ER26-3380-001 · 2026-10-29 · Northern Virginia Electric Cooperative

Request for Rehearing and Clarification or Alternative Request for Rehearing of Northern Virginia Electric Cooperative, Inc.

UNITED STATES OF AMERICA 
BEFORE THE 
FEDERAL ENERGY REGULATORY COMMISSION 
 
 
) 
 
PJM Interconnection, L.L.C. 
) 
) 
Docket Nos. ER26-3380-000 
                   EL26-108-000 
 
) 
 
 
REQUEST FOR REHEARING AND CLARIFICATION OR ALTERNATIVE REQUEST 
FOR REHEARING OF NORTHERN VIRGINIA ELECTRIC COOPERATIVE, INC. 
 
Pursuant to section 313(a) of the Federal Power Act (“FPA”)1 and Rule 713 of the Rules 
of Practice and Procedure of the Federal Energy Regulatory Commission (“FERC” or the 
“Commission”),2 Northern Virginia Electric Cooperative, Inc. (“NOVEC”) respectfully seeks 
rehearing and clarification, or alternative request for rehearing, of the Commission’s September 
29, 2026, order (“RBP Order”) in Docket Nos. ER26-3380-000 and EL26-108-0003 on PJM 
Interconnection, L.L.C.’s (“PJM”) proposed Reliability Backstop Procurement.4 The RBP Order 
found that certain aspects of PJM’s proposal were just and reasonable, but found that others did 
not appear to be just and reasonable, and directed further briefing through a paper hearing on 
alternatives that may be just and reasonable.5 NOVEC respectfully urges the Commission to 
grant rehearing of its decision finding the RBP to be just and reasonable, and to clarify that all 
aspects of cost allocation associated with the RBP is within the scope of the paper hearing that 
the Commission ordered to be conducted. Should the Commission’s clarification restrict the 
scope of the paper hearing, then NOVEC seeks rehearing of any limitations imposed on the 
scope of the paper hearing insofar as cost allocation associated with RBP is concerned. 
 
1 16 U.S.C. § 825l(a). 
2 18 C.F.R. § 385.713. 
3 PJM Interconnection, L.L.C., 196 FERC ¶ 61,245 (2026) (“RBP Order”). 
4 PJM Interconnection, L.L.C., Reliability Backstop Procurement, Docket No. ER26-3380-000 (July 31, 2026) 
(Accession No. 20260731-5214) (“RBP Proposal”). 
5 RBP Order at P 2.

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I. 
STATEMENT OF ISSUES AND SPECIFICATIONS OF ERROR 
NOVEC submits the following Statement of Issues and Specifications of Error pursuant 
to Rules 713(c)(1) and 713(c)(2)6 of the Commission’s Rules of Practice and Procedure: 
1. The Commission erred by not considering and requiring the voluntary, stakeholder-
endorsed subscription model. FERC must engage in reasoned decision-making. See 
Emera Me. v. FERC, 854 F.3d 9, 27 (D.C. Cir. 2017). Reasoned decision-making 
requires FERC to “respond to objections and address contrary evidence in more than 
a cursory fashion.” Trans. Agency of N. Cal. v. FERC, 628 F.3d 538, 543-44 (D.C. 
Cir. 2010) (“TANC”). Further, FERC is required to consider “reasonable alternatives” 
to the Commission’s decision. Am. Gas Ass’n v. FERC, 593 F.3d 14, 19 (D.C. Cir. 
2010); see also Laclede Gas Co. v. FERC, 873 F.2d 1494, 1498 (D.C. Cir. 1989). The 
Commission did not respond to or consider NOVEC’s argument, which advocated for 
the adoption of the voluntary framework as an alternative to the RBP filed by PJM. 
 
2. The Commission erred by not rejecting the as-filed RBP framework because the RBP 
distorts market signals that the capacity market needs to operate and unduly 
discriminates against Load Serving Entities (“LSE”) serving new large loads by 
imposing a capacity surcharge on them. The fact that PJM presumes or expects that 
the LSEs will, in turn, pass these charges through to their data center customers does 
not alter the fact that PJM’s tariff would impose charges on some – but not all – LSEs 
based on the nature of the retail load they are serving. PJM has no authority to base its 
tariff rates and charges on the character of retail service provided by LSEs. As a 
result, the Commission’s decision is arbitrary and capricious, unsupported by record 
evidence, and inconsistent with the FPA and the Commission’s regulations. See 5 
U.S.C. § 706; Motor Vehicle Mfrs. Ass’n of U.S., Inc. v. State Farm Mut. Auto. Ins. 
Co., 463 U.S. 29, 43 (1983) (quoting Burlington Truck Lines v. United States, 371 
U.S. 156, 168 (1962)); ANR Storage Co. v. FERC, 904 F.3d 1020, 1024 (D.C. Cir. 
2018). 
 
