional details and, at times, more stringent standards for remedial action schemes.  
PJM describes an illustrative list of interconnection requirements and operational 
practices in its brief, including NERC Reliability Standards PRC-012-2 and PRC-017-1, 
PJM Manual 3, section 1.8, and PJM Manual 7, section 17.2.951 
 Indicated TOs do not offer a specific proposal at this time, but they highlight 
concerns and key elements relating to interconnection, planning, and operational 
practices for the new transmission services.952  Indicated TOs assert that it is novel to use 
multiple special protection schemes/remedial action schemes to protect the grid from 
large amounts of on-site load exceeding their contractual withdrawal limitations.  
 
950 PJM Initial Brief at 56-57. 
951 Id. at 57-58. 
952 Indicated TOs Initial Brief at 22-26.

Docket No. EL25-49-002, et al. 
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Indicated TOs recommend that all special protection schemes and remedial action 
schemes be fully redundant to protect against the failures of protection schemes.  
Indicated TOs recommend that the Eligible Customer taking FCD transmission service, 
NFCD transmission service, or Interim NITS on behalf of Co-Located Load pay for   
PJM- and transmission owner-administered studies to ensure any special protection 
schemes or remedial action schemes can mitigate the risks of potential failure modes.  
Indicated TOs request the option to review and agree to curtailment procedures and 
operational control mechanisms.  Indicated TOs argue that all special protection schemes 
and remedial action schemes must meet PJM and transmission owner technical criteria.   
 Indicated TOs state that the Commission should consider requiring more frequent 
testing of special protection schemes and remedial action schemes than is currently 
required by NERC reliability standards.  Indicated TOs argue that they and PJM should 
receive test results of protection schemes and that any inadequate special protection 
schemes or remedial action schemes should be updated accordingly.  Indicated TOs argue 
that they and PJM should be permitted to implement and enforce reasonable limits on the 
total amount of load that can be covered by special protection schemes or remedial action 
schemes.  Indicated TOs request that the Commission direct NERC to establish 
requirements so that Eligible Customers taking FCD transmission service, NFCD 
transmission service, or Interim NITS on behalf of Co-Located Loads would be 
responsible for meeting relevant NERC reliability standards.  Indicated TOs contend that 
the Commission must strictly enforce compliance with NERC Reliability Standard   
PRC-012-2 (Remedial Action Schemes), which includes nine requirements to address all 
aspects of remedial action schemes.  Indicated TOs also emphasize that they will need to 
perform load integration studies for any Co-Located Load, as they currently do for large 
load customers, which could involve analysis of whether upgrades are needed to 
accommodate the physical gross load behind the Point of Interconnection.  
2. 
Response Briefs 
 Vistra opposes Indicated TOs’ request to implement and enforce limits on the 
amount of load that can be covered by special protection schemes, including in certain 
areas.953  Vistra expresses concern that this limit could lead to undue discrimination, and 
argues that if the Commission permits such limits, the Commission must ensure 
standardized and transparent guidelines are in place.  Vistra contends that Indicated TOs’ 
proposal would violate the comparability requirement because PJM’s existing procedures 
do not include location-based restrictions for remedial action schemes.  Vistra also 
opposes Indicated TOs’ proposal to own special protection schemes, arguing that it 
would needlessly raise the cost of transmission service.  
 
953 Vistra Response Brief at 27-28, 31.

Docket No. EL25-49-002, et al. 
- 210 - 
 NOVEC states that at a minimum, PJM’s proposal to incorporate NERC reliability 
standards is just and reasonable.954  NOVEC also states that the Commission should 
direct NERC to establish registration requirements for Co-Located Loads so that they can 
be responsible for meeting NERC reliability standards.  
 NOVEC states that special protection schemes should be fully redundant and that 
the applicable transmission owner should be able to establish technical criteria for the 
interconnection of Co-Located Load.955  NOVEC argues that transmission owners are 
familiar with the operating characteristics of their own systems, and any criteria should 
be flexible enough to include reasonable requirements the transmission owners believe 
are necessary to protect the transmission system. 
 Industrials/Amtrak argue that, to the extent that special protective schemes are 
required by the Commission for access to NFCD transmission service, the requirements 
should account for realistic on-site constraints, such as certain load/generation 
configurations that allow only a limited amount of draw from the transmission system.956 
 In response to PJM’s Initial Brief, Indicated TOs argue that any Eligible Customer 
taking any of the new transmission services (including FCD transmission service) ought 
to comply with requirements to implement necessary control technologies and protection 
systems to ensure that a Co-Located Load does not exceed its specified level of 
service.957  Indicated TOs therefore request that PJM add language to section 708(c) of 
PJM’s illustrative tariff provisions making clear that Interim NITS, FCD transmission 
service, and NFCD transmission service are contingent on the implementation of 
necessary control technologies and protection systems, where applicable.  Relatedly, 
Indicated TOs propose to strike the phrase “only in the case of Non-Firm Contract 
Demand Transmission Service” from subclause (ii) of section 710.5 of PJM’s illustrative 
tariff provisions.958  Similarly, Indicated TOs contend that PJM should revise                  
section 713.6 of PJM’s illustrative tariff provisions so as to not limit the requirement to 
establish necessary control technologies and protection systems to NFCD transmission 
service.  
 
954 NOVEC Response Brief at 16-17. 
955 Id. at 17. 
956 Industrials/Amtrak Response Brief at 25. 
957 Indicated TOs Response Brief at 7-8, 17-18. 
958 Id. at 19-20, 22.

Docket No. EL25-49-002, et al. 
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 Indicated TOs argue that PJM should include language in the Tariff making clear 
that necessary control technologies and protection systems may be required on both the 
customer’s and the transmission owner’s side of the Point of Interconnection, including 
in section 710.5 of PJM’s illustrative tariff provisions.959   
 Indicated TOs argue that it is important for PJM to work with the PJM 
transmission owners and other stakeholders to develop details on the requirements 
associated with control technologies and protection systems necessary to ensure that    
Co-Located Loads do not exceed their relevant withdrawal limitations.960 
 Constellation seeks clarification that PJM only intends to apply existing 
requirements in Manual 3 to Co-Location Arrangements, not to establish new 
requirements solely for such arrangements.961  Constellation also seeks clarification that 
PJM does not intend to restrict the use of permanent system protection schemes. 
 Constellation supports Indicated TOs’ first four recommendations, subject to 
clarification to avoid delay and discrimination.962  For example, while Constellation 
supports requiring full redundancy for special protection schemes and remedial action 
schemes, Constellation argues that it is not clear what full redundancy means.  
Constellation opposes the Indicated TOs’ remaining recommendations as unsupported 
and discriminatory.  
3. 
Reply Briefs 
 Indicated TOs state that they agree that the transmission owner and customer each 
may own the circuit breaker(s) and protection systems at their respective facilities and, in 
response to Constellation, state that the number of breakers will be determined by the 
transmission owner’s and customer’s design practices and budgets, as well as the 
 
959 Id. at 8-9, 20. 
960 Id. at 9. 
961 Constellation Response Brief at 21. 
962 Id. at 22-25.  More specifically, Constellation supports, subject to clarification, 
Indicated TOs’ recommendations that:  (1) all special protection schemes and remedial 
action schemes be fully redundant; (2) customers should pay for PJM and transmission 
owner-administered studies to ensure any special protection schemes and remedial action 
schemes can effectively mitigate the risks of potential failure modes; (3) transmission 
owners have the option to review and agree to any customer load curtailment procedures 
or operational control mechanisms; and (4) all special protection schemes and remedial 
action schemes must fully meet PJM and transmission owner technical criteria.  Id.

Docket No. EL25-49-002, et al. 
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transmission owner’s technical criteria.  Indicated TOs disagree with Constellation’s 
assertion that new technical criteria specific to Co-Located Load need not be added to 
PJM Manual 3.  Indicated TOs argue that such revisions or additions may be unavoidable 
due to the technical characteristics of Co-Located Load and contend that PJM and the 
PJM transmission owners should not be restricted from developing and implementing 
criteria applicable to Co-Located Load as a class if warranted by reasonable technical 
differences.963   
 Indicated TOs argue that Constellation’s request for the Commission to reject 
certain recommendations made by Indicated TOs is without merit.  Indicated TOs reject 
Constellation’s claim that these recommendations treat Co-Located Loads differently 
without legitimate basis and explain that certain transmission owners already require 
protection on their facilities in certain circumstances.964 
 Indicated TOs argue that Vistra provides no convincing reason for the 
Commission to reject Indicated TOs’ recommendation for reasonable limits on the 
amount of load covered by special protection schemes/remedial action schemes in 
specific geographic areas.  Indicated TOs acknowledge, however, that implementing such 
limitations would require the development of further details and guidelines.965 
 Joint Co-Location Developers argue that PJM and Market Monitor ignore the 
distinction between simple withdrawal-limiting protection systems that are required by 
PJM for sites taking non-firm transmission service and standard remedial action 
schemes.966  Joint Co-Location Developers explain that unlike standard remedial action 
schemes, which monitor and control components across the grid, simple                      
withdrawal-limiting protection systems monitor and control only facility-internal 
components, monitoring flows, adjusting consumption or generation at the site level, and 
disconnecting from the grid if necessary.  Joint Co-Location Developers argue that 
simple withdrawal-limiting protection systems can be relied upon much more extensively 
than standard remedial action schemes without creating the same complexities and 
interdependencies.  
 
963 Indicated TOs Reply Brief at 11-13. 
964 Id. at 13-14. 
965 Id. at 14. 
966 Joint Co-Location Developers Reply Brief at 6-7.

Docket No. EL25-49-002, et al. 
- 213 - 
 Joint Co-Location Developers agree with Indicated TOs that all special protection 
schemes and remedial action schemes should be fully redundant.967 
 Constellation argues that Indicated TOs’ recommendation that PJM impose 
necessary control technologies and protection systems on both the customer’s side and 
the transmission owner’s side of the Point of Interconnection for Co-Located Loads as a 
default requirement is unsupported and unduly discriminatory.968  Constellation asserts 
that always requiring double special protection schemes is not good utility practice and 
would likely be appropriate only in rare situations.969 
 Constellation contends that system studies of unauthorized use should be 
standardized, transparent, and based on reasonable assumptions set ahead of time to avoid 
disparate treatment.970  Constellation states that PJM can use the standardized study 
processes and established reliability tests in its existing generator interconnection process 
and RTEP process to determine whether a special protection scheme is needed.  
 Constellation argues that criteria for special protection schemes should leverage 
current RTEP planning criteria to develop specific criteria for Co-Located Load risks that 
are reasonable and transparent.971 
 Constellation asserts that the special protection scheme that PJM requires an 
Eligible Customer to implement should be commensurate with the risks identified in the 
studies.  Constellation argues that special protection schemes are not appropriate for 
every situation, and PJM only requires them when studies identify actual overloads and 
conditions that could cause cascading failures that PJM cannot mitigate through normal 
operations.972  Constellation contends that double special protection schemes should not 
be employed when other measures can maintain system reliability and real-time 
monitoring can address any unexpected reliability issue.973 
 
967 Id. at 7 n.23 (citing Indicated TOs Initial Brief at 23).  
968 Constellation Reply Brief at 13-14 (citing Indicated TOs Response Brief at 8). 
969 Id. at 14 (citing Kormos Aff. ¶¶ 7, 11). 
970 Id. at 15. 
971 Id. at 15-16. 
972 Id. at 16 (citing Kormos Aff. ¶¶ 5-6). 
973 Id. at 18.

Docket No. EL25-49-002, et al. 
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4. 
Answer 
 In response to Constellation, Indicated TOs argue that, in order for an Eligible 
Customer to take one of the new transmission services, it is necessary and just and 
reasonable to require an Eligible Customer to include appropriate protection systems.974  
Indicated TOs further assert that special protection schemes on the Co-Located Load 
customer’s and the transmission owner’s side of the point of interconnection should not 
be limited to what Constellation claims are higher-risk situations.975  Indicated TOs claim 
that, without protection system redundancy, the transmission system is at risk.976  
Indicated TOs reject Constellation’s assertion that PJM should use a PJM-driven study 
process to evaluate special protection schemes, arguing that special protection schemes 
and remedial action schemes are within the purview of the transmission owners, and PJM 
is not equipped to perform these studies.  Indicated TOs also allege that the cost to 
implement protection systems is extremely low compared to other costs to develop and 
interconnect Co-Located Load and would not be a deterrent.977 
5. 
Determination 
 We decline to direct PJM’s proposal as part of the replacement rate because it does 
not require Eligible Customers taking FCD transmission service to have necessary 
control technologies and/or protection systems to limit their energy withdrawals from the 
transmission system to their contract demand level.  We find that PJM’s proposal is 
inconsistent with the directives in the December Order.  In the December Order, the 
Commission found that an Eligible Customer that is willing and able to limit its energy 
withdrawals from the transmission system under certain conditions should be able to take 
transmission services on behalf of Co-Located Load that reflect their ability to limit 
withdrawals.978  The Commission stated that where a Co-Location Arrangement includes 
special protection schemes that limit its energy withdrawals, it is a just and reasonable 
replacement rate to allow an Eligible Customer taking transmission service on behalf of 
such load to take these transmission services.979  We clarify, however, that the December 
 
974 Indicated TOs May 28 Answer at 4. 
975 Id. at 5. 
976 Id. at 6. 
977 Id. at 7. 
978 December Order, 193 FERC ¶ 61,217 at PP 159-160. 
979 Id. PP 204-205.

Docket No. EL25-49-002, et al. 
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Order did not limit eligibility to take the new transmission services only to Co-Location 
Arrangements that include a special protection scheme.980  
 Based on the record here, we find it just and reasonable that, in order for an 
Eligible Customer to take Interim NITS, FCD, and/or NFCD transmission services on 
behalf of any Eligible Load, 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 contract demand level.981  This replacement rate is 
consistent with prior Commission precedent for interconnection service, which 
recognizes that these necessary control technologies and/or protection systems are 
essential to enforce physical limits and ensure system reliability where an Interconnection 
Customer has requested a level of service below its maximum capacity.982  Further, 
consistent with the Commission’s determination in Order No. 845, nothing prevents an 
Eligible Customer taking Interim NITS, FCD, and/or NFCD transmission service on 
behalf of Eligible Load from proposing its own necessary control technologies and/or 
protection systems for consideration, which may include a special protection scheme.983  
 PJM’s proposal falls short because it does not require Eligible Customers taking 
FCD transmission service to have necessary control technologies and/or protection 
systems to limit their energy withdrawals from the transmission system to their contract 
demand level.  As such, PJM would have to rely on penalties that disqualify an Eligible 
Customer from taking FCD transmission service if the Eligible Customer fails to follow 
established load shedding and curtailment procedures, and financial penalties for 
unreserved use of the PJM transmission system, to discourage excess energy 
withdrawals.  However, load shedding and curtailment events for a transmission service 
that will be treated as the equivalent of NITS for purposes of curtailment will be rare; and 
PJM itself has stated concerns that financial penalties alone are insufficient to deter 
 
980 Id. P 205 (“For these reasons, in these instances where the Co-Location 
Arrangement includes special protection schemes that limit its energy withdrawals, we 
find that it is a just and reasonable replacement rate to allow an Eligible Customer taking 
transmission service on behalf of such load to take and be charged for new types of 
transmission service that are alternatives, and not equivalent, to NITS.”). 
981 While we will continue to use the term “special protection scheme” in this 
proceeding, we reiterate that this term is equivalent to “remedial action scheme.”  Id. 
P 204. 
982 Reform of Generator Interconnection Procs. & Agreements, Order No. 845, 
163 FERC ¶ 61,043, at P 367 (2018), order on reh’g, Order No. 845-A, 166 FERC                    
¶ 61,137, order on reh’g, Order No. 845-B, 168 FERC ¶ 61,092 (2019). 
983 Id. P 372.

Docket No. EL25-49-002, et al. 
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unreserved use.984  Accordingly, and consistent with our determination above to extend 
the three new transmission services set forth in the December Order to Eligible 
Customers taking service on behalf of load with BTMG that are willing and able to limit 
their energy withdrawals from the transmission system under certain conditions, we 
direct PJM to file, within 60 days of the date of issuance of this order, a compliance filing 
with Tariff revisions that require Eligible Customers taking Interim NITS, FCD, and/or 
NFCD transmission service on behalf of Eligible Loads, to have necessary control 
technologies and/or protection systems.  
 We find it just and reasonable for PJM to include the interconnection requirements 
and operational practices needed for necessary control technologies and/or protection 
systems in the PJM manuals and, as applicable, to rely on relevant NERC reliability 
standards, consistent with PJM’s current practices.  Further, we find it appropriate for 
PJM to develop new interconnection requirements and operational practices that 
recognize the unique nature of Co-Location Arrangements and the new transmission 
services.  However, PJM has not, to date, actually proposed any interconnection 
requirements and operational practices specific to Co-Location Arrangements, nor does 
PJM indicate which of its existing interconnection requirements and operational practices 
it will apply to Co-Location Arrangements.  Consistent with our determination above to 
extend the three new transmission services set forth in the December Order to Eligible 
Customers taking service on behalf of load with BTMG that are willing and able to limit 
their energy withdrawals from the transmission system under certain conditions, we 
direct PJM to submit, as part of its compliance filing due within 60 days of the date of 
issuance of this order, an explanation of what new and existing interconnection 
requirements and operational practices it will apply to Eligible Customers taking Interim 
NITS, FCD, and/or NFCD transmission services on behalf of Eligible Load.  We agree 
with Indicated TOs that it is important for PJM to work with the transmission owners to 
develop specificity regarding the requirements associated with necessary control 
technologies and/or protection systems necessary to ensure that Eligible Customers do 
not withdraw energy from the transmission system in excess of their contract demand. 
 We do not agree that all parties’ recommendations to clarify PJM’s proposal are 
just and reasonable, or even within the scope of this proceeding.  However, we agree that 
some guidance on the study and implementation of necessary control technologies and/or 
protection systems would be of value.  Therefore, and consistent with our determination 
above to extend the three new transmission services set forth in the December Order to 
Eligible Customers taking service on behalf of load with BTMG that are willing and able 
to limit their energy withdrawals from the transmission system under certain conditions, 
we explain several principles that PJM’s compliance filing should consider. 
 