3. If the Commission does not clarify that all aspects of the design for cost allocation of 
the RBP are within the scope of the paper hearing and that NOVEC is not foreclosed 
from advocating for alternative designs for cost allocation, the Commission erred by 
not addressing NOVEC’s arguments with respect to cost allocation, see Trans. 
Agency of N. Cal. v. FERC, 628 F.3d 538, 543-44 (D.C. Cir. 2010). By approving an 
approach for cost allocation that does not recognize other causes of the capacity 
deficit that PJM is seeking to address, the Commission has improperly sanctioned 
 
6 18 C.F.R. § 385.713(c)(1)-(c)(2).

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subsidization of capacity for some customers at the expense of RBP buyers. That is 
not consistent with the Commission’s cost-causation principle and should be set 
aside. KN Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992); El Paso Elec. 
Co. v. FERC, 76 F.4th 352 (5th Cir. 2023) (“El Paso”). As a result, the Commission’s 
decision is arbitrary and capricious, unsupported by record evidence, and inconsistent 
with the FPA and the Commission’s regulations. See 5 U.S.C. § 706; Motor Vehicle 
Mfrs. Ass’n of U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983) 
(quoting Burlington Truck Lines v. United States, 371 U.S. 156, 168 (1962)); ANR 
Storage Co. v. FERC, 904 F.3d 1020, 1024 (D.C. Cir. 2018). 
 
II. 
REQUEST FOR REHEARING AND REQUEST FOR CLARIFICATION OR 
ALTERNATIVE REQUEST FOR REHEARING 
A. 
The Commission should require PJM to adopt the voluntary stakeholder RBP 
framework. 
 
While it may be easy and expedient to attribute the current capacity shortfall solely to 
growth of large loads, which has been the most visible development in recent years, the causes of 
the present shortfall pre-date and are not solely due to the buildout of data centers. Until recently, 
PJM’s interconnection queue was a serial process that struggled to interconnect the volume of 
generation-interconnection requests,7 which was coupled with the early retirement of capacity 
resources due in part to states’ environmental policies.8 The PJM stakeholders proposed a 
voluntary framework for the RBP that recognized the contribution of load growth to the capacity 
shortfall without the issues attendant to PJM’s proposed RBP.9 Unlike PJM’s mandatory 
approach, which would impose all obligations and consequences of the capacity shortfall onto 
relatively few LSEs, as if they are to be deemed responsible for the shortfall, the voluntary RBP 
would allow large loads to fulfill their obligations under the Ratepayer Protection Pledge without 
 
7 PJM, Interconnection Reform Tariff Filing, Docket No. ER22-2110-000, at 4 (June 14, 2022) (Accession No. 
20220614-5081).  
8 NOVEC, Protest, Docket No. ER26-3380-000, at 11-12 (Aug. 21, 2026) (Accession No. 20260821-5307) 
(“NOVEC Protest”) (citing IMM, 2023 State of the Market Report for PJM Volume I at 1 (March 14, 2024) 
(https://www.monitoringanalytics.com/reports/pjm_state_of_the_market/2023.shtml)).  
9 NOVEC, Motion for Leave to Answer and Answer, Docket No. ER26-3380-000, at 5-9 (Sep. 23, 2026) (Accession 
No. 20260923-5149) (“NOVEC Answer”).

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creating undesirable consequences for the Transmission Owners, Electric Distributors, and LSEs 
who happen to serve those large loads. 
 
Under the voluntary RBP framework, interested developers would have the option to 
subscribe to pay the RBP costs or accept an interruptible form of transmission service.10 This 
provides the flexibility necessary for choosing how to manage the uncertainty risk created by 
PJM’s intent to assign 15-year financial obligations to forecasted conditions that have not yet 
come into existence, which is a critical and necessary aspect of the framework that needs to be 
included in any methodology approved for assigning RBP obligations – a component that PJM 
was asked to include in the proposal it filed, but that it declined to incorporate. To be just and 
reasonable, the RBP must include the ability to proactively and preemptively choose 
interruptible service rather than accept a capacity obligation. The voluntary RBP framework 
achieved a clear consensus during stakeholder discussions as the only proposal endorsed out of 
more than a dozen considered.11 The voluntary RBP framework is just and reasonable because, 
unlike PJM’s proposal, it preserves the ability of LSEs to control their level of RBP obligations 
while providing sufficient incentives for large load to participate in the process. 
 