984 PJM Initial Brief at 50.

Docket No. EL25-49-002, et al. 
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 First, Eligible Customers shall pay for PJM and transmission owner-administered 
studies to evaluate and design necessary control technologies and/or protection systems, 
consistent with their responsibilities for the costs of other studies performed as part of the 
evaluation of their transmission service request.  However, the scope of these studies 
should be defined in the Tariff, consistent with the level of detail for other transmission 
services, as discussed in Part VI.A.3.985  Furthermore, we reiterate our finding above that 
an Eligible Customer taking transmission service on behalf of an Eligible Load may 
propose its own necessary control technologies and/or protection systems for 
consideration as part of this study, which may include a special protection scheme, 
although PJM and the transmission owners retain their existing discretion regarding the 
determination of what is necessary to ensure the reliability of the transmission system. 
 Second, if a special protection scheme is employed as necessary control 
technologies and/or protection systems, then such special protection schemes 
implemented must be, at minimum, fully redundant.  Given questions by commenters 
regarding what “redundant” specifically means, we clarify that such special protection 
schemes must be able to withstand removal of part or all of one scheme due to a failure, 
or to allow for maintenance on a scheme, while providing full scheme capability with a 
functionally equivalent and separate scheme.986 
 Third, all necessary control technologies and/or protection systems, which may 
include a special protection scheme, must fully meet PJM and transmission owner 
technical criteria, as well as any applicable NERC reliability standards. 
 Fourth and finally, both PJM and the transmission owners shall have the option to 
review and agree to the implementation of the Eligible Customer’s necessary control 
technologies and/or protection systems as defined in the service agreement, to ensure that 
it meets both PJM and transmission owner technical criteria, and is capable of limiting 
withdrawals from the transmission system. 
 We disagree with Indicated TOs that PJM should include language in the Tariff 
making clear that necessary control technologies and/or protection systems may be 
required on both the Interconnection Customer’s and the transmission owner’s side of the 
Point of Interconnection.  PJM and the transmission owners will, as noted in the 
principles above, be responsible for evaluating and designing necessary control 
technologies and/or protection systems for each Co-Location Arrangement.  The location 
or number of devices required should be based on the engineering judgment of PJM and 
 
985 See supra Part VI.A.3. 
986 See, e.g., WECC, Remedial Action Scheme Design Guide, § 4.10 (July 2022), 
https://www.wecc.org/sites/default/files/documents/meeting/2024/WECC%20RAS%20D
esign%20Guide%202022.pdf.

Docket No. EL25-49-002, et al. 
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the transmission owners.987  Similarly, we find that questions of ownership of these 
facilities, or the potential to earn a rate of return on said facilities, are outside the scope of 
this proceeding.  
 In response to Indicated TOs, we find that there is insufficient information in this 
record to justify allowing them or PJM to implement and enforce limits on the total 
amount of load that can be covered by a special protection scheme.  If PJM or its 
transmission owners wish to impose a specific limit, they may submit a new filing under 
FPA section 205 with a sufficient showing, based on experience gained once Eligible 
Customers begin taking Interim NITS, FCD, and/or NFCD transmission service on behalf 
of Eligible Load.  However, implementation of a special protection scheme should not be 
universally required as a condition of taking these transmission services; rather, only 
necessary control technologies and/or protection systems are required.  If PJM or its 
transmission owners wish to limit the use of special protection schemes on their system, 
they can also design necessary control technologies and/or protection systems for Eligible 
Customers that do not have a special protection scheme. 
 We decline to address NOVEC’s request that the Commission direct NERC to 
establish registration requirements for Co-Located Loads.  Whereas NOVEC’s request 
may be availing in the context of a FPA section 215 proceeding, the instant case arises 
under FPA section 206.  In addition, NERC is already considering registration 
requirements for large loads, including potentially Co-Located Loads, as part of its Large 
Load Action Plan.988 
D. 
Penalty Charge or Other Remedial Action for New Transmission 
Services 
1. 
Initial Briefs 
 PJM proposes different penalties where an Eligible Customer:  (1) fails to follow 
established load shedding and curtailment procedures; (2) relies on necessary control 
 
987 Cf. RWE Clean Energy, LLC v. PJM Interconnection, L.L.C., 194 FERC 
¶ 61,212, at P 42 (2026) (“The Commission generally allows transmission providers to 
exercise their engineering judgment when conducting interconnection studies, including 
deferring to transmission providers’ discretion regarding how to maintain a reliable 
transmission system.”); Order No. 1920-A, 189 FERC ¶ 61,126 at P 450 (“Finally, we 
clarify that the Commission generally provides transmission providers with the discretion 
to use engineering judgment in designing and conducting transmission planning studies, 
and we therefore decline to address Dominion’s hypothetical in the abstract.”). 
988 See NERC, Large Loads Action Plan, https://www.nerc.com/initiatives/large-
loads-action-plan (last visited May 15, 2026).

Docket No. EL25-49-002, et al. 
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technologies or protection systems that fail more than once; and (3) makes unreserved 
use of the transmission system.989  PJM argues that, where an Eligible Customer fails 
once to respond to established load shedding and curtailment procedures, the customer is 
disqualified automatically because of the significant reliability risk.  PJM asserts that its 
proposal is just and reasonable and consistent with the key principles that (1) Eligible 
Customers are willing and able to control their withdrawals from the transmission system 
and (2) the services are designed to allow PJM to maintain system reliability.  PJM 
proposes that, if the Eligible Customer is taking FCD or NFCD transmission service and 
is disqualified, such customer may still take NITS or Interim NITS.  PJM proposes that, if 
the Eligible Customer is taking Interim NITS and is disqualified, such customer may take 
NITS.990 
 PJM argues that when a control technology or protection scheme misoperates 
there can be serious consequences.991  PJM proposes that, after one instance of 
misoperation, the Eligible Customer will be prohibited from taking transmission service 
or otherwise withdrawing energy from the transmission system for a period of up to               
120 days from misoperation to allow for an analysis of the necessary control technology 
or protection system scheme’s operational performance.  PJM asserts that this proposed 
pause is consistent with NERC requirements for an investigation into the operation of a 
remedial action scheme992 and will allow PJM time to investigate, identify, and 
implement fixes to better protect the transmission system.993  PJM proposes that, after 
two instances of misoperation, the Eligible Customer will be automatically disqualified 
from taking the relevant new transmission service because of the significant reliability 
risks.  PJM asserts that this rule properly balances the need to protect reliability against 
the desire of an Eligible Customer taking service on behalf of a Co-Located Loads to take 
a transmission service lesser than NITS because the Co-Located Loads  are willing and 
able to limit their energy withdrawals.  PJM maintains that a second instance of a 
misoperation makes it evident that the necessary control technology or protection system 
cannot adequately protect the system from the Co-Located Load’s unreserved energy 
withdrawals.  PJM explains that an Eligible Customer disqualified from taking FCD or 
 
989 PJM Initial Brief at 40. 
990 Id. at 41-43. 
991 Id. at 43-44.  Misoperation, as contemplated by PJM, relies on and incorporates 
the term as defined by NERC (e.g., PRC-004-6).  See, e.g., NERC, PRC-004-6 – 
Protection System Misoperation Identification & Correction (June 12, 2025), 
https://www.nerc.com/globalassets/standards/reliability-standards/prc/prc-004-6.pdf. 
992 Reliability Standard PRC-004-6. 
993 PJM Initial Brief at 45.

Docket No. EL25-49-002, et al. 
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NFCD transmission service on this ground may either take NITS or Interim NITS, and 
that an Eligible Customer disqualified from taking Interim NITS on this ground may take 
NITS.  PJM supports its proposal to permit an Eligible Customer disqualified from taking 
the new transmission services to take NITS by reasoning that NITS, in and of itself, 
addresses curtailment, load shed, and control technology or protection scheme 
misoperation risk.994  
 PJM states that it supports a penalty for unreserved use in addition to the 
operational penalties and intends to work with the transmission owners to explore a 
financial penalty.995  PJM argues that financial penalties alone are insufficient to 
incentivize Eligible Customers to comply with load shed, curtailment, and control 
technology and protection system obligations.  PJM asserts that many, if not most, 
Eligible Customers taking service on behalf of a Co-Located Load could elect to absorb 
financial penalties for unreserved use rather than follow curtailment or load shed 
procedures or avoid misoperation of the protective technology or system. 
 Indicated TOs assert that any penalty regime should rely on both operational 
consequences and complementary financial penalties.996  Indicated TOs allege that it is of 
the utmost importance that Co-Located Loads respect contractual limits because                
Co-Location Arrangements involve substantial amounts of load connected to the grid and 
failure to respect these limits could pose severe reliability consequences for the system.   
 Indicated TOs support PJM’s proposal but argue that additional details must be 
developed as to how operational consequences would be applied.997  Indicated TOs also 
state that financial penalties could be valuable where the Eligible Customer exceeds its 
contract demand, even if such deviations are mitigated by a special protection scheme. 
2. 
Response Briefs 
 ODEC supports PJM’s proposed penalty structure, including operational 
penalties.998  NOVEC states that disqualification for failure to follow load shedding or 
 
994 Id. at 45-50. 
995 Id. at 50. 
996 Indicated TOs Initial Brief at 19. 
997 Id. at 20. 
998 ODEC Response Brief at 11.

Docket No. EL25-49-002, et al. 
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curtailment procedures is necessary to protect the integrity of the transmission system.999  
Indicated TOs request that Tariff language be included requiring that the relevant 
transmission owner’s approval be obtained before service to an Eligible Customer is 
reinstated following a control technology/protection system misoperation. 
 Constellation opposes the proposal to suspend or disqualify an Eligible Customer, 
arguing it is excessive and applies regardless of fault and does not apply to Non-Firm 
PTPS customers.1000  Constellation urges the Commission to follow SPP’s proposal for 
Conditional High Impact Large Load Service (CHILLS) and align treatment of 
unreserved use for the new services with its treatment of Non-Firm PTPS.  DCC 
expresses concern about PJM’s operational penalties in light of the lack of clarity around 
PJM’s curtailment procedures for the new transmission services.1001  Vistra similarly 
argues that PJM’s proposed operational penalties diverge from the Commission’s 
directives and violate the comparability principle because the December Order does not 
contemplate disqualification and, more generally, such a penalty structure exceeds what 
the Commission has allowed for unreserved use of the transmission system.1002  Vistra 
contends that PJM’s proposal is excessively punitive and may be unduly discriminatory 
in comparison to customers that take PTPS.  Vistra also alleges that PJM’s proposal also 
violates the comparability requirement because it treats Co-Location Arrangements using 
special protection schemes differently from any other entities using such schemes.  Vistra 
also points out that, if the Commission accepts transmission owners’ proposal to own 
special protection schemes, then misoperation of such schemes must attach to the 
transmission owner, not the Eligible Customer.  
 Joint Co-Location Developers argue that PJM’s proposed penalty provisions are 
unjust and unreasonable because they are not “narrowly designed to balance the need to 
deter conduct that is harmful to the system with the need to limit excessive and 
unnecessary costs.”1003  Joint Co-Location Developers express concern that PJM’s 
proposed disqualification rules will dissuade Eligible Customers from taking the new 
transmission services because of the risk of stranding or undermining investments in the 
 
999 NOVEC Response Brief at 11-12. 
1000 Constellation Response Brief at 19-20.  See also Joint Co-Location Developers 
Response Brief at 25. 
1001 DCC Response Brief at 7. 
1002 Vistra Response Brief at 29-31. 
1003 Joint Co-Location Developers Response Brief at 23 (quoting Mirant Kendall, 
LLC, 110 FERC ¶ 61,272, at P 17 (2005)).

Docket No. EL25-49-002, et al. 
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new services.1004  Joint Co-Location Developers propose that PJM adopt financial 
penalties sufficient to deter gaming of transmission service subscription.  Joint                 
Co-Location Developers contend that a disqualification-based penalty is not necessary 
because transmission owners can manually disconnect a facility in case of potential 
severe reliability risk.  Joint Co-Location Developers assert that failure to respond to 
curtailment would have a similar impact from a resource adequacy perspective to a 
capacity resource failing to perform during emergency events, in which case only a                
non-performance charge is assessed.  Joint Co-Location Developers urge that, if the 
Commission adopts disqualification as a penalty, the Commission should adopt intent (or 
at least fault), materiality, and repetition elements prior to disqualification to ensure 
disqualification sends an actionable signal.1005  Joint Co-Location Developers suggest 
that that an operational penalty is excessive for misoperation of control technologies or 
protection systems because misoperation without withdrawal does not risk system 
harm.1006 
 Indicated TOs propose a financial penalty charge structure with two components:  
(1) a base penalty charge; and (2) a penalty ratchet.1007  The base penalty charge would be 
assessed for any hour in which at least one five-minute interval occurs during which a 
customer’s metered load at the Point of Interconnection exceeds its reserved transmission 
service.  The penalty ratchet would apply additional daily penalties if exceedances 
occurred in more than one hour during a day, additional weekly penalties if exceedances 
occurred on more than one day during a week, and additional monthly penalties if 
exceedances occurred in more than one week during a month.  Further, each of these 
penalties would entail escalating financial liabilities for repeated penalties, which 
Indicated TOs argue would reinforce the expectation that Co-Located Load customers 
manage their load in a manner consistent with their reserved transmission service.  
 NOVEC states that a penalty for unreserved use in addition to disqualification and 
pause-in-service rules is appropriate, as this penalty would be an additional deterrent that 
would help make the market or other ratepayer whole if a Co-Located Load customer 
exceeds its contract demand.1008  NOVEC suggests that any financial penalty should 
compensate other customers for any harm caused by the Eligible Customer’s departure 
 
1004 Id. at 24-25. 
1005 Id. at 26 (citing PJM Interconnection, L.L.C., 178 FERC ¶ 61,104, at PP 60-61 
(2022)). 
1006 Id. at 26. 
1007 Indicated TOs Response Brief at 12-13. 
1008 NOVEC Response Brief at 13 (citing Indicated TOs Initial Brief at 20).

Docket No. EL25-49-002, et al. 
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from Co-Location requirements or, if there is no harm, be set at a level sufficient to 
encourage compliance with the Tariff’s scheduling requirements. 
 ODEC suggests that the Commission also consider whether any protections are 
needed for local utilities or transmission owners should they need to take the 
extraordinary measure of disconnecting an Eligible Customer taking service on behalf of 
Co-Located Loads, if the Eligible Customer’s use of the transmission system exceeds 
contract demand or is called upon for load shedding and curtailment.1009  ODEC states 
that, in such instance, the local utility or transmission owner should not be liable for 
legal, financial, or other damages that might be experienced by an Eligible Customer.  
NOVEC asserts that PJM’s penalty language should be revised to specify that when an 
Eligible Customer serves multiple Co‑Located Loads, only the culpable Co‑Located Load 
is disqualified rather than the Eligible Customer as a whole.1010 
3. 
Reply Briefs 
 PJM argues that monetary penalties, in place of non-monetary penalties, would 
undermine the value of reliability and hand it to a single site or a class of load that may 
decide to pay the penalty in place of operating as agreed to ensuring overall system 
reliability.1011  PJM alleges that non-monetary operational penalties are essential to the 
responsible integration of large loads.  PJM maintains that its non-monetary operational 
penalties represent a measured approach that balances significant reliability concerns 
with the interest in integrating large loads quickly.  However, PJM notes that, in response 
to protesters’ concerns, PJM proposes revisions to its illustrative tariff language to add 
discretion to the strict application of non-monetary operational penalties.   
 PJM argues that the Commission did not foreclose non-monetary penalties 
because the December Order “also direct[s] parties to brief . . . any other remedial action 
that PJM should take to address withdrawals in excess of the contract demand.”1012  PJM 
also claims that financial penalties alone are insufficient to support reliability in light of 
the volume of load that is anticipated to come online in short order and the nature of how 
these new loads will seek to connect through co-location with potentially critical 
generators.  PJM rejects Vistra’s contention that non-monetary penalties are a departure 
from Commission precedent, and responds that the Commission has long held that where 
monetary penalties do not incentivize actions consistent with reliability, it may be 
 
1009 ODEC Response Brief at 11-12. 
1010 NOVEC Response Brief at 14-15. 
1011 PJM Reply Brief at 40-43.  
1012 Id. at 49-50 (quoting December Order, 193 FERC ¶ 61,217 at P 212).

Docket No. EL25-49-002, et al. 
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necessary to implement “a range of non-monetary and monetary penalties” to promote 
behavior that supports and improves the reliability of the bulk power system.1013  PJM 
rejects Joint Co-Location Developers’ suggestion that PJM adopt financial penalties 
sufficient to deter gaming, and responds that PJM’s proposed penalty structure is not 
intended to address gaming but to support reliability.  In response to Joint Co-Location 
Developers’ suggestion that disqualification is unnecessary because transmission owners 
can manually disconnect a facility, PJM argues that it is inconsistent with reliable 
operation of the transmission system to shift responsibility away from the Eligible 
Customer.  PJM also alleges that it and the transmission owner will become aware of an 
improperly set-up protection scheme only after the misoperation incident, which will 
expose the PJM system to risk.  PJM adds that when a transmission owner manually cuts 
load suddenly, without proper coordination, it can have disastrous and dangerous 
cascading system effects.1014 
 Nevertheless, PJM proposes revisions to its illustrative tariff language to permit, 
where appropriate, PJM to exercise discretion in determining when disqualification 
penalties are appropriate based on PJM’s assessment of factors including the reliability 
impact of the failure to curtail or shed load or the misoperation of control technologies or 
protection system schemes.  PJM adds that, with these revisions, the Eligible Customer 
taking transmission service on behalf of Co-Located Load will not be held liable for the 
actions of others.1015 
 Several parties agree that financial penalties are insufficient to ensure 
reliability.1016  ODEC asserts that it does not agree that PJM’s proposed suspension and 
disqualification measures are unfairly imposed regardless of fault and will make the 
services unduly risky for many loads.  Earthjustice argues that PJM’s operational 
penalties are proportionate to the prospective harm associated with a customer’s failure to 
follow curtailment orders.  Earthjustice argues that, while opposing commenters note that 
PJM’s proposed penalties are stricter than the penalties it has levied in other 
circumstances, those comments fail to acknowledge that the stakes here are higher.  
 
1013 Id. at 51 (quoting Rules Concerning Certification of the Elec. Reliability Org.; 
and Procs. for the Establishment, Approval, and Enf’t of Elec. Reliability Standards, 
Order No. 672, 114 FERC ¶ 61,104, at PP 49, 455, order on reh’g, Order No. 672-A,            
114 FERC ¶ 61,328 (2006)). 
1014 Id. at 52-53. 
1015 Id. at 54. 
1016 ODEC Reply Brief at 4-5; Earthjustice Reply Brief at 2-3, 5, 8; Indicated TOs 
Reply Brief at 14-15 (citing Joint Blazunas/Schafer/Hammer Rebuttal Test. at 4).