NOVEC challenged PJM’s decision to ignore the stakeholder consensus and file the 
RBP.12 PJM specifically represented that the Commission could exercise its authority under 
NRG13 and “modify and/or sever any element of the proposed Tariff and RAA language to the 
extent necessary and permitted under section 205 of the FPA and NRG Power Marketing, LLC v. 
FERC, where such modification and/or severance is consistent with PJM’s overarching 
 
10 NOVEC Protest at 25.  
11 Id. at 24-25.   
12 Id. at 24-26; NOVEC Answer at 5-9. 
13 NRG Power Mktg., LLC v. FERC, 862 F.3d 108 (D.C. Cir. 2017) (“NRG”).

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objectives in this filing.”14 Thus, the Commission had the option to modify the RBP Proposal to 
make it voluntary, in line with the stakeholder proposal.15 
 
The Commission’s orders must be supported by reasoned decision-making and cannot 
rely on a “bare conclusion” without explanation.16 The Commission must “respond to 
objections…in more than a cursory fashion.”17 The Commission neglected to address NOVEC’s 
arguments that PJM should be required to adopt the voluntary, subscription-based model in lieu 
of the RBP Proposal. The Commission neglected even to acknowledge NOVEC’s argument. The 
only reference to the voluntary, subscription-based model that was approved by the stakeholders 
appears in paragraph 12 of the Commission’s order, where the Commission describes the 
background to the RBP Proposal.18 The Commission is further required to consider reasonable 
alternatives to its decision.19 Because the Commission did not address NOVEC’s arguments, it 
did not engage in reasoned decision-making. 
 
As NOVEC set forth in its pleadings, the RBP Proposal is not just and reasonable 
because it imposes an unreasonable and excessive collateral obligation on RBP buyers; the 
proposed cost allocation is not just and reasonable because it does not recognize other causes of 
the capacity shortfall and because it results in NOVEC and other RBP buyers potentially 
subsidizing other capacity customers; the RBP framework is not just and reasonable because it 
requires too many MWs to offset each RBP buyers’ pro rata share of the RBP Target; and the 
 
14 RBP Proposal at 3 (internal citation omitted). 
15 Even if the Commission did not believe it had that authority, it did have the authority to reject the RBP with 
guidance on what might constitute a just and reasonable proposal.  
16 Emera Me. v. FERC, 854 F.3d 9, 27 (D.C. Cir. 2017).  
17 TANC, 628 F.3d at 543-44. 
18 RBP Order at P 12.  
19 Laclede Gas Co. v. FERC, 873 F.2d 1494, 1498 (D.C. Cir. 1989) (“[W]here a party raises facially reasonable 
alternatives to FERC’s decision . . . the agency must either consider those alternatives or give some reason, within 
its broad discretion . . . for declining to do so.”) (internal citation omitted); see also Am. Gas Ass’n v. FERC, 593 
F.3d 14 (D.C. Cir. 2010).

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RBP improperly relies on potentially flawed load forecasts which were not designed to allocate 
costs in this manner.20 While the RBP’s final design remains subject to the outcome of a paper 
hearing, the overall framework is not just and reasonable, and it should have been rejected or 
modified to address its deficiencies. In support of that result, NOVEC presented the reasonable 
alternative of adopting the voluntary, subscription-based framework that a supermajority of PJM 
had voted in favor of adopting, as it would address all the flaws that NOVEC identified. NOVEC 
respectfully submits that the Commission should set aside its order, consider the proposed 
alternative, and require PJM to adopt the voluntary, subscription-based model version of the 
RBP approved in the PJM stakeholder process.  
B. 
The RBP distorts the Reliability Pricing Model (“RPM”) price signals and unduly 
discriminates against LSEs serving large loads. 
 
The RBP is a fundamental departure from how the RPM operates. The RPM is designed 
to procure capacity for all customers using a market structure where the price signals sent by the 
auction’s outcome encourage generation to enter (or exit) the market in response to demand.21 
The RPM is operated “to ensure that enough capacity is procured, at a reasonable cost, to 
maintain reliable grid operations.”22 The RPM is intended to allow generators providing capacity 
an opportunity to recover their fixed costs while giving customers the opportunity to procure the 
least-cost option for capacity as a service. Thus, the auction clearing price (“ACP”) varies from 
year to year based on the supply present in the market for the series of auctions for each year, the 
demand from load, and the costs of providing the service, which are a blend of the clearing 
prices for the auctions in each year’s series. Generators do not receive a firm price from year to 
year, but neither do capacity buyers. All are exposed to the potential for significant price 
 
20 See NOVEC Protest; NOVEC Answer.  
21 See NOVEC Answer at 4-5.  
22 PJM Interconnection L.L.C., 190 FERC ¶ 61,084, P 3 (2025).

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volatility, which is the point. Although customers can choose to procure bilateral capacity as a 
way to hedge that volatility, it is not required, and a completely satisfactory way to procure 
capacity has always been solely through the RPM.23 
 
Except for those utilities with a Fixed Resource Requirement (“FRR”) plan, all utilities in 
PJM rely on the RPM, in some measure, to procure the capacity they must maintain. NOVEC’s 
own experience has led it to largely rely on the PJM markets for capacity and energy.24 Virginia 
initially deregulated the electric industry to introduce retail competition but subsequently 
reregulated it.25 The legacy of these events, along with the establishment of the RPM, led 
NOVEC to rely on the RPM to supply its capacity.  
 
In contrast to the RPM, the RBP is a cost-based rate that provides a fixed and certain 
amount of revenue for capacity for whichever is shorter: 15 years or the life of the resource. It 
employs a contract-for-difference mechanism where the RBP Resource bids into the RPM as a 
price-taker and is compensated for the shortfall between its PJM-accepted contract price and the 
ACP. In addition to providing a long-term price guarantee, the RBP further differs from the RPM 
in that it imposes costs and obligations of providing that long-term price guarantee on only a 
subset of LSEs that provide retail service to large loads that were identified in a single 2026 
Load Adjustment. For all other LSEs that are or will be providing retail service to large loads 
that materialize later than the forecasts on which PJM premised its RBP Proposal, there are no 
 
23 PJM Business Practice Manual No. 18 at § 1.2.1 (“Under RPM, each LSE that serves load in a PJM Zone during 
the Delivery Year shall be responsible for paying a Locational Reliability Charge equal to their Daily Unforced 
Capacity Obligation in the Zone multiplied by the Final Zonal Capacity Price applicable to that Zone. LSEs may 
choose to hedge their Locational Reliability Charge obligations by directly offering and clearing resources in the 
Base Residual Auction and Incremental Auctions or by designating self-supplied resources (resources directly 
owned or resources contracted for through unit-specific bilateral purchases) as self-scheduled to cover their 
obligation in the Base Residual Auction.”). 
24 NOVEC does own a small biomass facility, but its load dwarfs its generation capacity. See NOVEC’s Halifax 
County Biomass Electric Generating Facility (https://www.novec.com/About_NOVEC/SBE.cfm).  
25 Appalachian Power Co. v. State Corp. Comm’n, 284 Va. 695 (2012).

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additional charges and collateral requirements, even if the capacity shortfall persists. For them, 
the rules of RPM are unchanged. For the first time ever, PJM has proposed and the Commission 
has approved a paradigm that sets different terms of service for some LSEs but not others. 
 
There are two principal consequences of the RBP apart from the issues NOVEC raised 
relating to cost allocation: 
1. 
The RBP distorts the RPM market by suppressing the capacity price and 
interfering with price formation. 
 
The RBP suppresses the capacity price, which is the result whenever some generation 
must bid into the market as price-takers.26 The suppressed capacity price mutes the market signal 
for non-RBP generation to enter the RPM, which risks compounding the RPM’s inability to 
procure new generation.27 The Commission responded to concerns about requiring RBP 
Resources to offer into the RPM Auctions as price-takers “because the requirement will likely 
suppress RPM prices, leading to premature generator retirements and artificial shortages” by 
reasoning that the Commission has “consistently found that Regional Transmission 
Organizations and Independent System Operators can reasonably require resources that are 
compensated outside of the capacity market because they are needed to maintain reliability to 
offer as price-takers in capacity auctions to avoid double procurement, even at the risk of price 
suppression.”28 
 
26 New Jersey Board of Public Utilities v. FERC, 744 F.3d 74, 85 (3d Cir. 2014) (describing how offering capacity 
“at artificially low prices that are sure to clear the auction...crowd[s] out other capacity that is priced at a higher, 
cost-based rate, and thus result[s] in a lower overall clearing price.”).  
27 NOVEC Answer at n.53 (“It goes without saying that in addition to the price depressive effect benefiting other 
customers, it also distorts the PJM capacity market signals by altering the price signals being sent. The Commission 
should not lose sight of the fact that a cost-based intervention is not going to solve the problems with PJM’s market 
structure.”). 
28 RBP Order at P 53.