Docket No. EL25-49-002, et al. 
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Earthjustice argues that PJM’s penalty proposal is appropriately designed to protect 
system reliability, rather than assign fault.   
 Industrials/Amtrak urge the Commission to exercise caution in overly harsh 
operational penalties, especially for existing retail customers who may be forced to move 
from retail BTMG arrangements to Co-Location Arrangements.  Industrials/Amtrak 
argue that it is reasonable to pay financial penalties, but a retail customer should not be 
banned from NFCD transmission service for a lone violation.1017 
 PJM rejects Vistra’s contention that its non-monetary penalties for misoperation of 
necessary control technologies or protection systems are unduly discriminatory.  PJM 
alleges that NERC, Market Monitor, and PJM’s 2026 load forecast each demonstrate that 
the new large loads integrating into PJM’s transmission system are not similarly situated 
to traditional loads.  PJM adds that disqualification penalties do not foreclose Eligible 
Customers from taking transmission service entirely, and that, where Eligible Customers 
demonstrate that they cannot (or are unwilling to) limit withdrawals, it is appropriate for 
those Eligible Customers to take NITS.1018 
 Indicated TOs reject Constellation’s argument that PJM should simply adopt 
financial penalties as is the case with SPP’s High Impact Large Load (HILL) process.1019  
Indicated TOs argue that SPP’s HILL process is different in that, under PJM’s proposal, 
Co-Located Load customers may be in the position of installing and operating their own 
control technologies and protection systems.  Indicated TOs further argue that PJM and 
SPP are different regions with different characteristics, including topology and 
proliferation of large loads.  Indicated TOs also dismiss DCC’s and Vistra’s concerns 
regarding Co-Located Load’s liability for penalties associated with control technologies 
and protection systems operated by other parties, including transmission owners.  
Indicated TOs argue that installation of redundant protection facilities by transmission 
owners should not serve as an excuse for the failure of customers to properly maintain 
and operate their own equipment.  
 NOVEC states that it generally supports Indicated TOs’ proposed financial penalty 
charge structure, subject to Indicated TOs providing further information.1020  ODEC 
supports financial penalties but states that PJM’s implementation of its penalties must not 
subject ODEC or its member distribution cooperatives to service interruptions or 
 
1017 Industrials/Amtrak Reply Brief at 17-18. 
1018 PJM Reply Brief at 43, 45, 47. 
1019 Indicated TOs Reply Brief at 15-16. 
1020 NOVEC Reply Brief at 26-27.

Docket No. EL25-49-002, et al. 
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disqualification, or financial penalties, as a result of requiring ODEC to serve as the 
Eligible Customer.1021 
 Indicated TOs further explain their financial penalty proposal, explaining that 
when a Co-Located Load exceeds its reserved transmission service limit, which includes 
any reductions based on curtailments directed by PJM, the base penalty charge will be 
assessed for any hour (Exceedance Hour) in which at least one five-minute interval 
(Exceedance Interval) occurs during which a customer’s metered load at the point of 
delivery exceeds its reserved transmission service.  Indicated TOs state that the base 
penalty charge will apply to each Exceedance Hour.1022 
 Indicated TOs state that the base penalty charge will be calculated as the product 
of the Hourly Exceedance MW, the Equivalent Hourly FCD transmission service rate, 
and the number of Exceedance Intervals within the hour, where the Hourly Exceedance 
MW is equal to the maximum telemetered load during the hour less the reserved 
transmission service limit for the hour and where the Equivalent Hourly FCD 
transmission service rate is equal to the FCD transmission service rate divided by                
8,760 hours.1023  Indicated TOs explain that the FCD transmission service rate is used as 
the basis for assessing the penalty because, when a customer exceeds its reserved 
transmission service limit without authorization, the excess usage effectively imposes 
firm-level demand on the system.   
 Indicated TOs state that the penalty ratchet applies escalating FCD-equivalent 
transmission service rates as the frequency of unreserved transmission use increases.  
Indicated TOs explain that the penalty ratchet applies daily, weekly, monthly, or annual 
penalty charges depending on whether exceedances occur within the same calendar day, 
week, month, or year, and that these penalty charges are equal to the Daily                         
FCD-Equivalent Rate, Weekly FCD-Equivalent Rate, Monthly FCD-Equivalent Rate, 
and FCD Annual Rate, respectively.1024  Indicated TOs further explain that, where a daily 
penalty charge is assessed, it is in addition to the base penalty charge applicable to each 
individual Exceedance Hour; where a weekly penalty charge is assessed, it is in addition 
to the base penalty charges and daily penalty charges; and so on.   
 
1021 ODEC Reply Brief at 4. 
1022 Indicated TOs Reply Brief at 16-17. 
1023 Indicated TOs Reply Brief, Joint Blazunas/Schafer/Hammer Rebuttal Test. 
at 8-9. 
1024 Id. at 10-14.

Docket No. EL25-49-002, et al. 
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 Indicated TOs propose to distribute daily, weekly, and monthly penalty revenues 
on a monthly basis to Eligible Customers taking NITS or FCD transmission service that 
have not been penalized during the month, as pro rata bill credits.  Indicated TOs further 
propose to distribute annual penalty charges on an annual basis to Eligible Customers 
taking NITS and FCD transmission service that have not been penalized during the year 
as pro rata bill credits.1025 
4. 
Answer 
 Constellation alleges that PJM’s reliability arguments are not persuasive, because 
PJM’s example involves grid-connected load, not Co-Located Load.1026  Constellation 
argues that PJM fails to explain how resource adequacy concerns justify its proposed 
penalty scheme, and points out that PJM has proposed no such penalties for Connect and 
Manage.1027  Constellation next argues that a four-month suspension is not consistent 
with NERC requirements, as PJM claims.1028 
5. 
Determination 
 We find that it is just and reasonable to impose operational and financial penalties 
on Eligible Customers taking the three new transmission services as part of the 
replacement rate, given that these services are designed for Eligible Customers taking 
transmission service on behalf of Eligible Loads that are willing and able to limit their 
withdrawals from the transmission system under certain conditions, and there are 
significant reliability risks if Eligible Customers fail to do so.  However, we decline to 
adopt PJM’s proposed replacement rate.  First, we disagree that it is just and reasonable 
to disqualify an Eligible Customer from taking any of the new transmission services after 
the first instance of failing to follow a curtailment or load shedding directive, as 
discussed below.  We instead find that it is just and reasonable to establish an operational 
penalty whereby, after the second instance of failing to follow a curtailment or load 
shedding directive, PJM will terminate the transmission service agreement with the 
Eligible Customer taking Interim NITS, FCD, or NFCD transmission service on behalf of 
the Eligible Load.  We agree with PJM that there are significant reliability risks 
associated with failing to follow a curtailment or load shedding directive, but we find that 
PJM’s one strike proposal is unnecessarily strict.  We direct PJM to file, within 60 days 
 
1025 Id. at 15-16. 
1026 Constellation May 11 Answer at 8-9. 
1027 Id. at 9. 
1028 Id. at 9-10.

Docket No. EL25-49-002, et al. 
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of the date of issuance of this order, a compliance filing to revise its Tariff consistent 
with these findings.   
 Second, we find that it is just and reasonable to establish an operational penalty of 
suspension in service for a period of up to 120 days for an Eligible Customer taking 
Interim NITS, FCD, and/or NFCD transmission service after the first misoperation of 
necessary control technologies and/or protection systems given the reliability risks 
associated with such misoperation.  However, as above, we disagree with PJM’s proposal 
regarding disqualification, and we instead find that it is just and reasonable to establish an 
operational penalty whereby, after the second misoperation of necessary control 
technologies and/or protection systems, PJM will terminate the transmission service 
agreement with the Eligible Customer taking Interim NITS, FCD, and/or NFCD 
transmission service on behalf of Eligible Load.  We direct PJM to file, within 60 days of 
the date of issuance of this order, a compliance filing to revise its Tariff consistent with 
these findings.   
 Third, we find that it is just and reasonable to subject an Eligible Customer taking 
any of the three new transmission services on behalf of Eligible Load to financial 
penalties in any circumstance where the transmission customer uses transmission service 
that it has not reserved.  We thus direct the PJM transmission owners to file, within             
60 days of the date of issuance of this order, a compliance filing that effectuates Indicated 
TOs’ proposed framework for financial penalties for Eligible Customers taking one of the 
three new transmission services that withdraw from the transmission system in excess of 
their contract demand level (i.e., for unreserved use).  
 Before addressing each topic in turn, as an initial matter, we disagree with 
protesters that operational penalties, either for failure to follow a curtailment or load 
shedding directive, or for misoperation of necessary control technologies and/or 
protection systems, “diverg[e] from” or were “not contemplated” in the December 
Order.1029  The financial penalties that the Commission required only apply to Eligible 
Customers’ unreserved use of the transmission system and are consistent with the 
Commission’s directives in the December Order.1030  The Commission has previously 
found that transmission customers should be subject to unreserved use penalties in 
circumstances where a transmission customer uses transmission service in excess of its 
 
1029 Constellation Response Brief at 19; Vistra Response Brief at 29. 
1030 December Order, 193 FERC ¶ 61,217 at P 212 (directing a penalty rate for 
excess withdrawals of energy from the transmission system by an Eligible Customer 
taking FCD transmission service on behalf of a Co-Located Load); id. P 217 (directing 
same as to excess withdrawals by an Eligible Customer taking NFCD transmission 
service on behalf of a Co-Located Load).

Docket No. EL25-49-002, et al. 
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reserved capacity or if it uses transmission service where it does not have a reservation, 
and as discussed further below, we find it just and reasonable that an Eligible Customer 
taking any of the three new transmission services on behalf of Eligible Load incur a 
financial penalty for unreserved use of the transmission system.1031  But the Commission 
also directed briefing broadly on the rates, terms, and conditions of the new transmission 
services, including “other remedial action[s]” in addition to financial penalties, as 
pertinent to this question.1032  We find that an operational penalty for Eligible Customers 
taking Interim NITS, FCD transmission service, and/or NFCD transmission service on 
behalf of Eligible Load for misoperation of necessary control technologies and/or 
protection systems is consistent with the December Order’s finding that Eligible 
Customers may take Interim NITS, FCD transmission service, and/or NFCD transmission 
service because it is the use of necessary control technologies and/or protection systems 
that effectively limits their energy withdrawals from the transmission system.1033  The 
Commission in the December Order also broadly sought briefing on the appropriate 
procedures to govern circumstances under which PJM curtails an Eligible Customer 
taking any of the three new transmission services, and we find that an operational penalty 
for an Eligible Customer taking the new transmission services on behalf of Eligible Load 
failing to follow a curtailment or load shedding directive is within the scope of provisions 
that we can consider as part of establishing curtailment procedures for the three new 
transmission services.      
a. 
Failure to Follow Curtailment or Load Shedding Directive 
 We find that it is just and reasonable to establish an operational penalty for an 
Eligible Customer taking any of the new transmission services on behalf of Eligible Load 
after the second instance of failing to follow a curtailment or load shedding directive.  
Specifically, we find that it is just and reasonable for PJM to terminate the transmission 
service agreement with the Eligible Customer taking Interim NITS, FCD transmission 
service, or NFCD transmission service on behalf of Eligible Load after the second 
instance of failing to follow a curtailment or load shedding directive.  We direct PJM to 
file, within 60 days of the date of issuance of this order, a compliance filing to revise its 
Tariff consistent with this finding.  PJM persuasively argues that there are significant 
reliability risks associated with failure to curtail, and “financial penalties, alone, are not 
sufficient to incentivize Eligible Customers to comply with Load Shed and 
Curtailment.”1034  However, we agree with concerns raised in the record that PJM’s 
 
1031 Order No. 890, 118 FERC ¶ 61,119 at P 834.  
1032 December Order, 193 FERC ¶ 61,217 at P 219. 
1033 Id. P 205; see supra Part VI.C. 
1034 PJM Initial Brief at 41-42, 45, 50.

Docket No. EL25-49-002, et al. 
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proposal to disqualify an Eligible Customer taking one of the three new transmission 
services on behalf of Eligible Load from continuing to take any of those services is 
unnecessarily strict.  When considering the need to ensure reliability is preserved, as well 
as to allow Eligible Customers taking transmission service on behalf of Eligible Load to 
adapt to a new transmission service paradigm, we find that, on balance, complete 
disqualification is excessive because it would impose penalties on the Eligible Customer 
that apply to all of its transmission service agreements, even those for which it has 
followed all curtailment or load shedding directives.  However, we agree with PJM that a 
strict operational penalty will deter conduct contrary to the fundamental principle upon 
which the new transmission services required by the December Order were based, which 
is that Eligible Customers taking service on behalf of Co-Located Loads are willing and 
able to limit their energy withdrawals from the transmission system under certain 
conditions.1035  We therefore find, as part of the just and reasonable replacement rate, that 
the transmission service agreement with the Eligible Customer taking Interim NITS, FCD 
transmission service, or NFCD transmission service on behalf of Eligible Load should be 
terminated on the second instance of failing to follow a curtailment or load shedding 
directive.  The Eligible Customer will remain eligible to take the three new transmission 
services on behalf of other Eligible Loads through its other transmission service 
agreements.  NITS remains an option for an Eligible Customer disqualified from taking 
one of the new transmission services; however, such Eligible Customer may not begin 
taking NITS until all necessary Network Upgrades are completed.1036 
 Recognizing that we are not adopting the exact penalty framework for failing to 
follow a curtailment or load shedding directive that PJM proposes, we nevertheless 
disagree with many of protesters’ arguments on this matter.  Joint Co-Location 
Developers, for example, argue that disqualification is not necessary because 
transmission owners can manually disconnect a facility.  This argument supports PJM’s 
premise that a financial penalty alone cannot deter the Eligible Customer taking one of 
the three new transmission services on behalf of Co-Located Load from failing to control 
unauthorized withdrawals; instead, it unreasonably and unnecessarily shifts the 
responsibility to manage complying with the Tariff and the terms of the transmission 
service from the Eligible Customer to the transmission owners.  Joint Co-Location 
 
1035 December Order, 193 FERC ¶ 61,217 at P 177 (“we also find that PJM’s 
Tariff is unjust and unreasonable because it does not include transmission services that 
reflect Eligible Customers taking service on behalf of Co-Located Loads that are willing 
and able to limit their energy withdrawals from the transmission system under certain 
conditions.”). 
1036 See PJM Initial Brief at 43 (“Importantly, however, such an Eligible Customer 
may take NITS, which would begin after all necessary upgrades are placed into 
service.”).

Docket No. EL25-49-002, et al. 
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Developers also claim that disqualification is disproportionate and may not send an 
actionable signal without “fault or materiality elements.”  This argument is misplaced, as 
PJM’s requirements for the new transmission services make the Eligible Customer’s 
responsibilities clear and actionable:  prior to commencement of service, the Eligible 
Customer must demonstrate to PJM’s satisfaction that it can fully comply with load 
shedding and curtailment procedures.  Lastly, Joint Co-Location Developers suggest that 
the Commission’s approval of a non-performance charge rate for capacity resources that 
fail to perform in emergency events means that an Eligible Customer that fails to follow a 
curtailment or load shedding directive can be sufficiently penalized through a similar 
charge.  Joint Co-Location Developers allege that failure to respond or perform in both 
these circumstances is similar from a resource adequacy perspective.  We disagree that 
the two are comparable.  Capacity resources are purchased to meet the needs of 
transmission customers taking existing firm service, such as NITS.  As PJM explains in 
its initial brief, the choice to take NITS decreases the likelihood of significant issues 
arising from failure to curtail.1037  By contrast, the Commission created the three new 
transmission services to reflect that Eligible Customers taking transmission service on 
behalf of Co-Located Load are willing and able to limit their energy withdrawals from 
the transmission system under certain conditions that are different than those under which 
Network Customers take NITS.1038  For these reasons, we find that it is just and 
reasonable to subject Eligible Customers on behalf of such loads to a stricter penalty 
regime. 
 We also disagree with Constellation’s suggestion that the Commission should 
adopt SPP’s approach for CHILLS, which contains only penalties for exceeding the 
transmission customer’s reserved capacity.1039  The Commission has permitted regional 
 
1037 Id. at 48-49. 
1038 December Order, 193 FERC ¶ 61,217 at P 2; see, e.g., id. P 208 
(distinguishing an Eligible Customer’s rights under FCD transmission service in contrast 
to NITS). 
1039 Sw. Power Pool, Inc., 195 FERC ¶ 61,196, at 98 (2026).

Docket No. EL25-49-002, et al. 
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variation among RTOs/ISOs1040 and need only explain its choice and how it has chosen a 
just and reasonable rate.1041   
 We also find that ODEC has not demonstrated a need, nor does the record 
developed in this paper hearing otherwise reflect a need, to establish protections for 
transmission owners if the Eligible Customer may experience damages as a result of the 
transmission owner disconnecting the Eligible Customer.  Lastly, with respect to Joint 
Co-Location Developers’ concern that PJM’s proposed disqualification rules will 
dissuade Eligible Customers from taking the new transmission services because of the 
risk of stranding or undermining investments in the new transmission services, we note 
that an Eligible Customer is not required to take the new transmission services and may 
elect to take NITS if that transmission service option better reflects the Eligible 
Customer’s use of the transmission system and risk profile.1042   
 
1040 See, e.g., Reg’l Transmission Orgs., Order No. 2000, FERC Stats. & Regs.                 
¶ 31,089, at 31,073 (1999) (cross-referenced at 89 FERC ¶ 61,285), order on reh’g, 
Order No. 2000-A, FERC Stats. & Regs. ¶ 31,092 (2000) (cross-referenced at 90 FERC  
¶ 61,201), aff’d sub nom. Pub. Util. Dist. No. 1 of Snohomish Cnty. v. FERC, 272 F.3d 
607 (D.C. Cir. 2001) (stating there is no “one size fits all” approach to RTO governance); 
Offer Caps in Mkts. Operated by Reg’l Transmission Orgs. & Indep. Sys. Operators, 
Order No. 831, 157 FERC ¶ 61,115, at P 147 (2016), order on reh’g & clarification, 
Order No. 831-A, 161 FERC ¶ 61,156 (2017) (permitting regional variation for treatment 
of incremental energy offers above $1,000/MWh that the RTO/ISO or Marketing 
Monitoring Unit cannot verify prior to the start of the market clearing process); 
Wholesale Competition in Regions with Organized Elec. Mkts., Order No. 719,                        
125 FERC ¶ 61,071, at P 62 (2008), order on reh’g, Order No. 719-A, 128 FERC                     
¶ 61,059, order on reh’g, Order No. 719-B, 129 FERC ¶ 61,252 (2009) (permitting 
regional variation for RTOs/ISOs developing requirements for demand response 
resources participating in ancillary service markets).   
1041 See ExxonMobil Oil Corp. v. FERC, 487 F.3d 945, 955 (D.C. Cir. 2007) (“We 
need not decide whether the Commission has adopted the best possible policy as long as 
the agency has acted within the scope of its discretion and reasonably explained its 
actions.”); Cities of Batavia v. FERC, 672 F.2d 64, 84 (D.C. Cir. 1982) (“[T]he billing 
design need only be reasonable, not theoretically perfect.”). 
1042 See PJM Reply Brief at 47 (arguing that disqualification penalties reflect that 
Eligible Customers take the level of transmission service that aligns with their 
demonstrated use of the transmission system).

Docket No. EL25-49-002, et al. 
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b. 
Misoperation of Necessary Control Technologies and/or 
Protection Systems 
 We find that it is just and reasonable to establish an operational penalty of 
suspension in service for a period of up to 120 days for an Eligible Customer taking 
Interim NITS, FCD, and/or NFCD transmission service on behalf of Eligible Load after 
the first misoperation of necessary control technologies and/or protection systems.  
However, as noted above, we disagree with PJM’s proposal regarding disqualification, 
and we instead find that it is just and reasonable to establish an operational penalty 
whereby, after the second misoperation of necessary control technologies and/or 
protection systems, PJM will terminate the transmission service agreement with the 
Eligible Customer taking Interim NITS, FCD transmission service, or NFCD 
transmission service on behalf of Eligible Load.  We direct PJM to file, within 60 days of 
the date of issuance of this order, a compliance filing to revise its Tariff consistent with 
these findings.  
 We agree with PJM that there are significant reliability risks associated with 
misoperation of special protection schemes, and that “financial penalties, alone, are not 
sufficient to incentivize Eligible Customers to comply with . . . control technology and 
protection system obligations.”1043  We find that this replacement rate serves to deter 
conduct contrary to the fundamental principle around which the new transmission 
services created by the Commission were based, i.e., that Eligible Customers taking 
service on behalf of Co-Located Loads are willing and able to limit their energy 
withdrawals from the transmission system under certain conditions.1044  Moreover, we 
agree with PJM that, after the first misoperation of necessary control technologies and/or 
protection systems, suspension of service for a period of up to 120 days is reasonable to 
allow for an analysis by PJM, and the affected transmission owner(s) as necessary, of the 
operational performance of the necessary control technologies and/or protection systems.  
 
1043 PJM Initial Brief at 41-42, 45, 50. 
1044 December Order, 193 FERC ¶ 61,217 at P 177 (“we also find that PJM’s 
Tariff is unjust and unreasonable because it does not include transmission services that 
reflect Eligible Customers taking service on behalf of Co-Located Loads that are willing 
and able to limit their energy withdrawals from the transmission system under certain 
conditions.”); see id. P 205 (“We note that, in general, special protection schemes allow 
Eligible Customers on behalf of Co-Located Load to effectively limit their withdrawals 
from the transmission system.  For these reasons, in these instances where the                       
Co-Location Arrangement includes special protection schemes that limit its energy 
withdrawals, we find that it is a just and reasonable replacement rate to allow an Eligible 
Customer taking transmission service on behalf of such load to take and be charged for 
new types of transmission service that are alternatives, and not equivalent, to NITS.”).

Docket No. EL25-49-002, et al. 
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In response to the Indicated TOs, we find that it is reasonable that the Tariff provide that 
service may resume following PJM’s approval, as well as the relevant transmission 
owner’s approval of the necessary control technologies and/or protection systems for 
consistency with the transmission owner’s technical standards. 
 However, we reject PJM’s proposal not to apply such a penalty to Eligible 
Customers taking FCD transmission service on behalf of Co-Located Load, consistent 
with our findings above that Eligible Customers taking FCD transmission service on 
behalf of Co-Located Load must also have necessary control technologies and/or 
protection systems to limit their energy withdrawals from the transmission system to their 
contract demand level.1045  We also disagree with protesters’ arguments opposing PJM’s 
proposal to establish an operational penalty for misoperation of necessary control 
technologies and/or protection systems.  Vistra suggests that PJM’s proposal unduly 
discriminates against Co-Location Arrangements as compared to other entities using 
special protection schemes, but this penalty proposal (which Vistra mistakenly alleges 
applies only to special protection schemes) is not relevant to existing transmission 
services in PJM.1046  By contrast, as discussed above, correct operation of necessary 
control technologies and/or protection systems is foundational to the new transmission 
services.  Vistra’s separate claim that PJM’s proposal is unduly discriminatory “insofar as 
it treats unreserved use of the transmission system by point-to-point customers differently 
from unreserved use by customers taking these new transmission services” is misplaced.  
In contrast to Eligible Customers taking Interim NITS, FCD transmission service, and/or 
NFCD transmission service on behalf of Eligible Load, PTPS customers are not required 
to establish necessary control technologies and/or protection systems in order to take 
PTPS.1047  We also find unpersuasive Joint Co-Location Developers’ allegation that this 
operational penalty is even more excessive, as compared to a penalty for failure to follow 
curtailment or load shedding directives, because misoperation without withdrawal does 
not risk system harm.1048  We agree with PJM that “[w]hen a control technology or 
protection scheme misoperates, there can be serious consequences.”1049  Where PJM 
 
1045 See supra Part VI.C. 
1046 See PJM Initial Brief at 47 (justifying its proposal to allow that an Eligible 
Customer disqualified from the new transmission services may take NITS because 
“NITS, in and of itself, addresses Curtailment, Load Shed, and control technology or 
protection scheme misoperation risk”). 
1047 Id. at 50 (“PJM supports a penalty for unreserved use in addition to the 
disqualification and pause-in-rules discussed above.”); see id. at 41 (Table 1 (Penalties)). 
1048 Joint Co-Location Developers Response Brief at 26. 
1049 PJM Initial Brief at 43, 45; PJM Reply Brief at 52-53.

Docket No. EL25-49-002, et al. 
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plans and operates the system around an assumption that necessary control technologies 
and/or protection systems will work, unexpected system behavior due to misoperation 
risks system reliability regardless of whether withdrawals occur, and we find that it is 
reasonable not to rely only on financial penalties to mitigate these risks. 
 We disagree with Constellation’s suggestion that the Commission should adopt 
SPP’s approach from CHILLS, which contains only penalties for exceeding the 
transmission customer’s reserved capacity,1050 but not suspension or disqualification, for 
the same reasons discussed above.   
 We agree with NOVEC that PJM’s proposed penalty language to disqualify the 
Eligible Customer as a whole from taking the relevant transmission service is not just and 
reasonable.  Instead, we direct PJM to propose on compliance Tariff provisions providing 
that, after the second misoperation of necessary control technologies and/or protection 
systems pertaining to a transmission service agreement governing an Eligible Customer 
taking Interim NITS, FCD transmission service, and/or NFCD transmission service on 
behalf of Eligible Load, PJM will terminate the transmission service agreement.  The 
Eligible Customer could still take transmission service, including Interim NITS, FCD 
transmission service, and NFCD transmission service, on behalf of other loads through 
other transmission service agreements. 
 ODEC asserts that PJM’s implementation of its penalties must not subject ODEC 
or its member distribution cooperatives to service interruptions or disqualification, or 
financial penalties, as a result of requiring ODEC to serve as the Eligible Customer.  The 
Commission set a replacement rate in the December Order applicable to Eligible 
Customers taking transmission service on behalf of Co-Located Load.  The operational 
(and financial) penalties we establish in this order apply to Eligible Customers who elect 
to take the new transmission services on behalf of Eligible Load and who do not comply 
with the terms and conditions of the new transmission services, including misoperation of 
necessary control technologies and/or protection systems.  The December Order does not 
require that Eligible Customers on behalf of Co-Located Load take one of the new 
transmission services and they may choose to take NITS instead.  The Co-Located Load 
cannot force an Eligible Customer to take a type of transmission service it does not wish 
to take.  As the Commission explained in the December Order, NITS remains a just and 
reasonable transmission service option that an Eligible Customer on behalf of a                     
Co-Located Load may choose.1051   
 
1050 Sw. Power Pool, Inc., 195 FERC ¶ 61,196 at 98. 
1051 December Order, 193 FERC ¶ 61,217 at P 195.

Docket No. EL25-49-002, et al. 
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c. 
Unreserved Use of the Transmission System 
 We find that it is just and reasonable to impose a financial penalty on an Eligible 
Customer taking any of the new transmission services on behalf of Eligible Load for 
unreserved use of the transmission system.  We find that it is just and reasonable to use 
Indicated TOs’ two-part penalty framework and to apply, within that framework, a 
penalty rate that is twice the rate we establish in this order for FCD transmission 
service.1052  Indicated TOs propose a base penalty charge for each hour in which the 
Eligible Customer’s reserved service limit is exceeded at the Point of Interconnection 
during at least one five-minute interval (Exceedance Hour) and a penalty ratchet when 
exceedances occur repeatedly.1053  Specifically, Indicated TOs propose that, if more than 
one Exceedance Hour occurs on the same day, then an additional daily penalty applies; if 
exceedances occur on multiple days within the same week, an additional weekly penalty 
applies; if exceedances occur in multiple weeks within the same month, then an 
additional monthly penalty applies; and if exceedances occur in multiple months within 
the same year, then an additional annual penalty applies.1054  We agree with Indicated 
TOs that progressively increasing the consequences of repeated penalties encourages 
Eligible Customers to manage their usage consistent with their reserved transmission 
service limit.1055  We note that Indicated TOs submit testimony indicating that they 
propose to distribute revenues collected from financial penalty charges on a monthly 
basis to Eligible Customers taking NITS and FCD transmission service.  However, we 
find that unreserved use penalties should be distributed to all non-offending transmission 
 
1052 See Order No. 890, 118 FERC ¶ 61,119 at P 848 (“As a result, we establish a 
rebuttable presumption that unreserved use penalties no greater than twice the firm   
point-to-point rate for the penalty period defined above are just and reasonable.”); id.       
P 846 (basing penalty charges on the period of unreserved use and determining that, as a 
general rule, more than one assessment for a given duration will increase the penalty 
period to the next longest duration). 
1053 Indicated TOs Response Brief at 12 (“When a Co-Located Load exceeds its 
reserved transmission service limit, the base penalty charge will be assessed for any hour 
in which at least one five-minute interval occurs during which a customer’s metered load 
at the point of interconnection exceeds its reserved transmission service.”); Indicated TOs 
Reply Brief at 16. 
1054 Indicated TOs Reply Brief at 16; Indicated TOs Reply Brief, Ex.                  
No. PTO-0005 at 7. 
1055 Indicated TOs Response Brief at 12-13; Indicated TOs Reply Brief at 17.

Docket No. EL25-49-002, et al. 
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customers consistent with Order No. 890.1056  We direct the PJM transmission owners 
to file, within 60 days of the date of issuance of this order, a compliance filing consistent 
with these findings.  
E. 
Anti-Toggling Mechanisms for Firm Contract Demand Transmission 
Service 
 In the December Order, the Commission found that FCD transmission service 
should have a minimum term of one year, but that PJM should propose an anti-toggling 
mechanism for Eligible Customers switching between FCD and NFCD transmission 
service.1057 
1. 
Initial Briefs 
 PJM proposes an anti-toggling mechanism to prevent transmission customers from 
switching between FCD and NFCD transmission services by providing that the portion of 
the Co-Located Load served by FCD transmission service is not eligible to be served by 
NFCD transmission service for five years following the effective date of the Service 
Agreement.  Conversely, PJM explains, it does not bar Co-Located Load served by 
NFCD transmission service from being served by FCD transmission service in future 
years.  However, PJM proposes an exception if there is a physical change to the                    
Co-Located Generator that would materially alter the MW level dedicated to the load or 
to the Co-Located Load that would materially alter the MW level of its gross demand.1058  
PJM argues this exception is necessary to ensure that, if an Eligible Customer materially 
changes either the generation capacity or the load on a gross demand basis, the Tariff 
provides flexibility to determine whether FCD or NFCD transmission service should be 
taken for the new incremental portion. 
 PJM also maintains that its proposed 42-month notice of termination acts as an 
anti-toggling device in a manner similar to the five-year commitment period applicable to 
the Fixed Resource Requirement alternative in the PJM capacity market.  PJM explains 
that its notice period recognizes that PJM incorporates these loads in the capacity market, 
 
1056 See Order No. 890, 118 FERC ¶ 61,119 at P 860 (“Unreserved use penalties 
are assessed against transmission customers and should, therefore, be distributed to all 
non-offending transmission customers, whether affiliated with the transmission provider 
or not.”). 
1057 December Order, 193 FERC ¶ 61,217 at P 213. 
1058 PJM Initial Brief at 53-54.

Docket No. EL25-49-002, et al. 
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and it would unreasonably shift costs to other loads if Co-Located Loads could avoid 
capacity charges incurred on their behalf by terminating service prematurely.1059 
 Indicated TOs propose a five-year minimum commitment period for FCD 
transmission service, arguing that doing so is necessary to ensure that FCD transmission 
service customers cannot trigger Network Upgrades and then cease taking service, 
thereby potentially shifting costs to other transmission customers, and because it mirrors 
the commitment period for loads seeking to procure their own capacity.1060  Indicated 
TOs argue that, where Network Upgrades are attributable to FCD transmission service 
customers, separate payment guarantees may be required to prevent Network Customers 
from being left “holding the bag” if an FCD transmission service customer exits the 
system before the costs of the Network Upgrades are fully paid.1061  Finally, Indicated 
TOs recommend that the Commission adopt the same requirements for FCD transmission 
service that apply to notices of termination for NITS, including the 42-month notice 
period.1062 
2. 
Response Briefs 
 NOVEC states that it supports PJM’s five‑year minimum service commitment and 
42‑month notice requirement.  NOVEC asserts that the minimum service commitment 
sends timely price signals to the capacity market, enhances market stability, and 
minimizes upgrade‑related risks if a Co-Located Load withdraws.  NOVEC notes that the 
notice-of-termination period is identical to the requirements for termination of NITS and 
prevents Co-Located Loads from avoiding capacity charges by prematurely terminating 
their agreement.1063 
3. 
Determination 
 Except as noted below, we find PJM’s proposed anti-toggling mechanism to be a 
just and reasonable replacement rate.  In particular, we find that PJM’s proposal to 
prohibit, for a period of five years, Eligible Customers taking transmission service on 
behalf of a Co-Located Load from taking NFCD transmission service for any portion of 
 
1059 Id. at 54-55. 
1060 Indicated TOs Initial Brief at 21 (citing December Order, 193 FERC ¶ 61,217 
at P 213). 
1061 Id. at 21 n.50. 
1062 Id. at 21 & n.52. 
1063 NOVEC Response Brief at 15-16.

Docket No. EL25-49-002, et al. 
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Co-Located Load served by FCD transmission service will ensure that such Eligible 
Customers do not attempt such a switch based on expected capacity market conditions, 
consistent with the December Order.1064  We further find that PJM’s proposed 42-month 
notice of termination provision applicable to FCD transmission service customers mirrors 
that applicable to Network Customers and recognizes that PJM has procured capacity on 
their behalf.  We direct PJM to file, within 60 days of the date of issuance of this order, a 
compliance filing to revise its Tariff consistent with these findings. 
 However, we find PJM’s proposed exceptions regarding changes to the                     
Co-Located Generator or Co-Located Load are not just and reasonable to the extent they 
would permit Eligible Customers to decrease the level of contract demand for FCD 
transmission service they take on behalf of an Eligible Load, and increase the level of 
contract demand for NFCD transmission service, without being subject to the                     
anti-toggling provision.  The Commission found that the anti-toggling mechanism should 
ensure Eligible Customers taking transmission service on behalf of Co-Located Loads 
cannot switch from FCD to NFCD transmission service based on expected capacity 
market conditions.1065  As such, PJM’s proposal is not consistent with the December 
Order, and we direct PJM to propose an anti-toggling mechanism without an exception 
for Eligible Customers taking FCD transmission service on behalf of Eligible Load in a 
compliance filing within 60 days of the date of issuance of this order.  
 We also reject Indicated TOs’ proposal for a five-year minimum commitment 
period.  As Indicated TOs acknowledge, the Commission required in the December Order 
that the minimum term for FCD transmission service should be one year.1066  As such, we 
find that Indicated TOs’ arguments in support of its proposal are an untimely request for 
rehearing of the December Order.1067 
 
1064 December Order, 193 FERC ¶ 61,217 at P 213. 
1065 Id. 
1066 Id. 
1067 See, e.g., ISO New Eng. Inc., 132 FERC ¶ 61,098 at P 12 (“The Commission 
has held that requests to alter a compliance filing in a manner that differs from the order 
requiring the compliance filing constitute a collateral attack on the order requiring the 
compliance filing.”).

Docket No. EL25-49-002, et al. 
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F. 
Communications, Alarm, SCADA, or Other Requirements 
1. 
Initial Briefs 
 PJM proposes to develop telemetry requirements for Co-Located Load so that 
PJM can monitor the status of demand placed on PJM’s transmission system, including 
unreserved use, to ensure reliability.1068  PJM states that it still determining the scope of 
the tools and requirements necessary to limit withdrawals that exceed reserved use.  PJM 
also proposes to develop data exchange and metering requirements for Co-Located Load 
that may be similar to those applicable to generation.  PJM proposes to develop the 
capability to differentiate more granularly between the transmission services available to 
Eligible Customers on behalf of Co-Located Load because they are prioritized 
differently.  PJM maintains that Eligible Customers would need to take these different 
forms of transmission service on different feeders, or cables leaving substations, to 
ultimately serve the Co-Located Load. 
 PJM next proposes to develop requirements and identify any relevant NERC rules 
to ensure that relay settings are consistent with the design of the necessary control 
technologies and/or protection systems, as set forth in each Service Agreement.1069  PJM 
asserts that transmission owners must be heavily involved in ensuring that necessary 
control technology and/or protection systems are properly designed.  PJM explains that it 
proposes technical requirements that must be in place prior to commencement of service 
because there are significant risks introduced by the necessary control technology and 
protection systems.  PJM also proposes to make changes to core Markets and Operations 
systems to incorporate the information provided by Eligible Customers and Co-Located 
Load to ensure reliability of the PJM transmission system.  
2. 
Response Briefs 
 Indicated TOs support PJM’s proposal in its initial brief to develop telemetry 
requirements and require Co-Located Load to meet such requirements in order to monitor 
Co-Located Loads’ use of the transmission system.1070 
3. 
Determination 
 We decline to direct PJM’s proposed telemetry, data exchange, metering, and 
relay setting requirements as the replacement rate because PJM has not provided 
 
1068 PJM Initial Brief at 59-61. 
1069 Id. at 60-61. 
1070 Indicated TOs Response Brief at 10-11.

Docket No. EL25-49-002, et al. 
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sufficient detail to find they are just and reasonable.  PJM by its own admission has not 
finished determining the scope of what might be necessary to limit energy withdrawals 
from the transmission system.  Accordingly, and consistent with our determination above 
to extend the three new transmission services set forth in the December Order to Eligible 
Customers taking service on behalf of load with BTMG that are willing and able to limit 
their energy withdrawals from the transmission system under certain conditions, we 
direct PJM to file, within 60 days of the date of issuance of this order, a compliance filing 
with Tariff revisions it deems necessary for PJM to be able to ensure that an Eligible 
Customer has adequate telemetry, data exchange, and metering requirements such that 
PJM may monitor the Eligible Load’s use of the transmission system, limit withdrawals, 
and ensure relay settings are consistent with necessary control technologies and/or 
protection systems. 
G. 
Curtailment Procedures for Interim NITS and Non-Firm Contract 
Demand Transmission Service 
1. 
Initial Briefs 
 PJM proposes that Interim NITS and NFCD transmission service will be curtailed 
before FCD transmission service and NITS.1071  PJM also proposes that it may curtail 
Interim NITS or NFCD transmission service prior to dispatching the Pre-Emergency 
Load Response Program or in response to a transfer capability shortage as a result of 
system reliability conditions.  PJM proposes that FCD transmission service be treated 
equal to NITS for purposes of curtailment.1072  PJM states that it reserves the right to 
curtail the three new transmission services on a non-discriminatory basis for the purpose 
of making necessary adjustments to, changes in, or repairs on its lines, substations, and 
facilities, and in cases where continuation of service would endanger persons or property.  
PJM proposes that the Eligible Customer must shed load in accordance with previously 
established procedures under the relevant Service Agreement. 
 PJM acknowledges that its system does not differentiate between different types of 
transmission service because all load within PJM is currently served by NITS.1073  Thus, 
PJM explains, core systems would need to be implemented to enable sufficient 
granularity when shedding an Eligible Customer’s Co-Located Load being served by two 
different levels of transmission service, i.e., both FCD and NFCD transmission services.  
PJM clarifies that, assuming these core system design changes can be implemented, 
Eligible Customers taking transmission service on behalf of Co-Located Load would 
 