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The Commission relied solely on its prior orders authorizing the inclusion of reliability-
must-run (“RMR”) units as price-takers in the supply stack for RPM,29 but having RBP 
Resources bid as price-takers is not the same as having RMR units bid as price-takers. The RMR 
cases the Commission relies on in the RBP Order make this point effectively and demonstrate 
why the RBP should be rejected as unjust and unreasonable. Unlike the RBP, which would 
disrupt price formation for 15 years, Commission precedent “has emphasized that RMR 
agreements should be of a limited duration so as to not perpetuate out-of-market solutions that 
have the potential, if not undertaken in an open and transparent manner, to undermine price 
formation.”30 An RMR should only be “entered into in the first place as a last-resort measure.”31 
Capacity markets “are designed to achieve resource adequacy in the region” and the Commission 
emphasized the need to make “market rule changes before pursuing an RMR agreement.”32 
 
The RBP is distinct as a matter of duration, exigency, and scale. The RBP contracts are 
each to last a decade and a half (i.e., 15 years), during which time the RBP will suppress the 
capacity price and interfere with price formation, hindering the entry of unsubsidized generation 
into the market. In terms of exigency, while NOVEC agrees that the capacity shortfall is an issue 
that must be addressed, PJM has not made an effort to seek changes to market rules before 
introducing out-of-market payments and has not shown that there is an immediate, specific need 
for the RBP. In comparison, when FERC approved the contested settlement on the Brandon 
Shores and Wagner RMRs and allowed the inclusion of the uneconomic units as price-takers in 
the RPM,33 it was in the context of PJM informing the Commission in supporting comments that 
 
29 PJM Interconnection, L.L.C., 196 FERC ¶ 61,098, P 21 (2026).  
30 N.Y. Indep. Sys. Operator, Inc., 150 FERC ¶ 61,116, P 2 (2015) (emphasis added). 
31 N.Y. Indep. Sys. Operator, Inc., 155 FERC ¶ 61,076, P 33 (2016).  
32 N.Y. Indep. Sys. Operator, Inc., 161 FERC ¶ 61,189, P 63 (2017).  
33 H.A. Wagner, LLC, 191 FERC ¶ 61,098 (2025).

10 
 
deactivating Brandon Shores would cause “nearly 600 reliability violations, including severe 
voltage drop and thermal violations across seven distinct PJM zones (particularly under N-1-1 
contingency conditions), which could in turn lead to a widespread voltage collapse in Baltimore, 
Maryland and the immediately surrounding areas (e.g., the BGE, APS, ME, PPL, PECO, PEPCO 
and DOM Zones)” with a similar observation for Wagner.34 And the scale of the RBP dwarfs the 
RMR tariffs with respect to both the amount of capacity involved and the duration of the 
commitments to that capacity. The RBP auction and the related Qualifying RBP Offset UCAP 
MW would have committed PJM to somewhere between 6,831.3 MW and 9,033.2 MW for a full 
15 years. Far from supporting the RBP Proposal’s acceptance, the Commission’s RMR precedent 
actually warrants rejection of the RBP due to the disproportionate, lasting impacts on the RPM’s 
ability to send accurate price signals. 
 
The RBP, with its out-of-market payments, attaches a traditional cost-of-service model to 
PJM’s market paradigm, both implying that the RPM has failed and potentially triggering a 
failure of the RPM. In order for markets to work, investors must have confidence that they will 
have an opportunity to earn a return, and that confidence requires a degree of certainty. The RPM 
has been anything but certain in recent years. As NOVEC noted in its protest, PJM sought a price 
cap rather than allow the RPM to clear at the price the PJM Tariff would otherwise have 
provided to spur the entry of new generation.35 As that price cap expires (assuming it is not 
 
34 PJM, Comments in Support of Joint Offer of Settlement, Docket Nos. ER24-1787-001 and ER24-1790-001, at 2 
(Feb. 14, 2025) (Accession No. 20250214-5153).  
35 See NOVEC Protest at 14. As PJM stated: “The practical consequence is that the capacity market, working as 
designed, will need to print prices at or above the administrative Net CONE for an extended period in order to attract 
entry of new supply. But as the paper’s analysis in the following sections makes clear, those prices – while 
economically necessary – will collide with the political and affordability realities of a system where much of the 
native load appears not to have been hedged against capacity price cycles of the magnitude now being observed.”  
PJM, Powering Reliability Through Market Design: Addressing Rising Demand and Constrained Supply, and 
Stimulating Investment to Support Durable Reliability at 23-24 (May 6, 2026) (20260506-powering-reliability-
through-market-design.pdf) (“PJM Report”).