1071 PJM Initial Brief at 63. 
1072 Id. at 64. 
1073 Id. at 65-66.

Docket No. EL25-49-002, et al. 
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need to take different forms of transmission service on different feeders, or cables leaving 
substations, to ultimately serve Co-Located Load. 
2. 
Response Briefs 
 Joint Co-Location Developers argue that PJM fails to adequately clarify when and 
how NFCD transmission service and Interim NITS shall be curtailed, in particular the 
curtailment trigger.1074  Joint Co-Location Developers maintain that the curtailment 
trigger significantly affects rates and service and is realistically susceptible of 
specification and should be included in the tariff.  Joint Co-Location Developers assert 
that PJM does not clarify whether and how it will determine curtailment priority among 
its different classes of non-firm service, including Non-Firm PTPS, NFCD transmission 
service, and Interim NITS. 
 Constellation argues that it is discriminatory to require different feeders and would 
unnecessarily delay Co-Location Arrangements.1075  At minimum, Constellation asserts 
that such a requirement should not apply in the case of Interim NITS since the                       
Co-Located Load is not taking both firm and non-firm service. 
 AEU/SEIA explain that the December Order established a curtailment hierarchy in 
accordance with which Interim NITS and NFCD transmission service will be curtailed 
before NITS and FCD transmission service and before pre-emergency demand response 
resources are dispatched.1076  AEU/SEIA claim that PJM’s implementation of this 
hierarchy is contradictory because PJM states that it “may” curtail Interim NITS and 
NFCD transmission service prior to dispatching the Pre-Emergency Load Response 
Program and that it “will” curtail Interim NITS and NFCD transmission service before 
demand response resources are called upon to reduce load.1077  AEU/SEIA argue that this 
inconsistency must be resolved because a customer considering whether to take Interim 
NITS or NFCD transmission service needs to know whether curtailment before                      
pre-emergency demand response is a certainty or a possibility. 
 AEU/SEIA contend that PJM has provided no information about the conditions 
that would actually trigger curtailment of Interim NITS or NFCD transmission service in 
practice and that, because these are novel services, no historical curtailment data 
 
1074 Joint Co-Location Developers Response Brief at 17. 
1075 Constellation Response Brief at 29-30. 
1076 AEU/SEIA Response Brief at 11. 
1077 Id. (citing PJM Initial Brief at 63-64).

Docket No. EL25-49-002, et al. 
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exists.1078  AEU/SEIA further argue that modeling of expected curtailment frequency and 
duration or examples of how curtailment would operate for a hypothetical Co-Location 
Arrangement must be provided in order for customers to make informed business 
decisions on the transmission service that best serves their needs.  If it is not, AEU/SEIA 
argue that prospective customers will default to taking NITS.  AEU/SEIA request that the 
Commission require PJM to develop and publish historical analysis and forward-looking 
modeling of curtailment frequency and duration for Interim NITS and NFCD 
transmission service, as informed by historical system conditions in PJM and broken 
down by zone.  AEU/SEIA also argue that PJM should set out in its reply brief how it 
intends to operationalize curtailment for NFCD transmission service, including the 
sequence in which Co-Located Loads will be curtailed relative to other non-firm services 
and the mechanism by which curtailment instructions will be communicated and 
enforced.  Without this sequence, AEU/SEIA claim that neither the Commission nor 
affected parties can evaluate whether PJM’s proposed curtailment framework is 
consistent with the December Order’s requirement that NFCD transmission service be 
available “as needed during normal, non-emergency system operating conditions.”1079 
3. 
Reply Briefs 
 Earthjustice argues that the Commission should require PJM to clarify how and 
when PJM will enforce its curtailment procedures, including:  (1) how PJM will 
communicate its curtailment directives; (2) how and when transmission providers will 
determine that load shed is necessary, which loads will be curtailed first, and at what 
stage curtailments will occur; and (3) how a data center will be disqualified and the 
timeline for that disqualification.1080   
 Industrials/Amtrak argue that many traditional large loads cannot shut off 
immediately if their on-site generation trips.1081   
 
1078 Id. at 12-14. 
1079 Id. at 14 (quoting December Order, 193 FERC ¶ 61,217 at P 215). 
1080 Earthjustice Reply Brief at 14, 16. 
1081 Industrials/Amtrak Reply Brief at 6.

Docket No. EL25-49-002, et al. 
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4. 
Answers 
 Constellation argues that PJM inappropriately attempts in its reply brief to 
reinstate a curtailment criterion of a capacity/reserve shortage and that the Commission 
rejected this element of PJM’s proposed Option 7 in the December Order.1082   
5. 
Determination 
 We find PJM’s proposed curtailment hierarchy for Interim NITS, FCD 
transmission service, and NFCD transmission service to be just and reasonable.  PJM’s 
proposal to treat FCD transmission service as comparable to NITS is consistent with the 
December Order,1083 as is PJM’s proposal to curtail Interim NITS and NFCD 
transmission service prior to firm transmission services.1084  In addition, we find PJM’s 
proposal to curtail Interim NITS and NFCD transmission service prior to deployment of 
its Pre-Emergency Load Response Program, or in response to a transfer capability 
shortage as a result of system reliability conditions, to be just and reasonable because it is 
consistent with how Non-Firm PTPS is curtailed.1085  We disagree with Constellation that 
PJM’s proposal to curtail Interim NITS during capacity or reserve shortages is 
inconsistent with the Commission’s findings in the December Order that PJM’s proposed 
construct for an interim transmission service was too broad and not sufficiently detailed 
to direct as a replacement rate.1086  Constellation misunderstands the December Order, 
which found it was not reasonable to allow the transitional period for Interim NITS to 
continue until any resource adequacy challenges associated with the addition of the     
Co-Located Load were addressed, and instead limited the transitional period to the time 
 
1082 Constellation May 11 Answer at 13 (citing December Order, 193 FERC 
¶ 61,217 at P 202). 
1083 See, e.g., December Order, 193 FERC ¶ 61,217 at P 208 (stating that FCD 
transmission service will have the same curtailment priority as existing firm transmission 
services). 
1084 See, e.g., id. P 201 (stating that Interim NITS “will be curtailed before existing 
firm transmission services and the new Firm Contract Demand Transmission Service”); 
id. P 215 (stating same with respect to NCFD transmission service). 
1085 See PJM, Intra-PJM Tariffs, OATT, § II, § 14.7 (Curtailment or Interruption of 
Service) (0.0.0) (describing PJM’s curtailment procedures for Non-Firm PTPS); PJM 
Manual 13:  Emergency Operations, Rev. 97 (eff. November 20, 2025), § 2.3.2. 
1086 Constellation May 11 Answer at 13 (citing December Order, 193 FERC 
¶ 61,217 at P 202).

Docket No. EL25-49-002, et al. 
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needed to complete any Network Upgrades identified in the study process.1087  The 
Commission did not find, as Constellation alleges, that Interim NITS could not be 
curtailed as a result of capacity or reserve shortages.  Here, we find that PJM’s proposal 
to curtail Interim NITS during capacity or reserve shortages is just and reasonable and 
consistent with both the nature of the transmission service as a non-firm transmission 
service for which Eligible Customers do not pay generation capacity charges, and the 
need to maintain reliability. 
 We disagree with commenters that PJM must provide specific details in its Tariff, 
such as the trigger and procedures for curtailment of Interim NITS and FCD or NFCD 
transmission services, or how PJM will enforce its curtailment procedures.  We find that 
requiring PJM to specify the curtailment priority of these new transmission services in its 
Tariff, while leaving specific implementation details in its manuals and individual service 
agreements, provides transmission customers sufficient certainty as to their priority 
relative to other transmission services and ensures that PJM has sufficient flexibility to 
preserve system reliability in varying operating conditions.1088  We find that it is just and 
reasonable and important to protect transmission system reliability to provide PJM with 
sufficient operational flexibility during emergency procedures to curtail transmission 
customers as needed to preserve reliability.1089 
 However, we find that PJM does not adequately explain its curtailment hierarchy 
amongst non-firm transmission services.  For example, while PJM states that it will 
curtail Interim NITS and NFCD transmission service prior to deployment of its           
Pre-Emergency Load Response Program, it does not detail if these transmission services 
will be curtailed before or after Non-Firm PTPS, or if curtailment priority within NFCD 
transmission service will be based on duration, as are curtailments for Non-Firm 
PTPS.1090  
 
1087 December Order, 193 FERC ¶ 61,217 at P 202. 
1088 See PJM, Intra-PJM Tariffs, OATT, § II.14.7 Curtailment or Interruption of 
Service (0.0.0) (describing PJM’s curtailment procedures for Non-Firm PTPS). 
1089 See Order No. 890-A, 121 FERC ¶ 61,297 at P 566 (“If the [conditional firm 
transmission] customer selects the annual hourly cap option, the transmission provider 
will have the flexibility to conditionally curtail the customer for any reliability reason 
during those hours, including but not limited to, the system condition(s) identified in the 
system impact study.”). 
1090  PJM, Intra-PJM Tariffs, OATT, § II.14.7 Curtailment or Interruption of 
Service (0.0.0).

Docket No. EL25-49-002, et al. 
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 We also find that PJM has not justified its assertion that an Eligible Customer 
taking different forms of transmission service on behalf of Co-Located Load would need 
to take those services on different feeders.  PJM states that this requirement is based on 
the need for core systems to be implemented to enable sufficient granularity when 
shedding an Eligible Customer’s Co-Located Load being served by two different levels 
of transmission service.1091  While we recognize that core systems will need to be 
implemented, PJM provides no explanation as to why these systems could not be 
sufficiently flexible as to accommodate a single feeder with two different levels of 
transmission service on it. 1092  
 Accordingly, we direct PJM to submit, within 60 days of the date of issuance of 
this order, a compliance filing to revise the Tariff to include the curtailment priorities for 
Interim NITS, FCD transmission service, and NFCD transmission service consistent with 
our findings above.  This language must specify that FCD transmission service shall be 
treated the same as NITS for the purposes of curtailment, and that Interim NITS and 
NFCD transmission service will be curtailed prior to deployment of PJM’s Pre-
Emergency Load Response Program, or in response to a transfer capability shortage as a 
result of system reliability conditions.  PJM’s submittal must also detail the curtailment 
priorities between Non-Firm PTPS, Interim NITS, and NFCD transmission service, 
including how or if PJM will prioritize transmission customers for curtailment based on 
duration of service.  Consistent with our determination above to extend the three new 
transmission services set forth in the December Order to Eligible Customers taking 
service on behalf of load with BTMG that are willing and able to limit their energy 
withdrawals from the transmission system under certain conditions, we further direct 
PJM to reflect this change in its compliance filing. 
H. 
Rates, Terms, and Conditions for Interim NITS 
1. 
Initial Briefs 
 PJM proposes to model the non-rate terms and conditions for Interim NITS on 
NITS.1093  PJM proposes that an Eligible Customer may take Interim NITS on behalf of 
Co-Located Load until Network Upgrades are complete, and then the customer will 
automatically convert to a Network Customer.  PJM states that an Eligible Customer 
receiving Interim NITS on behalf of Co-Located Load will receive non-firm transmission 
 
1091 PJM Initial Brief at 66. 
1092 For example, this system could assume that load on a feeder is firm up until 
the Eligible Customer’s Firm Contract Demand withdrawal limit, and non-firm above 
that contract demand amount. 
1093 PJM Initial Brief at 67-70.

Docket No. EL25-49-002, et al. 
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service for the delivery of energy to Co-Located Load.  PJM proposes that, upon receipt 
of request, PJM will determine the amount of Interim NITS that can be reliably provided 
based on the results of appropriate studies and in consultation with the affected 
transmission owner.  PJM proposes that, for Interim NITS, the Eligible Customer must 
meet certain conditions and appropriate technical requirements.  PJM proposes that the 
Eligible Customer have an ongoing obligation to notify PJM of material changes in the 
demand characteristics of the Co-Located Load and the supply characteristics of the Co-
Located Generator.  PJM explains that the Co-Location Arrangement cannot change 
during the term of the Interim NITS without discussion and possible further studies by 
PJM. 
 PJM proposes load shedding and curtailment provisions applicable to Interim 
NITS, including that prior to commencement of service, the Eligible Customer must 
demonstrate its ability to comply with PJM’s load shedding and curtailment 
procedures.1094  PJM proposes to require Eligible Customers taking Interim NITS to work 
with PJM and the affected transmission owners to establish necessary control 
technologies and/or protection systems.  PJM proposes that Eligible Customers will be 
assessed certain non-transmission-related rates, including:  (1) administrative service 
charges, (2) ancillary services charges except for regulation, (3) black start service 
charges based on gross demand, and (4) any redispatch costs.  PJM proposes a single 
Service Agreement specific to Eligible Customers serving Co-Located Load via Interim 
NITS or NITS.  Indicated TOs propose to apply the NITS rate to Eligible Customers 
taking Interim NITS.1095 
2. 
Response Briefs 
 Indicated TOs propose several clarifications to PJM’s illustrative Tariff 
provisions.1096  First, Indicated TOs propose revisions to section 702.4 to require an 
Eligible Customer to satisfy any applicable technical requirements imposed by the 
relevant transmission owner.  Second, Indicated TOs propose revisions to section 703.2 
to clarify that both new and increased Co-Located Loads will be studied pursuant to a 
new application for transmission service.  Third, Indicated TOs contend that PJM should 
provide additional information as to what would constitute a “material change” in the 
demand characteristics of a Co-Located Load for purposes of an Eligible Customer’s 
notice obligations under section 703.3.  Fourth, Indicated TOs recommend that PJM 
establish load shedding practice guidelines applicable to Co-Location Arrangements for 
purposes of load shedding conducted under section 705.3 of PJM’s illustrative tariff 
 
1094 Id. at 71-75. 
1095 Indicated TOs Initial Brief at 5 n.13.  
1096 Indicated TOs Response Brief at 13-17, 23.

Docket No. EL25-49-002, et al. 
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provisions.  Indicated TOs explain that they are particularly concerned with automatic 
load shedding schemes because of the possibility that unintentional activation of these 
schemes may result in unwanted shedding of nearby customer loads in addition to the   
Co-Located Load.  Fifth, Indicated TOs propose revisions to section 705.5 to require that 
the necessary control technologies and/or protection systems that must be approved by 
PJM are also approved by and developed in accordance with the transmission owners’ 
interconnection standards, guidelines, and practices.  Sixth, Indicated TOs assert that the 
reference to the transmission owner’s cost responsibility for redispatch costs in                 
section 706.2 of PJM’s illustrative tariff provisions is incorrect and request that PJM 
remove such reference from the filed Tariff records.  Seventh, Indicated TOs propose to 
correct a typo to the conditions of Part XI of the Tariff in section 2.0 of PJM’s proposed 
Attachment F-3A.  Last, Indicated TOs request that PJM add a placeholder section for 
listing required control technologies and/or protection systems to section 4.0 of PJM’s 
proposed Attachment F-3A.  
 Vistra argues that PJM’s study process is flawed because it provides too much 
discretion to PJM and transmission owners to determine whether studies are required, 
which studies to conduct, the timeline for doing so, and how to prioritize different 
requests.1097  Also, Vistra contends that PJM’s proposal is unclear on what it means to 
ensure that non-firm transmission service can be provided reliably, and that it is critical 
customers seeking non-firm service not be held to some higher standard.  Constellation 
similarly argues that PJM’s proposed study procedures lack sufficient detail to prevent 
delay and discrimination by transmission owners.1098  Constellation argues that PJM must 
spell out the studies it will perform in the tariff, as well as the timetable for completing 
the studies.  
 Market Monitor argues that Interim NITS is not consistent with PJM’s planning 
process and poses potentially significant reliability risks due to the complexity introduced 
by the necessary control technology and protection systems.  Market Monitor states that 
these risks mean there is not an unlimited amount of Interim NITS that can be provided, 
which raises questions about which customers would be allowed to take Interim NITS if 
demand exceeds supply.1099 
 Several parties oppose any restriction on Co-Located Loads accessing on-site 
generation while using Interim NITS and being curtailed, noting that PJM’s initial brief is 
not clear on whether such a requirement is being proposed.  Parties argue that such a 
requirement would be in violation of the December Order and significantly degrade the 
 
1097 Vistra Response Brief at 31, 39. 
1098 Constellation Response Brief at 14-15. 
1099 Market Monitor Response Brief at 6-7.

Docket No. EL25-49-002, et al. 
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value of Interim NITS.1100  DCC argues that allowing customers to be curtailed despite 
bringing their own generation does not align with the Commission’s objective to enable 
more flexible and timely service arrangements for Co-Located Load.1101  DCC argues 
that PJM’s proposal does not recognize an intermediate operational state in which Co-
Located Generators can operate in parallel with the grid on a limited, non-exporting or                       
non-market-participating basis while completing interconnection requirements.  
Enchanted Rock argues that because this limitation during curtailment conditions is a 
practice that affects rates and service significantly, that is reasonably susceptible of 
specification, and that is not so generally understood in any contractual arrangement as to 
render recitation superfluous, it must be included within the Tariff in order to be 
effectuated.1102   
 AEU/SEIA request that the Commission direct PJM to revise its Interim NITS 
proposal to explicitly allow Eligible Customers to use on-site generation to serve load 
continuously, provided that the generator is new and that the Co-Located Load does not 
simultaneously withdraw energy from the transmission system.1103  Joint Co-Location 
Developers assert that, as long as Co-Located Generators are not capacity resources, they 
should be free to serve Co-Located Loads during curtailment conditions.1104   
 Constellation asks the Commission to direct PJM to include a transitional 
mechanism for pending large load NITS applicants so that this new service is not 
unnecessarily limited to new applicants.1105 
 
1100 See AEU/SEIA Response Brief at 20 (citing December Order, 193 FERC 
¶ 61,217 at P 201); Enchanted Rock Response Brief at 7; Joint Co-Location Developers 
Response Brief at 18. 
1101 DCC Response Brief at 3-4.  
1102 Enchanted Rock Response Brief at 7. 
1103 AEU/SEIA Response Brief at 21. 
1104 Joint Co-Location Developers Response Brief at 19. 
1105 Constellation Response Brief at 14.

Docket No. EL25-49-002, et al. 
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3. 
Reply Briefs 
 In consideration of parties’ comments, particularly those of Indicated TOs, PJM 
proposes certain revisions to the illustrative tariff provisions for Interim NITS and NITS, 
and the Service Agreement for Interim NITS.1106 
 PJM articulates several reasons why Interim NITS customers should not be 
allowed to access the Co-Located Generator when PJM curtails the Co-Located Load.1107  
First, PJM states that Interim NITS will be curtailed when the system cannot support it in 
real time, whether with sufficient generation or transmission capacity.  Second, PJM 
argues that Interim NITS must be designed to allow PJM to maintain system reliability, 
both from a transmission and capacity perspective, and that allowing an interruptible 
customer to preclude PJM from accessing a generation resource during times of system 
stress would be contrary to that objective.  PJM maintains that, if the Co-Located 
Generator is a capacity resource, then PJM has the first call on such resource’s energy to 
meet the region’s needs.  Third, PJM explains that Interim NITS is a type of NITS and is 
served by the pool of resources and not any one dedicated resource.  PJM asserts that 
allowing an Interim NITS customer to take energy from the Co-Located Generator during 
curtailment would effectively transform this service into something akin to FCD or 
NFCD transmission service, where the Co-Located Generator dedicates a MW level of 
output to the Co-Located Load.  Lastly, PJM argues that Interim NITS is predicated on 
the Co-Located Load’s willingness to curtail, and allowing an Interim NITS customer 
access to the Co-Located Generator during times of system stress is contrary to this 
foundational element of the December Order.1108  PJM also asserts that providing a right 
to an Interim NITS customer to access the Co-Located Generator during times of system 
stress is illogical when such right is not available to full Network Customers.  NOVEC 
urges the Commission to accept PJM’s proposal and argues that if prospective customers 
find that Interim NITS is not desirable, they have the flexibility to pursue a combination 
of FCD and NFCD transmission services.1109 
 PJM defends its process for Interim NITS to determine whether “additional studies 
are needed” by arguing that the NITS study could provide sufficient information for PJM 
to determine if Interim NITS can be reliably provided.1110  PJM maintains that it should 
 
1106 PJM Reply Brief at 60-64. 
1107 Id. at 16-20. 
1108 Id. at 21 (citing December Order, 193 FERC ¶ 61,217 at P 201). 
1109 NOVEC Reply Brief at 16. 
1110 PJM Reply Brief at 27.

Docket No. EL25-49-002, et al. 
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not be required to provide as much detail for Interim NITS determinations as for FCD 
and NFCD transmission services given that Interim NITS is derivative of the customer’s 
existing NITS request and associated studies, although the illustrative tariff authorizes 
PJM to perform additional studies if needed.1111   
 Joint Co-Location Developers argues that the Interim NITS proposal undermines 
PJM’s reliability rationale for NFCD transmission service outage restrictions because 
PJM has proposed to make it broadly available during normal operating conditions, and 
PJM has not claimed that doing so will compromise reliability.1112 
 Constellation avers that PJM’s omission of any detail with respect to this study 
process does not comply with the Commission’s directive to provide additional record 
evidence to set the appropriate replacement rates, terms, and conditions for Interim NITS 
and urges the Commission to direct PJM to file its study process for Interim NITS within 
30 days.1113 
4. 
Answers 
 Constellation asks the Commission to direct PJM to revise its illustrative tariff to 
clarify that large loads with pending NITS applications shall be studied for Interim NITS 
at the request of the load without having to submit a separate application.1114 
 Enchanted Rock reiterates that PJM’s implementation of Interim NITS is 
fundamentally flawed because, while an Eligible Customer takes Interim NITS on behalf 
of a Co-Located Load, PJM proposes not to allow that Co-Located Load to receive any 
capacity or energy from a Co-Located Generator and instead to treat the Co-Located 
Generator as a capacity resource.1115  Enchanted Rock disagrees with PJM that this 
limitation accords with the principles of the December Order that the new transmission 
services are designed to serve loads that are willing and able to control their withdrawals 
from the transmission system and to allow PJM to maintain system reliability.  Enchanted 
Rock avers to the contrary that allowing a Co-Located Load to take capacity and energy 
from a Co-Located Generator enables that Co-Located Load to control its withdrawals 
 
1111 Id. at 31-32. 
1112 Joint Co-Location Developers Reply Brief at 9-10. 
1113 Constellation Reply Brief at 12. 
1114 Constellation May 11 Answer at 14. 
1115 Enchanted Rock May 7 Answer at 2-3.

Docket No. EL25-49-002, et al. 
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from the transmission system.1116  Enchanted Rock also contends that PJM is mistaken in 
its argument that the PJM region has first call on the output of a Co-Located Generator 
before the Co-Located Generator has completed PJM’s interconnection study process and 
received a GIA, because until that point, the Co-Located Generator is not eligible to be a 
capacity resource.  Enchanted Rock argues that forcing the Co-Located Generator to be 
dispatched under emergency conditions during this period would be unduly 
discriminatory by imposing on these Co-Located Generators obligations that are not 
imposed on similarly situated generators.1117  Finally, Enchanted Rock argues that it 
would be illogical that an Interim NITS customer not be allowed to rely on its non-firm 
Co-Located Generator in order to remain online during emergencies when it is taking 
non-firm transmission service.  Enchanted Rock further contends that it would be unjust 
and unreasonable for a Co-Located Load to bear the full capital and development risk of 
bringing a Co-Located Generator online only for PJM to dispatch the Co-Located 
Generator to serve firm Network Customers during emergencies—precisely when PJM is 
serving firm Network Customers but curtailing Interim NITS customers.1118 
5. 
Determination 
 We find PJM’s proposal for Interim NITS to be just and reasonable, subject to the 
clarifications directed below, and direct PJM to file, as the replacement rate, rates, terms, 
and conditions for Interim NITS as detailed below on compliance.  We generally agree 
with PJM that the non-rate terms and conditions for Interim NITS reflect those applied to 
NITS, with necessary modifications to reflect the interim and non-firm nature of this new 
transmission service.  We find that PJM’s proposals that an Eligible Customer taking 
Interim NITS will receive non-firm transmission service for the delivery of energy to    
Co-Located Load and convert automatically to a Network Customer when Network 
Upgrades are complete to be consistent with the directives in the December Order.1119  
We direct PJM to file, within 60 days of the date of issuance of this order, a compliance 
filing revising its Tariff consistent with these findings.  Consistent with our determination 
above to extend the three new transmission services set forth in the December Order to 
Eligible Customers taking service on behalf of load with BTMG that are willing and able 
 
1116 Id. at 5-6. 
1117 Id. at 6-8. 
1118 Id. at 8-9. 
1119 December Order, 193 FERC ¶ 61,217 at P 200 (stating that Interim NITS “can 
be interrupted until the Network Upgrades necessary to provide NITS are complete and 
the Co-Located Load can be designated as Network Load”).

Docket No. EL25-49-002, et al. 
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to limit their energy withdrawals from the transmission system under certain conditions, 
we further direct PJM to reflect this change in its compliance filing. 
   We find that Indicated TOs’ proposal to apply the NITS rate to Eligible 
Customers taking Interim NITS on behalf of Co-Located Load is just and reasonable and 
consistent with the December Order.1120  Therefore, and consistent with our 
determination above to extend the three new transmission services set forth in the 
December Order to Eligible Customers taking service on behalf of load with BTMG that 
are willing and able to limit their energy withdrawals from the transmission system under 
certain conditions, we direct the PJM transmission owners to submit, within 60 days of 
the date of issuance of this order, a compliance filing to apply the NITS rate to Eligible 
Customers taking transmission service on behalf of Eligible Loads.   
 Consistent with our findings in Part VI.A.4, we also find just and reasonable 
PJM’s proposal to charge Eligible Customers taking Interim NITS on behalf of                    
Co-Located Load certain administrative and ancillary services charges, and to assess 
charges based on gross demand for regulation and black start service.  We find PJM’s 
proposal consistent with the December Order.1121  Moreover, we find it is just and 
reasonable to charge Interim NITS customers redispatch costs to cover congestion-related 
costs, given that Interim NITS will be pool-scheduled and can be served by generators 
redispatched to mitigate congested transmission paths.  Accordingly, and consistent with 
our determination above to extend the three new transmission services set forth in the 
December Order to Eligible Customers taking service on behalf of load with BTMG that 
are willing and able to limit their energy withdrawals from the transmission system under 
certain conditions, we direct PJM to submit, within 60 days of the date of issuance of this 
order, a compliance filing to incorporate in the Tariff revisions to assess to Eligible 
Customers taking transmission service on behalf of Eligible Loads:  (1) administrative 
service charges, (2) ancillary service charges, (3) black start service charges,                          
(4) regulation charges, and (5) any redispatch costs.   
 We note that only curtailment procedures were explicitly included in the paper 
hearing, and Tariff provisions governing other terms and conditions for Interim NITS, 
including the study process, should be filed on compliance.1122  That said, we find it is 
just and reasonable to allow PJM greater discretion as to how it studies Interim NITS 
 
1120 Id. (stating that Interim NITS customers would pay the NITS rate). 
1121 Id. (stating that Interim NITS customers would pay ancillary service charges 
and charges for black start service). 
1122 Id. P 219.

Docket No. EL25-49-002, et al. 
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requests, in comparison to requests for FCD transmission service.1123  We disagree with 
Vistra that PJM’s proposed study process provides too much discretion to PJM and 
transmission owners.  We reiterate that Interim NITS is only “available to the extent PJM 
determines that it can provide some level of interim service reliably,”1124 and therefore 
we find that it is just and reasonable to limit this service to situations in which PJM, in 
consultation with transmission owners, grants such service based on the results of 
appropriate studies.  The Commission generally defers to transmission providers’ 
discretion regarding how to maintain a reliable transmission system.1125   
 We further find that Interim NITS is distinguishable from FCD and NFCD 
transmission services, for which we direct PJM to provide additional detail in the Tariff 
regarding the study process as discussed Part VI.A.3, because Interim NITS is a 
temporary service akin to provisional interconnection service in that both services are 
intended to allow a customer to temporarily use an amount of a service that can be 
provided reliably until such customer may begin taking the full requested service.  In 
both cases, the Commission requires the transmission provider to determine if the 
requested service could be provided reliably.1126  Similar to provisional interconnection 
 
1123 See PJM, Intra-PJM Tariffs, OATT, § VIII.L 439 Provisional Interconnection 
Service (0.0.0) (providing that PJM “may grant such service at its discretion based upon 
an evaluation that will consider the results of available studies”); Order No. 890,                    
118 FERC ¶ 61,119 at P 957 (in the case that a request for long-term Firm PTPS cannot 
be satisfied out of existing capacity, the transmission provider is required to identify 
options for providing service but has discretion to study and offer a mix of planning 
redispatch and conditional firm options for a single service request). 
1124 December Order, 193 FERC ¶ 61,217 at P 200. 
1125 RWE Clean Energy, LLC, 194 FERC ¶ 61,212 at P 42 (“The Commission 
generally allows transmission providers to exercise their engineering judgment when 
conducting interconnection studies, including deferring to transmission providers’ 
discretion regarding how to maintain a reliable transmission system.”). 
1126 December Order, 193 FERC ¶ 61,217 at P 200 (“Moreover, this new service 
would be optional for an Eligible Customer seeking NITS on behalf of a Co-Located 
Load and would only be available to the extent PJM determines that it can provide some 
level of interim service reliably.”); Order No. 845, 163 FERC ¶ 61,043 at P 440 (“In 
response to CAISO, we clarify that ‘a certain amount of capacity already studied’ refers 
to situations where, for example, available studies or additional studies as necessary 
indicate that there is a certain amount of interconnection service available without the 
need for additional network upgrades and the transmission provider can reliably 
accommodate the interconnection service.”).

Docket No. EL25-49-002, et al. 
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service, we find that it is just and reasonable, in the case of this new interim transmission 
service, to afford PJM greater discretion as to how it decides to study Interim NITS 
requests, in comparison to requests for FCD and NFCD transmission services, and thus 
we decline to direct PJM to provide more detail in its Tariff on the process for studying 
requests for Interim NITS.1127  We also disagree with Constellation that it is necessary for 
PJM to study requests for Interim NITS as part of the NITS process, rather than pursuant 
to a separate application.  On compliance, we direct PJM to file Tariff provisions to 
effectuate a study process for Interim NITS, as discussed herein.  Consistent with our 
determination above to extend the three new transmission services set forth in the 
December Order to Eligible Customers taking service on behalf of load with BTMG that 
are willing and able to limit their energy withdrawals from the transmission system under 
certain conditions, we further direct PJM to reflect this change in its compliance filing.   
 Regarding requests from parties that Interim NITS customers be allowed access to 
the Co-Located Generator during curtailments, we find that it is just and reasonable to 
prohibit the Eligible Customer taking Interim NITS on behalf of Co-Located Load from 
drawing energy from the Co-Located Generator when the Eligible Customer is curtailed, 
if the Co-Located Generator is a capacity resource.  As PJM explains, capacity resources 
have an obligation to serve Network Load, and this obligation is particularly important 
during emergency or pre-emergency conditions when PJM needs all resources at its 
disposal to maintain reliability.1128  However, in response to parties, we clarify that such a 
restriction would not be applicable to an Eligible Customer taking Interim NITS on 
behalf of Co-Located Load if the associated Co-Located Generator does not yet have any 
interconnection service or has only provisional interconnection service.  Further, this 
restriction applicable to an Eligible Customer taking Interim NITS on behalf of             
Co-Located Load would not be applicable if the associated Co-Located Generator is 
seeking capacity resource status, but not yet obtained such status, because that Co-
Located Generator would not yet have any obligation to provide capacity under the 
 
1127 See PJM, Intra-PJM Tariffs, OATT, § VIII.L 439 Provisional Interconnection 
Service (0.0.0) (providing that PJM “may grant such service at its discretion based upon 
an evaluation that will consider the results of available studies”); RWE Clean Energy v. 
PJM Interconnection, L.L.C., 194 FERC ¶ 61,212 at P 42 (“The Commission generally 
allows transmission providers to exercise their engineering judgment when conducting 
interconnection studies, including deferring to transmission providers’ discretion 
regarding how to maintain a reliable transmission system.”); Order No. 890, 118 FERC   
¶ 61,119 at P 957 (in the case that a request for long-term Firm PTPS cannot be satisfied 
out of existing capacity, the transmission provider is required to identify options for 
providing service but has discretion to study and offer a mix of planning redispatch and 
conditional firm options for a single service request). 
1128 PJM Reply Brief at 18.

Docket No. EL25-49-002, et al. 
- 256 - 
Tariff.  We therefore direct PJM to submit, within 60 days, a compliance filing to 
incorporate the rates, terms, and conditions for Interim NITS that includes clarifications 
to specify that (1) an Eligible Customer taking Interim NITS on behalf of Co-Located 
Load may be served by a Co-Located Generator that is seeking capacity resource status 
during a curtailment condition to the extent that Co-Located Generator has yet to obtain 
interconnection service or has only provisional interconnection service, and (2) an 
Eligible Customer on behalf of Co-Located Load cannot expect to be served by a                  
Co-Located Generator that is a capacity resource during a curtailment condition.  
Consistent with our determination above to extend the three new transmission services set 
forth in the December Order to Eligible Customers taking service on behalf of load with 
BTMG that are willing and able to limit their energy withdrawals from the transmission 
system under certain conditions, we further direct PJM to reflect this change in its 
compliance filing. 
 We disagree with Market Monitor’s arguments that Interim NITS is not consistent 
with PJM’s transmission planning process and poses potentially significant reliability 
risks.  As discussed above, we adopt PJM’s proposal for application and studies for 
Interim NITS, which limits the amount of Interim NITS available to an Eligible Customer 
seeking to take Interim NITS on behalf of a Co-Located Load to the amount that PJM, in 
consultation with the affected transmission owner(s), determines can be provided reliably 
to that customer while maintaining the reliability of the transmission system.   
 We decline to adopt Constellation’s proposal to include a transitional mechanism 
for pending NITS applications.  PJM’s proposal does not prohibit any NITS applicant 
from also applying for Interim NITS, provided the applicant pays the additional study fee 
and is subject to the technical requirements for Interim NITS.  Therefore, we find such a 
transitional mechanism not to be necessary.   
I. 
Annual Report on New Transmission Services 
 Having addressed the rates, terms, and conditions for each of the new transmission 
services (subject to additional compliance), we now turn to our ongoing oversight of the 
implementation and use of these new transmission services.  As discussed in the 
December Order and reiterated today, we expect that these new transmission services will 
facilitate more efficient use of the existing transmission system and limit unnecessary 
transmission system buildout.  However, we also recognize that the new transmission 
services represent new developments in the provision of transmission service in the PJM 
region.  These developments require effective oversight and monitoring to help ensure 
the transmission services are working as intended and do not create reliability issues or 
raise novel questions regarding application of cost causation principles.  Transparent 
information on the use of the new transmission services is also important for prospective 
Eligible Customers on behalf of Eligible Loads to assess which transmission service to 
request and where on the transmission system to make such requests.  We conclude that

Docket No. EL25-49-002, et al. 
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the Commission, states, PJM market participants, and stakeholders would benefit from 
additional transparency about these new transmission services, and we therefore direct 
PJM to prepare an annual report, posted to its website, containing information about the 
demand for and use of these new transmission services.  Accordingly, we direct PJM to 
submit, as part of its compliance filing within 60 days of the date of issuance of this 
order, proposed Tariff provisions requiring such a report and a proposal for the 
information to be included in that annual report.  
 As PJM considers the scope and content of that annual report, we propose that the 
following information could aid the Commission, states, PJM market participants, and 
stakeholders in assessing the impact of the new transmission services: 
1) Data regarding each transmission service request seeking each of the new services 
by transmission zone, including:1129 
a. Peak gross load of the Eligible Load 
b. Category of the Eligible Load 
c. Type and MW of transmission service being requested 
d. Type and MW of transmission service granted  
e. Dates of reservation and usage (for non-firm services) 
2) Total MW of each type of transmission service taken each year by transmission 
zone, including: 
a. Total amount of FCD transmission service taken relative to peak gross load 
at the meter receiving FCD transmission service  
b. Total amount of NFCD transmission service taken relative to peak gross 
load at the meter receiving NFCD transmission service  
c. Total amount of Interim NITS relative to peak gross load at the meter 
receiving Interim NITS  
 
1129 Some of the information we identify here is likely to be available on PJM’s 
Open Access Same-Time Information System.  PJM may account for that availability in 
designing its proposal and addressing the potential burden associated with preparing the 
annual report.