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extended again), PJM’s new solution is to single out some LSEs to pay new generation to enter 
the market directly and with no commercial risk, which will also suppress the price. Because 
there is an intervention on every occasion available to lower the price, investors will begin – if 
they have not already, as PJM’s insistence on the need for the RBP in the first place suggests 
they might have – to incorporate expectations that they will not receive the ACP into their 
investment decisions, which creates a negative feedback loop causing investors to avoid entering 
the market no matter how high the ACP rises in anticipation of an intervention to again reduce 
the revenue they receive. PJM itself has identified this problem, commenting that “[t]his is the 
essence of the credibility trap: The signal that is required to attract investment is the same signal 
that triggers the intervention that undermines it.”36 The RBP is a further sign that the RPM’s 
price signals cannot be trusted — and worse, it creates an incentive for investors to wait out the 
ordinary process and only enter when PJM has volunteered captive customers for a fixed rate, 
15-year contract.  
2. 
The RBP sanctions undue discrimination against LSEs that serve large loads 
and must be rejected under the FPA. 
 
The RBP constitutes undue discrimination against LSEs that serve large loads. As the 
Commission explained in its order on the Interim Resource Adequacy Service (“IRAS”), 
“[h]istorically, PJM’s capacity market has treated all load taking NITS comparably, procuring 
capacity on its behalf regardless of retail customer class or whether the load is new or 
existing.”37 The RBP means PJM will no longer be treating all LSEs equally in terms of capacity, 
and will now be singling out certain of those LSEs that serve large loads to take on an additional 
charge and possibly38 a burdensome collateral obligation. Just as the Commission observed in the 
 
36 PJM Report at 24.  
37 PJM Interconnection, L.L.C., 197 FERC ¶ 61,019, P 94 (2026) (“IRAS Order”).  
38 NOVEC recognizes that the Commission has set the collateral obligation for further procedures.

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IRAS Order, PJM is distinguishing between different LSEs taking NITS for purposes of 
procuring capacity and “fails to provide sufficiently detailed evidence to support why Electric 
Distributors and LSEs using NITS to serve New Large Loads should not be treated comparably 
to Electric Distributors and LSEs using NITS to serve equivalent quantities of load growth.”39 
 
Discrimination is not undue when the entities are not similarly situated such that there is 
good cause for the different treatment.40 In this case, the only reason that PJM gave for the 
disparate treatment is the general assertion that the “zones/areas and LSEs can be said to have 
caused the resource adequacy shortfall reflected in the 2028/2029 Delivery Year BRA” because 
they have new large loads.41 Although the Commission seemingly accepted PJM’s rationale for 
discrimination with respect to the RBP, the Commission made the opposite finding in the IRAS 
Order, commenting that: 
We note PJM’s explanation that New Large Loads have unique 
characteristics compared to traditional load growth and are the primary 
cause for the resource adequacy shortfall, assertions with which some 
commenters agree, but we find that PJM’s generic references to these retail 
customer characteristics without more detail are insufficient evidence to 
counter the current resource adequacy construct in PJM, i.e., that PJM will 
procure sufficient capacity to serve all NITS load in the PJM Region. 
Therefore, we find that, in its current filing, PJM did not adequately support 
its proposal to treat Electric Distributors and LSEs differently based on the 
characteristics of their retail customers.42 
The Commission cannot simultaneously maintain two opposing, contrary points of view and yet 
meet its obligation to engage in reasoned decision-making. When the Commission reconsiders 
RBP in conjunction with the arguments raised by NOVEC about the other causes of the capacity 
 
39 IRAS Order at P 94.  
40 Tenaska Clear Creek Wind, LLC v. FERC, 108 F.4th 858, 868 (D.C. Cir. 2024).  
41 RBP Proposal at 103.  
42 IRAS Order at P 94 (internal citation omitted).

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shortfall which the Commission did not address in its order,43 NOVEC respectfully submits that 
the record before it demands rejection of the RBP Proposal due to undue discrimination against 
LSEs serving large loads as retail customers.  
C. 
The Commission should clarify that all aspects of the RBP’s cost allocation are 
subject to further proceedings. In the alternative, the Commission erred by 
approving a framework for cost allocation that does not comport with the cost-
causation principle. 
1. 
Request for Clarification 
 
NOVEC respectfully requests that the Commission dispel any ambiguity as to the scope 
of the paper hearing and clarify that the Commission has set all issues concerning cost allocation 
for further procedures, and that it is not limiting those procedures to considering a variation of 
PJM’s proposal to assign the costs entirely to LSEs serving large loads as retail customers. The 
Commission found “that PJM’s proposed RBP cost allocation method may be unjust and 
unreasonable.”44 However, FERC also states in the RBP Order that allocating RBP costs to 
Electric Distributor zones/areas based on a snapshot of load growth between 2026/2027 and 
2028/2029 “may be just and reasonable, because it reasonably assigns costs to those responsible 
for the near-term capacity shortfall.”45 The Commission then comments that “relying on Load 
Adjustments to measure load growth” may be inconsistent or not reflect forecasted or actual 
growth of large loads and thus the method may be unjust and unreasonable.46 
 
That discussion, and the commentary in paragraphs 155 and 156, could create the 
inference that the Commission is only willing to consider variations on PJM’s proposal and is 
not willing to explore a methodology for cost allocation that reflects true causation. Even that 
 
43 Which also rendered the Commission’s order not the product of reasoned decision-making. TANC, 628 F.3d at 
543-44. 
44 RBP Order at P 153.  
45 Id. P 154. 
46 Id.