Docket No. EL25-49-002, et al. 
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3) Information about transmission revenues paid by Eligible Customers on behalf of 
Eligible Loads for each transmission service by transmission zone, including: 
a. Total revenues paid by Eligible Customers taking each service per 
transmission zone 
b. Percentage of each transmission owner’s total revenue requirement paid via 
revenues from each new service 
c. MWs of each new transmission service taken by Eligible Customers 
serving Eligible Loads as a percentage of peak gross load for each 
transmission owner 
4) Frequency and magnitude of curtailment from the reservation of NFCD 
transmission service and Interim NITS by transmission zone 
5) Frequency and magnitude of denials of NFCD transmission service reservation 
requests by transmission zone  
J. 
Proposed Effective Date 
1. 
Initial Briefs 
 PJM proposes an effective date of June 1, 2029, for the three new transmission 
services.  PJM advances two rationales for its proposal:  (1) integration of the new 
transmission services into PJM’s capacity market so that PJM can procure capacity for 
Eligible Customers taking FCD transmission service on behalf of Co-Located Loads 
cannot occur until 2029; and (2) necessary modifications to the PJM core markets and 
operations software will take time.1130  PJM also argues that this effective date will not be 
a limiting factor because Eligible Customers taking the new transmission services on 
behalf of Co-Located Load and their Co-Located Generators likely will not be online 
before June 1, 2029, given interconnection requirements, supply chain issues, 
procurement challenges, and capacity auction timelines.1131 
 As to the capacity market, PJM argues that demand associated with Co-Located 
Loads will significantly affect PJM’s load forecast and thus have significant implications 
for the capacity market.  PJM explains, however, that while the BRA for the 2028/2029 
delivery year (beginning June 1, 2028) has not taken place, the load forecast and eligible 
 
1130 PJM states this includes Real-Time Security Constrained Economic Dispatch, 
Day-Ahead Market, and dispatch software.  PJM Initial Brief, Horger Aff. ¶ 16. 
1131 PJM Initial Brief at 79-82.

Docket No. EL25-49-002, et al. 
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capacity have already been determined, and it is no longer possible to implement changes 
before the BRA is conducted.  Therefore, according to PJM, the 2029/2030 delivery year 
(beginning June 1, 2029) is the first BRA in which the effects of the new transmission 
services can be considered and PJM can procure capacity for Eligible Customers taking 
FCD transmission service on behalf of Co-Located Loads.1132 
 As to the technical implementation issues, PJM argues that implementing the 
proposed curtailment priorities applicable to Interim NITS and NFCD transmission 
service will require modifying PJM’s economic dispatch software and dispatch tools in 
order to incorporate system automation that will avoid undesirable outcomes.  PJM 
further contends that work cannot begin until the rates, terms, and conditions of these 
new transmission services are finalized, and that changes to these systems will be 
dependent on vendor availability, the speed with which systems changes can be designed, 
and interaction with other software changes.1133 
2. 
Response Briefs 
 Some parties support PJM’s proposed effective date.  Market Monitor argues that 
all load in PJM currently is served by NITS, and that PJM has demonstrated that it must 
significantly modify core systems to address curtailing load where an Eligible Customer 
takes more than one kind of transmission service on behalf of Co-Located Load.1134  
NOVEC contends that entities other than PJM must also prepare for these new 
transmission services by making operational adjustments and regulatory and billing 
changes to ensure costs reflect cost causation principles.1135 
 Constellation, DCC, Joint Co-Location Developers, and Vistra oppose PJM’s 
proposed effective date, and make a variety of arguments against PJM’s rationales for it 
or in favor of alternative proposals for faster implementation.1136  As to arguments PJM 
makes about the capacity market, Vistra contends that resource adequacy considerations 
 
1132 Id. at 79-80 (citing Horger Aff. ¶¶ 11-13).  PJM also argues that inclusion of 
these services in Incremental Auctions would be inappropriate because they are 
conducted to procure replacement resources and generally result in small adjustments.  
Id. at 80-81 (citing Horger Aff. ¶ 15). 
1133 Id. at 81; Horger Aff. ¶ 16. 
1134 Market Monitor Response Brief at 8. 
1135 NOVEC Response Brief at 17-18. 
1136 Constellation Response Brief at 7; Joint Co-Location Developers Response 
Brief at 28; Vistra Response Brief at 8-9.

Docket No. EL25-49-002, et al. 
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are beyond the scope of a transmission provider’s obligation to serve and that the 
Commission requires transmission providers to make transmission service decisions 
based on available transfer capacity.1137  Constellation, Joint Co-Location Developers, 
and Vistra each criticize PJM on the basis that Interim NITS and NFCD transmission 
service are not capacity-backed services such that PJM need not procure capacity on their 
behalf.  Joint Co-Location Developers contend that PJM does not explain why a customer 
taking NITS would be reflected in capacity market demand forecast but a customer 
taking FCD transmission service would not.  Similarly, Vistra argues that large loads 
were already included in the load forecasts for the 2027/2028 and 2028/2029 BRAs and 
that some of the new large loads in the forecasts may take the new transmission services.  
Joint Co-Location Developers argue that, if PJM’s concerns stem from a planning need 
associated with existing capacity resources de-registering, then PJM should propose a 
delayed implementation limited to particular use cases.  
 As to PJM’s technical implementation issues, Vistra and Joint Co-Location 
Developers criticize PJM for failing to offer any specificity.1138  Vistra alleges that 
previous experience, such as in PJM’s implementation of Order No. 841, suggests that 
PJM should be able to implement software changes much more quickly.  Vistra further 
charges that the Commission should demand more support to justify delaying 
implementation than PJM has provided here, as it did in prior cases such as MISO’s 
implementation of Order No. 2222.  Similarly, Joint Co-Location Developers argue that 
curtailable products can be implemented on much faster timelines, pointing in particular 
to SPP’s CHILLS and PJM’s planned Connect and Manage proposal.  Vistra also argues 
that PJM’s systems should already be capable of curtailing because its Tariff provides 
Non-Firm PTPS.  Joint Co-Location Developers assert that PJM does not explain why 
additional software must be developed for FCD transmission service, which is similar to 
NITS.  Lastly, Joint Co-Location Developers state that their attached testimony notes that 
leveraging price responsive demand modifications to security constrained economic 
dispatch could allow PJM to implement faster any security constrained economic 
dispatch changes for non-firm loads.  
 Several parties disagree with PJM that Co-Located Generators will not be online 
before June 1, 2029.1139  Joint Co-Location Developers argue that there are likely to be 
projects already in development that may opt to use these new transmission services.  
 
1137 Vistra Response Brief at 7 (citing, e.g., Order No. 890, 118 FERC ¶ 61,119               
at P 2). 
1138 Id. at 10-12; Joint Co-Location Developers Response Brief at 29-30. 
1139 Joint Co-Location Developers Response Brief at 30; Vistra Response Brief              
at 9-10; Constellation Response Brief at 8.

Docket No. EL25-49-002, et al. 
- 261 - 
Vistra adds that some generators are not capacity resources, are already in the process of 
de-listing, or could enter into a bilateral agreement with another generator to cover its 
capacity obligation.  Constellation points out that load co-locating with existing 
generation could take Interim NITS.  
 Several parties request that the Commission make all or certain of the new 
transmission services available earlier.1140  DCC argues that PJM has not demonstrated 
that all elements of the proposed services must be deferred for several years, nor has it 
identified opportunities for phased or interim implementation.  DCC argues that the 
Commission should consider whether certain components of the framework can be 
implemented on an accelerated or staged basis to provide near-term benefits while 
longer-term systems are developed.  Joint Co-Location Developers ask the Commission 
to require that FCD transmission service be available within six months of an order 
accepting PJM’s filing and NFCD transmission service and Interim NITS be available at 
the earliest date technically feasible. 
 Constellation urges the Commission to establish a separate track to approve rates 
and terms for Interim NITS and make them effective no later than October 1, 2026.1141  
Constellation argues that PJM offers no legitimate reason for proposing a                             
three-and-a-half-year delay and argues that it should not be difficult to adopt as soon as 
possible.  Constellation maintains that, if the Commission separates and implements 
Interim NITS on a fast track, potential logistical challenges will not risk delay.  
Constellation suggests that the Commission review FCD and NFCD transmission 
services on a separate track and urges the Commission not to delay them until June 2029.  
Vistra proposes that, even if the Commission accepts PJM’s software-based justifications, 
the Commission should require PJM to immediately accommodate Co-Location 
Arrangements for which software changes are irrelevant, such as where the Eligible 
Customer does not reserve any amount of NFCD transmission service on behalf of       
Co-Located Load.1142  Vistra asserts that, whereas PJM contends that it needs software 
upgrades to apply appropriate curtailment priorities, a customer that reserves zero MWs 
of transmission service has no service to curtail.  Vistra contends that it is not just and 
reasonable to prevent service on the basis of a software upgrade that is, at best, nominally 
relevant to that service.  Vistra maintains that delaying service to customers that pull no 
energy from the grid is inconsistent with the December Order’s goal to remedy PJM’s 
 
1140 DCC Response Brief at 9; Joint Co-Location Developers Response Brief                 
at 27-28. 
1141 Constellation Response Brief at 6-9. 
1142 Vistra Response Brief at 12-14.

Docket No. EL25-49-002, et al. 
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failure to provide transmission service reflecting a Co-Located Load’s willingness and 
ability to limit withdrawals.   
3. 
Reply Briefs 
 PJM asserts that NFCD transmission service is not easy to implement from an 
operations perspective, particularly at scale, and in addition to exposing the system to 
higher reliability risks, will also require PJM to modify key systems.1143  PJM explains 
that changes to Energy Management Systems are needed to ensure that PJM’s systems 
are able to properly account for the provision of energy to Co-Located Load in the               
day-ahead and real-time market.  PJM contends that its Energy Management System does 
not currently distinguish between different types of load, and that feature must be added.  
PJM argues that it must determine how to properly model and reflect NFCD transmission 
service and Co-Located Load in the different systems given that NFCD transmission 
service requires the transmission system to operate on reduced contingency margins.  
PJM maintains that significant modifications to the market clearing engines used in both 
the day-ahead and real-time markets will be required because PJM must be able to curtail 
NFCD transmission service with little to no advanced notification to respond to 
significant SOL/IROL exceedances. 
 Separate from systems updates, PJM argues that it will still be challenging from an 
operational perspective to provide NFCD transmission service.1144  PJM explains that its 
systems must not only accurately reflect how this new service affects the transmission 
system, but PJM must also account for this service in the Operating Plans and then 
implement those plans manually when needed in real time.  PJM argues that, because the 
transmission system is not designed to accommodate NFCD transmission service, it will 
likely trigger many more SOL/IROL exceedances for PJM to mitigate in the Operating 
Plan and require operations at or near operating limits, rendering the system less flexible 
to respond to unexpected changes during operations.  PJM contends that it will be 
imperative that loads taking NFCD transmission service can be removed from the system 
as soon as possible when needed. 
 PJM claims it will need additional tariff language and manuals to operationalize 
requests for service.1145  PJM asserts that it reserves the right to further supplement the 
record in this proceeding if and when it develops such tariff language. 
 
1143 PJM Reply Brief at 13-14. 
1144 Id. at 14-15. 
1145 Id. at 16.

Docket No. EL25-49-002, et al. 
- 263 - 
 PJM clarifies that June 1, 2029, is the effective date for providing the new 
transmission services and that, once the Commission establishes the terms and conditions 
for these new services, PJM is willing to start accepting service requests and processing 
service applications.1146  PJM states its intent to get a headstart on establishing the details 
as to how it would implement the illustrative tariff by soon commencing discussions with 
stakeholders regarding implementation details, to be stated in PJM manuals, for these 
new transmission services.  PJM contends that, with these clarifications, there is no need 
to establish a transition mechanism for pending NITS applications, as Constellation 
suggests.  In response to concerns that PJM failed to provide a specific timeline for 
software development, PJM contends that it cannot determine a more exact development 
schedule at this time because these are new transmission services.  
 Some commenters continue to support PJM’s proposed effective date.1147  Other 
commenters continue to criticize PJM’s proposed effective date.  Joint Co-Location 
Developers argue that it is unclear why PJM must delay implementation until 2029, given 
that ERCOT has committed to implementation of controllable load as soon as 2027.1148  
Joint Co-Location Developers further argue that PJM has provided no reason why its 
system uniquely requires a longer implementation process compared to other RTOs, and 
that PJM is well placed to implement changes to its security constrained economic 
dispatch given the existing capability of its nodal Price Responsive Demand 
implementation. 
 Constellation argues that PJM’s proposed effective date would impose a three- to 
five-year moratorium on Co-Location Arrangements and undermines the December 
Order by allowing rates found to be unjust and unreasonable to remain in place for 
years.1149  Constellation asserts that PJM has devoted significant resources to such 
changes and has the tools to implement new rules quickly.  Constellation urges the 
Commission to promptly approve the rates and terms for Interim NITS, including the 
study process, by no later than October 1, 2026.   
 
1146 Id. at 55-57. 
1147 NOVEC Reply Brief at 27; Earthjustice Reply Brief at 19.  
1148 Joint Co-Location Developers Reply Brief, Supp. Aff. of Andrew Levitt and 
Aniruddh Mohan at 10 (citing ERCOT Large Load Interconnection Batch Study 
Workshop #7 at 25 (April 9, 2026), ERCOT-Large-Load-Batch-Study-Workshop7-
20260409_v03.pptx). 
1149 Constellation Reply Brief at 3-5.

Docket No. EL25-49-002, et al. 
- 264 - 
4. 
Answer 
 Constellation opposes PJM’s requested effective date and points out that PJM 
seeks to begin Connect and Manage July 1, 2027, to allow the interconnection of                 
non-capacity-backed loads that are potentially interruptible during capacity shortages, 
unless the load brings its own generation.1150  Constellation contends that it is not 
credible that PJM will take more than three years to implement Interim NITS, but less 
than one year to commence Connect and Manage.1151  Constellation asks the Commission 
to make Interim NITS effective no later than October 1, 2026, so that service can begin 
no later than June 1, 2027. 
5. 
Determination 
 We find that PJM has not provided sufficient information for the Commission to 
find that its proposed June 1, 2029, effective date is just and reasonable.  We are 
concerned that the proposed June 1, 2029, effective date unduly delays the availability of 
the new transmission services, particularly those where PJM does not procure generation 
capacity for Eligible Customers taking the transmission service on behalf of Eligible 
Load, i.e., Interim NITS and NFCD transmission service.  As discussed above, while 
PJM will procure generation capacity in forward capacity auctions to serve Eligible 
Customers taking FCD transmission service based on the contract demand level, PJM 
will not consider Interim NITS or NFCD transmission service in its resource adequacy 
planning.  Further, we agree with Vistra and Joint Co-Location Developers that PJM’s 
proposal lacks specificity.  In particular, we find that the implementation details for the 
software updates necessary for PJM’s economic dispatch software and dispatch tools lack 
specificity.  Though PJM states that it cannot determine “a more exact development 
schedule” for software development,1152 the Commission generally requires more support 
for the timeliness of a proposed effective date.1153  We believe that the instant order 
provides PJM further clarity.  We note that June 1, 2029, is approximately three years 
from now, and the issues raised by this proceeding, including those pertaining to          
Co-Located Load, are urgent in nature and, therefore, merit serious consideration of an 
earlier effective date.  Therefore, we direct PJM to reconsider its proposed effective date 
of June 1, 2029.  Moreover, we direct PJM to make a compliance filing, due within                 
60 days of the date of issuance of this order, in which PJM must explain whether it can 
 
1150 Constellation May 11 Answer at 2. 
1151 Id. at 3. 
1152 PJM Reply Brief at 57. 
1153 See, e.g., Midcontinent Indep. Sys. Operator, Inc., 190 FERC ¶ 61,031,              
at P 163 & n.302 (2025).

Docket No. EL25-49-002, et al. 
- 265 - 
make the new transmission services available on different effective dates.  In the 
compliance filing, PJM should specifically discuss whether Interim NITS and NFCD 
transmission service can be made effective at an earlier date for Eligible Customers 
taking transmission service on behalf of Eligible Loads.  
K. 
Additional Arguments 
1. 
Behind the Meter Generation 
a. 
Reply Briefs 
 Industrials/Amtrak argue that the Commission should take the following actions:  
(1) set a realistic retail BTMG threshold to focus new Co-Located Load rules on 
“gridbusting” growth above 200-300 MW, not on existing industrial customers (e.g., 
consumer goods manufacturers, steel mills, chemical manufacturers, paper mills, and 
pharmaceutical factories); (2) qualify all QFs for retail BTMG treatment without a date 
limit, consistent with PURPA regulations; (3) set clear grandfathering rules to enable 
existing, established users to avoid intensive PJM study queues, study deposits, and 
processes for operations that continue to function properly.1154 
 PJM argues that certain parties raise issues beyond the scope of this proceeding.  
PJM contends that Industrials/Amtrak improperly ask the Commission to examine 
BTMG.1155 
b. 
Determination 
 Industrials/Amtrak raise issues with respect to PJM’s retail BTMG netting rules 
that we address in PJM’s second compliance filing above.1156 
2. 
Reliability Backstop Auction 
a. 
Reply Briefs 
 Maryland OPC asserts that PJM’s proposed terms and conditions do not explain 
how existing capacity resources that shift to Co-Location Arrangements with new data 
centers would be treated relative to the PJM’s proposed reliability backstop procurement 
(RBP).  For example, Maryland OPC states that it is unclear whether capacity from 
existing generators that remove themselves from the capacity market and enter                  
 
1154 Industrials/Amtrak Reply Brief at 15. 
1155 PJM Reply Brief at 58-59. 
1156 See supra Part V.A.

Docket No. EL25-49-002, et al. 
- 266 - 
Co-Location Arrangements with new data center load would need to be replaced with 
new capacity through the RBP or in the regular BRA, and whether new data center load 
that co-locates with an existing generator will be included in the cost allocation of the 
RBP.1157  Maryland OPC states that if the capacity of existing generation that shifts to 
serve new co-located data center load is added to the BRA, ratepayers would be saddled 
with enormous costs that should be assigned to the Co-Located Load, in contravention of 
the White House and PJM Governors’ Statement of Principles and the White House’s 
Ratepayer Protection Pledge.  Maryland OPC requests that the Commission at minimum 
require PJM demonstrate how its proposal meets ratepayer protection standards set forth 
in the Statement of Principles and Ratepayer Protection Pledge and defer action on the 
proposed revisions until after PJM proposes tariff revisions to implement its RBP.  
Maryland OPC also raises concern that PJM’s initial brief suggests PJM does not intend 
for existing load to be eligible for the new transmission services.1158 
b. 
Determination 
 As an initial matter, we clarify that, contrary to Maryland OPC’s concern, PJM’s 
paper hearing proposal does not restrict Eligible Customers on behalf of existing          
Co-Located Load from taking the new transmission services.  We decline Maryland 
OPC’s request to defer action.  Maryland OPC expresses concern that PJM’s paper 
hearing proposal does not address how existing capacity resources that seek to serve    
Co-Located Loads would be treated relative to a potential future filing by PJM to address 
its reliability backstop mechanism.  We find that Maryland OPC’s concerns about PJM’s 
capacity market are beyond the scope of this paper hearing, which addresses the rates, 
terms, and conditions for new transmission services for Eligible Customers to take on 
behalf of Eligible Loads.1159     
 
1157 Maryland OPC Reply Brief at 9-11. 
1158 Id. at 8 (noting PJM’s explanation that it is unlikely that new generation will 
be operational before its proposed June 1, 2029 effective date). 
1159 In recognition of the goal to prevent unfair cost shifts, we also note that as part 
of the President’s Ratepayer Protection Pledge, a number of computational loads have 
committed to paying for “all new power delivery infrastructure upgrades to service their 
data centers.”  Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026).