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conclusion is challenged by the Commission’s statement that: “Having found that PJM’s 
proposed method for allocating RBP costs among Electric Distributor zone/areas may be unjust 
and unreasonable, and because we are ordering paper hearing procedures to examine a 
reasonable cost allocation method, we decline to further address arguments raised in the protests 
related to PJM’s proposed cost allocation method at this time.”47 The final statement suggests 
that the Commission intends for the paper hearing to encompass all alternative methodologies for 
cost allocation.48 NOVEC respectfully requests that the Commission confirm this interpretation 
and clarify that the Commission has not ruled out any methodologies for cost allocation and has 
not yet rejected NOVEC’s arguments. 
2. 
Alternative Request for Rehearing 
 
If the Commission does not grant the foregoing request for clarification, NOVEC 
respectfully seeks rehearing of the Commission’s order with respect to cost allocation. At the 
outset, the Commission’s order, if final for purposes of rehearing, is deficient under TANC 
because the Commission stated that it declined to “to further address arguments raised in the 
protests related to PJM’s proposed cost allocation method at this time.”49 The Commission must 
set aside the order and fully address NOVEC’s arguments regarding cost allocation.50 
 
But even if the Commission were to address NOVEC’s arguments on cost allocation, the 
RBP Proposal as filed must be rejected because it violates the Commission’s cost-causation 
principle. The FPA requires the Commission to ensure that all rates charged are just and 
reasonable.51 Over time, the Commission and the courts “have added flesh to these bare statutory 
 
47 Id. P 157.  
48 NOVEC notes that adopting the voluntary, subscription-based model with an interruptible form of transmission 
service would eliminate the need to consider alternative methodologies to allocate costs.  
49 RBP Order at P 157. 
50 TANC, 628 F.3d at 543-44. 
51 16 U.S.C. §§ 824d, 824e.

15 
 
bones, establishing what has become known in Commission parlance as the ‘cost-causation’ 
principle.”52 The principle requires that all approved rates reflect to some degree the costs 
actually caused by the customer who must pay them, and the courts “evaluate compliance with 
this unremarkable principle by comparing the costs assessed against a party to the burdens 
imposed or benefits drawn by that party.”53 While adhesion to the cost-causation principle does 
not require “exacting precision,”54 the Commission must have an “articulable and plausible 
reason” to believe that the benefits are roughly commensurate with costs.55 In the final analysis, 
the Commission is “not authorized to approve a pricing scheme that requires a group of utilities 
to pay for facilities from which its members derive no benefits, or benefits that are trivial in 
relation to the costs sought to be shifted to its members.”56 
 
The cost-causation principle ensures that rates are just by preventing subsidization by 
ensuring that costs and benefits correspond to each other.57 The statutory mandate that rates be 
just cannot “be sacrificed…for some separate policy interest.”58 It is axiomatic that those that 
cause a cost, benefit from it as well.59 NOVEC explained in its protest and in its answer that 
there are two causes to the shortfall: load growth associated with large loads, but also the early 
 
52 K N Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992). 
53 Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1368 (D.C. Cir. 2004); see also Old Dominion 
Electric Cooperative v. FERC, 898 F.3d 1254, 1255 (D.C. Cir. 2018). 
54 Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1371 (D.C. Cir. 2004). 
55 Illinois Commerce Commission v. FERC, 576 F.3d 470, 477 (7th Cir. 2009). 
56 Id. at 476; see also Entergy Arkansas, Inc., Initial Decision, 142 FERC ¶ 63,017, P 114 (2013) (“The cost 
causation principle dictates this result. Unlike the network customers, the point-to-point customers did not ask 
Entergy to expand the WPP to permit them to participate, thereby causing Entergy to incur costs. Nor do the point-
to-point customers derive benefits from the WPP… Consequently, allocating any of the WPP expenses to point-to-
point customers would be neither just nor reasonable.”), aff’d, Entergy Arkansas, Inc., Opinion No. 532, 148 FERC 
¶ 61,059 (2014). 
57 El Paso, 76 F.4th at 361 (citing Transmission Planning & Cost Allocation by Transmission Owning & Operating 
Public Utilities, Order No. 1000-A, 139 FERC ¶ 61,132, P 578 (2012); BNP Paribas Energy Trading GP, 743 F.3d 
at 268; Nat’l Ass’n of Reg. Util. Comm’rs., 475 F.3d at 1285).  
58 El Paso, 76 F.4th at 361. 
59 Illinois Commerce Commission v. FERC, 576 F.3d 470, 476 (7th Cir. 2009).

16 
 
retirement of existing generation due to policies enacted by states in PJM’s footprint, and the 
inability to bring replacement generation online.60 Despite that fact, the RBP allocates all costs to 
LSEs serving large loads, a result inconsistent with the cost-causation principle. 
 
NOVEC is also compelled to reiterate that the rest of PJM market participants will 
benefit from RBP Resources funded by NOVEC and other LSEs serving large loads in a more 
direct sense. Requiring RBP Resources to bid into the market as price-takers suppresses the 
capacity price. The suppressed capacity prices benefit other capacity customers who benefit from 
a reduced capacity price. The suppressed capacity price can also harm RBP Buyers, who are 
responsible for a contract for difference: because RBP Buyers have to fund (or receive) the 
difference between the RPM clearing price and the fixed RBP price, a suppressed capacity price 
means they may pay more when they are forced to true-up the RPM ACP to the RBP, and they 
may get a lower payment in years where the RPM exceeds the RBP price. Essentially, NOVEC 
and other RBP Buyers would be subsidizing the rest of the capacity market, a result that is not 
consistent with the cost-causation principle. And after the first 15-year period, the generation 
will remain available to the capacity market – a clear benefit, even if difficult to quantify at this 
time.  
 
To be clear, NOVEC is not taking the position that load growth is not responsible for 
most of the costs. NOVEC is not taking the position that the Commission must perfectly allocate 
costs between the LSEs serving large loads and the rest of PJM. NOVEC is concerned that the 
principle in the Ratepayer Protection Pledge, which is meant to only hold “traditional” customers 
harmless, is being applied in a way that is inconsistent with the cost-causation principle because 
the RBP’s cost allocation does not reflect any recognition of the benefits drawn by other capacity 
 
60 NOVEC Protest at 11-14; NOVEC Answer at 9-11.

17 
 
customers, not even the direct impact on capacity prices. The Commission need not perfectly 
match benefit and burden, but it cannot ignore them. Further, the permanence of the 
methodology risks an unjust result, as there is no ability to reconsider or adjust it in light of new 
circumstances to avoid burdensome and untenable financial obligations. As it stands now, the 
RBP Proposal sacrifices the statutory mandate that rates be just, which requires the prevention of 
subsidization by ensuring that costs and benefits correspond to each other, for the policy interest 
of attempting to ensure in so much that FERC’s jurisdiction allows that data centers pay any and 
all costs associated with serving their needs. The statute does not allow that result. Thus, if the 
Commission does not grant clarification, it should set aside its order and reject the RBP with 
guidance. 
III. 
CONCLUSION 
WHEREFORE, for the foregoing reasons, NOVEC respectfully requests that the 
Commission grant its request for rehearing and require PJM to adopt the voluntary stakeholder 
framework. In the alternative, NOVEC requests that the Commission grant rehearing, set aside 
its order, and reject the RBP without further procedures. NOVEC further requests clarification 
that all issues relating to the methodology to allocate the costs of the RBP Resources are within 
the scope of the paper hearing, or in the alternative grant rehearing with respect to cost 
allocation.

18 
 
 
Respectfully submitted, 
 
  //s// Alan I. Robbins 
 
Alan I. Robbins 
Debra D. Roby 
Thomas B. Steiger III 
Peter E. Colvin 
Washington Energy Law LLP 
900 17th Street. N.W., Suite 500-A  
Washington, D.C. 20006 
Tel: (202) 326-9313 
Email: arobbins@washingtonenergylaw.com 
droby@washingtonenergylaw.com 
tsteiger@washingtonenergylaw.com 
pcolvin@washingtonenergylaw.com 
 
Counsel to Northern Virginia Electric Cooperative, Inc. 
 
Dated: October 29, 2026.

CERTIFICATE OF SERVICE 
I hereby certify that I have this day served the foregoing document upon each person 
designated on the official service list compiled by the Secretary of the Federal Energy 
Regulatory Commission in ER26-3380 and EL26-108. 
Dated at Washington, D.C. this 29th day of October, 2026. 
 
  //s// Jessika Dziechciowska  
 
Jessika Dziechciowska 
Energy Practice Analyst 
Washington Energy Law LLP 
900 17th Street, N.W., Suite 500-A 
Washington, D.C. 20006 
Tel: (202) 326-9308  
Email: jdziechciowska@washingtonenergylaw.com