Docket No. EL25-49-002, et al. 
- 267 - 
3. 
Eligible Customer Requirements 
a. 
Response Briefs 
 Invenergy requests that the Commission and PJM clarify how the definition of 
Eligible Customer applies to Co-Located Generators and Co-Located Loads.1160  
Invenergy explains that, where a state retail choice program results in unbundled retail 
access, customers may take transmission service as an Eligible Customer, and that 
therefore, Invenergy believes that a Co-Located Load could qualify as an Eligible 
Customer in a retail choice jurisdiction.1161  Invenergy seeks clarity as to whether, in the 
context of a Co-Location Arrangement, a Co-Located Generator qualifies as an Eligible 
Customer on behalf of the Co-Located Load, and whether that Co-Located Generator’s 
status as an Eligible Customer depends on whether the Co-Location Arrangement is in a 
retail choice jurisdiction. 
b. 
Reply Briefs 
 NOVEC argues that the Commission should consider a more definitive delineation 
of who may be an Eligible Customer as well as the scope of the Eligible Customer’s 
obligations.  Specifically, NOVEC seeks confirmation that it cannot be required to serve 
as an Eligible Customer serving Co-Located Load unless it agrees to do so.1162 
 NOVEC argues that the Commission cannot require LSEs to modify their retail 
rates to accommodate these new services and undertake the administrative burden of 
being an Eligible Customer for a Co-Located Load unless the LSE chooses to do so.  
Further, NOVEC contends that it should not be subject to potential liability for the 
transmission costs, much less penalties for non-compliance with the Tariff’s 
requirements, if a Co-Located Load for which NOVEC is serving as Eligible Customer 
fails to meet or comply with all applicable provisions.1163 
 Indicated TOs express support for PJM’s decision to retain the existing definition 
of Eligible Customer.  In response to Invenergy’s request for clarification as to how that 
definition applies to Co-Located Generators and Co-Located Loads, Indicated TOs argue 
that it will depend on an individual Co-Located Generator’s specific factual 
circumstances.  Indicated TOs contend that a Co-Located Generator is unlikely to meet 
 
1160 Invenergy Comments at 6. 
1161 Id. (citing Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,689). 
1162 NOVEC Reply Brief at 5. 
1163 Id. at 7.

Docket No. EL25-49-002, et al. 
- 268 - 
the definition of an Eligible Customer for purposes of obtaining FCD or NFCD 
transmission service because it is more likely to sell its output directly to the on-site load 
at retail.  Indicated TOs further contend that the ability of Co-Located Load or an entity 
representing the load to qualify as an Eligible Customer would necessarily depend on 
whether its host jurisdiction has adopted retail choice.1164 
c. 
Determination 
 With respect to Invenergy’s request, we note the Tariff defines an Eligible 
Customer as (1) any electric utility or any person generating electric energy for sale for 
resale, but with respect to transmission service that the Commission is prohibited from 
ordering by section 212(h) of the FPA, such entity is eligible only if the service is 
provided pursuant to a state requirement that the Transmission Provider or Transmission 
Owner offer the unbundled transmission service, or pursuant to a voluntary offer of such 
service by a Transmission Owner or (2) 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.1165  A Co-Located Generator may serve as an 
Eligible Customer if it meets the requirements of this definition of Eligible Customer. 
 We also clarify that nothing in this order or the December Order requires LSEs to 
modify their retail rates to accommodate the new transmission services.  We require PJM, 
as the transmission provider, to offer these services, but we do not require LSEs to offer 
them to their retail customers.  In other words, we do not require any LSE to become an 
Eligible Customer taking one of the new transmission services on behalf of an Eligible 
Load. 
4. 
Demand Side Pathways 
a. 
Response Briefs 
 Alliance supports converting Options 7 and 8 from PJM’s March 2025 Answer 
into enforceable tariff language.  Alliance supports strong measurement and verification 
of load reductions from demand response and energy efficiency in order to implement 
Options 7 and 8.1166 
 
1164 Indicated TOs Reply Brief at 6-7. 
1165 PJM, Intra-PJM Tariffs, OATT, § I.1 Definitions – E-F (41.0.0).   
1166 Alliance Response Brief at 5-6.

Docket No. EL25-49-002, et al. 
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b. 
Determination 
 Alliance’s comments are essentially an untimely request for rehearing of the 
December Order.  Alliance overlooks that the December Order required PJM to create a 
new interim non-firm transmission service similar to PJM’s Option 7.  As part of our 
determinations with respect to the rates, terms, and conditions for Interim NITS, we are 
directing PJM to submit a compliance filing to revise its Tariff to implement this new 
transmission service.  As for PJM’s Option 8, wherein Co-Located Load that is Network 
Load may participate as a demand response resource, the Commission in the December 
Order did not direct any changes to PJM’s demand response rules.  We reiterate, as the 
Commission explained in the December Order, there is not sufficient evidence to 
conclude that the existing Tariff is not just and reasonable as it relates to the existing 
demand response rules.1167  Co-Located Loads that elect to be Network Load may 
participate as a demand response resource under PJM’s existing Tariff to the extent that 
they meet the requirements to participate as such. 
5. 
Interconnection 
a. 
Response Briefs 
 AEU/SEIA claim that PJM proposes to require all co-located generators to 
undergo full interconnection studies, including those that have no intention of exporting 
power to the transmission system.1168  AEU/SEIA argue that PJM indisputably requires 
sufficient information about proposed co-located generators to reliably plan and operate 
the transmission system, but that subjecting non-exporting facilities to full 
interconnection studies will impose costs, delays, and administrative burden that are 
disproportionate to the reliability benefits that are achieved.  AEU/SEIA further argue 
that this would further strain the interconnection queue to the detriment of the PJM region 
and its customers. 
b. 
Reply Briefs 
 PJM argues that AEU/SEIA improperly assert that PJM should not study all 
interconnecting generators.1169   
 
1167 December Order, 193 FERC ¶ 61,217 at P 242. 
1168 AEU/SEIA Response Brief at 15-16 (citing PJM Initial Brief at 82). 
1169 PJM Reply Brief at 58.

Docket No. EL25-49-002, et al. 
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c. 
Determination 
 We find that AEU/SEIA’s concerns about interconnection studies for Co-Located 
Generators are beyond the scope of this paper hearing, which concerns the rates, terms, 
and conditions of new transmission services that Eligible Customers may take on behalf 
of Eligible Loads.  However, we note that the Commission has approved PJM’s proposal 
to comply with the directives of the December Order that, for Interconnection Customers 
seeking to use new generators to serve Co-Located Load:  PJM will consider requests for 
interconnection service below the full generating capability of the generator, and such 
Interconnection Customers may use existing procedures to accelerate a new service 
request if they satisfy the criteria of the Tariff.1170 
6. 
Co-Location Arrangement with Electric Storage Resource 
a. 
Response Brief 
 Joint Co-Location Developers ask that PJM clarify that its transmission service 
requirements for electric storage charging apply to storage co-located with load, and 
exempt customers from the Maximum Facility Output where the customer’s load shape 
and characteristics are inherently flexible.1171  Joint Co-Location Developers state that 
PJM does not require electric storage resources to take transmission service for charging, 
except where the storage charges during the zonal peak hour without being dispatched.  
Joint Co-Location Developers claim that, in the context of PJM’s proposal to limit NFCD 
transmission service to 100% of the Maximum Facility Output of the Co-Located 
Generator, PJM appears to allow the relevant Co-Located Load to take service while the 
co-located electric storage resource charges.  Joint Co-Location Developers maintain that 
PJM should clarify this point in its Tariff to avoid any implication that this activity is 
prohibited.  Joint Co-Location Developers request that PJM clarify that co-located 
charging loads, like standalone electric storage resources, do not require transmission 
service unless they charge during the zonal peak hour without being dispatched, and that 
any withdrawals for electric storage charging at the Point of Interconnection for which 
transmission service is not required do not count toward the Maximum Facility Output.  
Joint Co-Location Developers request, in the alternative, that PJM remove the Maximum 
Facility Output limit for loads co-located with electric storage resources. 
 
1170 PJM Interconnection, L.L.C., 195 FERC ¶ 61,030 at P 25. 
1171 Joint Co-Location Developers Response Brief at 13-14.

Docket No. EL25-49-002, et al. 
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b. 
Reply Brief 
 PJM argues Joint Co-Location Developers improperly ask the Commission to 
examine transmission service for charging electric storage resources.1172 
c. 
Determination 
 To the extent Joint Co-Location Developers ask the Commission to address 
transmission service for electric storage resources, such request is beyond the scope of 
this paper hearing, which concerns the rates, terms, and conditions of new transmission 
services for Eligible Customers on behalf of Eligible Loads.  However, insofar as Joint 
Co-Location Developers raise concerns about PJM’s proposed requirement that an 
Eligible Customer electing to take NFCD transmission service “must apply for [NFCD 
transmission service] equivalent to the megawatt level of the Co-Located Generating 
Facility dedicated to serving the Co-Located Load,” which Joint Co-Location Developers 
refer to as the Maximum Facility Output limit, we reject PJM’s proposal above.1173 
The Commission orders: 
 
(A) 
In response to the requests for rehearing, the December Order is hereby 
modified and set aside, in part, as discussed in the body of this order. 
(B) 
The clarification requests are hereby denied in part and granted in part, as 
discussed in the body of this order. 
(C) 
PJM is hereby directed to submit, within 60 days of the date of issuance of 
this order, a compliance filing with revisions to its Tariff as described in Part IV.B.3. 
(D) 
PJM is hereby directed to submit, within 60 days of the date of issuance of 
this order, a compliance filing with revisions to its Tariff as described in Part IV.C.1.b.i.  
(E) 
PJM is hereby directed to submit, within 60 days of the date of issuance of 
this order, a compliance filing with revisions to its Tariff as described in Part IV.C.1.c.i. 
(F) 
PJM is hereby directed to submit, within 60 days of the date of issuance of 
this order, a compliance filing as described in Part V. 
(G) 
PJM is hereby directed to submit, within 60 days of the date of issuance of 
this order, a compliance filing as described in Part VI. 
 
1172 PJM Reply Brief at 59. 
1173 See supra Part VI.A.2.

Docket No. EL25-49-002, et al. 
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(H) 
PJM transmission owners are hereby directed to submit, within 60 days of 
the date of issuance of this order, a compliance filing as described in Part VI.  
By the Commission.  Commissioner Chang is concurring with a separate statement  
 
 
 
  attached. 
 
( S E A L ) 
 
 
 
 
 
 
 
 
 
Debbie-Anne A. Reese, 
Secretary.

Docket No. EL25-49-002, et al. 
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Appendix – Tariff Record[s] 
 
PJM Interconnection, L.L.C. 
Intra-PJM Tariffs 
 
• A-B, OATT Definitions -- A - B (24.0.0)  
 
• L-M-N, OATT Definitions -- L -- M - N (52.0.0) 
 
• 28.1, OATT 28.1 Scope of Service: (2.0.0) 
 
• 29.1, OATT 29.1 Condition Precedent for Receiving Service (4.0.0) 
 
• 29.2, OATT 29.2 Application Procedures: (4.0.0) 
 
• 31.6, OATT 31.6 Annual Load and Resource Information Updates: (4.0.0) 
 
• 34.2, OATT 34.2 Netting of Behind the Meter Generation. (1.0.0) 
 
• 34.3, OATT 34.3 Netting of Non-Retail Behind The Meter Generation (2.0.0) 
 
• 300 B, OATT 300 Definitions B (2.0.0) 
 
• 300 N, OATT 300 Definitions N (3.0.0) 
 
• 400 B, OATT 400 Definitions B (2.0.0) 
 
• 400 N, OATT 400 Definitions N (4.0.0) 
 
• 401, OATT Part VIII.A 401 Applications for Cycle Process Intro (5.0.0) 
 
• 403, OATT Part VIII.B 403 Application Rules (4.0.0) 
 
• IX Subpart A, OATT Part IX Subpart A FORM OF APPLICATION AND 
STUDIES AGRMT (4.0.0) 
 
• IX.B GIA Appx-Sched, OATT Part IX.B GIA Appendices and Schedules (5.0.0) 
 
• IX.B GIA Schedule O, OATT Part IX.B GIA Schedule O (0.0.0) 
 
• IX Subpart G, OATT Part IX Subpart G FORM OF NECESSARY STUDIES 
AGREEMENT (3.0.0)

Docket No. EL25-49-002, et al. 
- 274 - 
• XI, OATT XI. TRANSMISSION SERVICES FOR CO LOCATED LOADS 
(0.0.0) 
 
• ATTACHMENT F-3A, OATT ATTACHMENT F-3A (0.0.0) 
 
• ATTACHMENT F-4, OATT ATTACHMENT F-4 (0.0.0)

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
 
 
PJM Interconnection, L.L.C. 
Allegheny Electric Cooperative, Inc. 
American Transmission Systems, Incorporated 
Atlantic City Electric Company 
Baltimore Gas and Electric Company 
Delmarva Power & Light Company 
Duke Energy Ohio, Inc. 
Duke Energy Kentucky, Inc. 
East Kentucky Power Cooperative, Inc. 
Essential Power Rock Springs, LLC 
Hudson Transmission Partners, LLC 
Jersey Central Power & Light Company 
Mid-Atlantic Interstate Transmission, LLC 
Neptune Regional Transmission System, LLC 
Old Dominion Electric Cooperative 
PECO Energy Company 
PPL Electric Utilities Corporation 
Potomac Electric Power Company 
Public Service Electric and Gas Company 
Rockland Electric Company 
Trans-Allegheny Interstate Line Company 
Transource West Virginia, LLC 
UGI Utilities, Inc. 
Monongahela Power Company 
The Potomac Edison Company 
Commonwealth Edison Company 
Commonwealth Edison Company of Indiana, Inc. 
The Dayton Power and Light 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. 
Appalachian Power Company 
Indiana Michigan Power Company 
Kentucky Power Company 
Kingsport Power Company 
Ohio Power Company 
Wheeling Power Company 
Docket Nos. EL25-49-002 
EL25-49-000

Docket No. EL25-49-002, et al. 
- 2 - 
Duquesne Light Company 
Virginia Electric and Power Company 
Linden VFT, LLC 
City of Cleveland, Department of Public Utilities, 
Division of Cleveland Public Power 
City of Hamilton, OH 
Southern Maryland Electric Cooperative, Inc. 
Ohio Valley Electric Corporation 
AMP Transmission, LLC 
Silver Run Electric, LLC 
NextEra Energy Transmission MidAtlantic Indiana, Inc. 
Wabash Valley Power Association, Inc. 
Keystone Appalachian Transmission Company 
Large Loads Co-Located at Generating Facilities  
Constellation Energy Generation, LLC 
v.  
PJM Interconnection, L.L.C. 
PJM Interconnection, L.L.C. 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
AD24-11-001 
 
EL25-20-001 
(consolidated) 
 
 
 
 
ER26-1479-000 
 
(Issued June 18, 2026) 
 
CHANG, Commissioner, concurring: 
 
 
In today’s order, the Commission addresses rehearing requests and the paper 
hearing and compliance record regarding the rates, terms, and conditions through which 
Co-Located Loads may take transmission service from the PJM Interconnection, L.L.C. 
(PJM) system.  I write separately to address the Commission’s resolution of the 
“minimum charge” issue raised in my concurrence to the December Order,1 which I 
believe provides a reasonable path forward based on the record before us. 
 
In its December Order, the Commission asked two briefing questions regarding 
establishing an additional charge for Eligible Customers on behalf of a Co-Located Load 
that elects not to take any amount of transmission service or only a de minimis amount of 
 
1 PJM Interconnection, L.L.C., 193 FERC ¶ 61,217 (2025) (December Order) 
(Comm’r Chang, concurring).

Docket No. EL25-49-002, et al. 
- 3 - 
transmission service.2  At that time, I wrote separately to emphasize my concern that the 
implementation of our rules around the new transmission services could risk cost shifting 
if those loads take little or no transmission service and thereby do not contribute to 
paying for the transmission system costs.  Broadly, I remain vigilant about the impacts on 
consumers as the Commission continues to respond to new challenges from large and Co-
Located Loads.  
 
In today’s order, the Commission concludes that the record does not adequately 
support either the need for an additional charge at this time, or how such a charge should 
be calculated and assessed.  In so doing, the Commission acknowledges the complexity 
of (1) documenting the benefits that accrue to Co-Located Loads paying little or no 
transmission service from the grid, and (2) designing a charge that corresponds to those 
benefits.   
 
As explained in my concurrence to the December Order, because the Commission 
does not require a Co-Located Load to take any specific amount of the new transmission 
services, it creates the possibility that the load could pay little or nothing towards the 
costs of the transmission system, notwithstanding potential benefits it receives from that 
system.  If this fact pattern occurs, particularly on any significant scale, it may result in 
problematic cost shifts to other transmission customers.  However, if Co-Located Loads 
do, in fact, take meaningful transmission service via an existing service or one or both of 
the new contract demand services, they would pay transmission charges that contribute to 
the recovery of the transmission system’s capital and operations and maintenance costs.  
Therefore, whether underlying concerns around cost shifting actually manifest will 
ultimately depend on how the new transmission services will be used. 
 
So, today’s order reasonably concludes that insights from concrete experience 
with the use of these new transmission services will help inform whether further action 
would be needed to address cost shifting issues.  Given the challenges demonstrated in 
the record with articulating or documenting the specific benefits associated with being 
synchronized to the PJM system, and designing a rate (including conditions under which 
and the parties to whom it will be charged) that is commensurate with those benefits, I 
am persuaded that continued monitoring of this issue is appropriate.   
 
Furthermore, as part of a broader recognition that implementing the new 
transmission services represents a significant development in PJM, the Commission 
directs PJM to prepare an annual report that includes critical information about how these 
services are being requested and used, as well as how loads using the services contribute 
toward transmission owners’ revenue requirements.3  The annual reports will provide 
 
2 December Order, 193 FERC ¶ 61,217 at P 219, questions 3 and 4. 
3 PJM Interconnection, L.L.C., 195 FERC ¶ 61,209, at PP 580-81 (2026).

Docket No. EL25-49-002, et al. 
- 4 - 
information that helps the Commission, the states, market participants, and stakeholders 
monitor the impacts of these new transmission services, including assessing whether the 
potential cost shift concern discussed above and in my prior concurrence actually occurs.  
If it does, I stand ready to consider Federal Power Act section 205 filings or section 206 
complaints (including sua sponte action by the Commission) to address those cost shifts. 
For these reasons, I respectfully concur.  
 
 
________________________ 
Judy W. Chang 
Commissioner