The opinion
United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued March 14, 2022 Decided August 9, 2022
No. 15-1183
CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.,
PETITIONER
v.
FEDERAL ENERGY REGULATORY COMMISSION,
RESPONDENT
HUDSON TRANSMISSION PARTNERS, LLC, ET AL.,
INTERVENORS
Consolidated with 15-1188, 16-1153, 19-1002, 20-1074, 20-
1077, 20-1082, 20-1269, 20-1351, 20-1382
On Petitions for Review of Orders
of the Federal Energy Regulatory Commission
Richard P. Bress argued the cause for petitioners. With
him on the joint briefs were Neil H. Butterklee, Susan J.
LoFrumento, Sebrina M. Greene, Gary D. Levenson, William
R. Hollaway, Lucas C. Townsend, David L. Schwartz, Eric J.
Konopka, Shannon M. Grammel, Lawrence G. Acker, Gary D.
Bachman, and Michael Diamond. Elias G. Farrah and Andrew
F. Neuman entered appearances.
2
Kevin M. Lang, John Sipos, John C. Graham, and Alina
Buccella were on the joint brief for intervenors City of New
York and New York State Public Service Commission in
support of petitioners.
Elizabeth E. Rylander, Attorney, Federal Energy
Regulatory Commission, argued the cause for respondent.
With her on the brief were Matthew R. Christiansen, General
Counsel, Robert H. Solomon, Solicitor, and Susanna Y. Chu,
Attorney.
David M. Gossett argued the cause for intervenors
American Electric Power Service Corporation, et al. in support
of respondent. With him on the joint brief were John
Longstreth, Donald A. Kaplan, Richard P. Sparling, Stacey
Burbure, Cara J. Lewis, and Steven M. Nadel. Kenneth R.
Carretta, Amanda R. Conner, Vilna W. Gaston, William M.
Keyser III, Morgan Parke, Bradley Miliauskas, and P. Nikhil
Rao entered appearances.
No. 20-1079
NEW JERSEY BOARD OF PUBLIC UTILITIES,
PETITIONER
v.
FEDERAL ENERGY REGULATORY COMMISSION,
RESPONDENT
PUBLIC SERVICE ELECTRIC AND GAS COMPANY, ET AL.,
INTERVENORS
Consolidated with 20-1080, 20-1081
3
On Petitions for Review of Orders
of the Federal Energy Regulatory Commission
Alec Schierenbeck, Deputy State Solicitor, Office of the
Attorney General for the State of New Jersey, argued the cause
for petitioner. With him on the briefs were Andrew J. Bruck,
Acting Attorney General, and Paul Youchak and Nathaniel
Levy, Deputy Attorneys General. Alex Moreau, Deputy
Attorney General, entered an appearance.
Susanna Y. Chu, Attorney, Federal Energy Regulatory
Commission, argued the cause for respondent. With her on the
brief were Matthew R. Christiansen, General Counsel, Robert
H. Solomon, Solicitor, and Elizabeth E. Rylander, Attorney.
Lucas C. Townsend argued the cause for intervenors
Consolidated Edison Company of New York, Inc., et al. in
support of respondent. With him on the brief were Neil H.
Butterklee, Susan J. LoFrumento, Richard P. Bress, David L.
Schwartz, Eric J. Konopka, Gary D. Levenson, William R.
Hollaway, Lawrence G. Acker, Gary D. Bachman, and Brian
M. Zimmet.
Before: KATSAS and RAO, Circuit Judges, and
SILBERMAN, Senior Circuit Judge.
Opinion for the Court filed PER CURIAM.
PER CURIAM: Part of the electricity transmission grid in
northern New Jersey was aging, storm-damaged, and
vulnerable to short circuits. In response, PJM Interconnection,
LLC (“PJM”)—the regional transmission organization
4
responsible for managing the grid in New Jersey—authorized
a series of upgrades to facilities owned by the Public Service
Electric and Gas Company (“PSE&G”). One set of
improvements centered on the transmission corridor between
PSE&G’s Bergen and Linden switching stations; a second
involved repairs to and around PSE&G’s Sewaren substation.
Together, these two projects cost around $1.3 billion. Initially,
PJM assigned most of the projects’ costs to entities that reroute
electricity from northern New Jersey into the New York
market. Thereafter, the New York-based entities gave up their
rights to withdraw electricity from New Jersey, and PJM
reassigned their costs to PSE&G.
The Federal Energy Regulatory Commission (“FERC” or
“the Commission”) approved both rounds of cost allocations.
The petitions for review in these two cases are about whether
these cost allocations were “just and reasonable” under the
Federal Power Act, 16 U.S.C. §§ 824d(a), 824e(a), and
whether FERC’s orders were “arbitrary [and] capricious” in
violation of the Administrative Procedure Act (“APA”), 5
U.S.C. § 706(2)(A). In effect, they are about who must pay the
bill.
I.
The thirteen petitions for review before us challenge
twenty FERC orders, involve numerous parties, implicate a
series of related legal issues, and arise from a complex
procedural history. We begin by setting out the regulatory and
factual background needed to understand these petitions.
A.
The Federal Power Act gives FERC “jurisdiction over
facilities that transmit electricity in interstate commerce,” Old
Dominion Elec. Coop. v. FERC, 898 F.3d 1254, 1255 (D.C.
5
Cir. 2018), and requires that the rates charged for such
transmission be “just and reasonable,” 16 U.S.C. § 824d(a).
“For decades, the Commission and the courts have understood
this requirement to incorporate a ‘cost-causation principle’—
the rates charged for electricity should reflect the costs of
providing it.” Old Dominion, 898 F.3d at 1255. “[A]lthough
the Commission need not allocate costs with exacting
precision, the costs assessed against a party must bear some
resemblance to the burdens imposed or benefits drawn by that
party.” Pub. Serv. Elec. & Gas Co. v. FERC (“Artificial
Island”), 989 F.3d 10, 13 (D.C. Cir. 2021) (cleaned up).
Utilities, independent system operators, and regional
transmission organizations must seek approval from FERC for
new rates through the process outlined in section 205 of the
Federal Power Act. See 16 U.S.C. § 824d(d)–(e). Section 206
permits “the Commission [to] investigate—on its own
initiative or based on a third-party complaint—whether an
existing rate is ‘unjust, unreasonable, [or] unduly
discriminatory.’” Artificial Island, 989 F.3d at 13 (quoting 16
U.S.C. § 824e(a)). “[U]ndue discrimination occurs [where]
entities [that] are similarly situated” are charged different rates
for no discernable reason. Mo. River Energy Servs. v. FERC,
918 F.3d 954, 958 (D.C. Cir. 2019) (cleaned up). In a section
206 proceeding, if FERC finds the existing rate is “unjust,
unreasonable, [or] unduly discriminatory,” it must “determine
the just and reasonable rate.” 16 U.S.C. § 824e(a).
B.
These petitions arise out of the legal relationships between
the parties as well as the FERC-approved method by which
PJM allocates the costs of major infrastructure projects on its
transmission grid.
6
1.
PJM is the regional transmission organization responsible
for coordinating the transmission of electricity in the mid-
Atlantic region, which stretches from North Carolina to New
Jersey. The dominant electricity provider in northern New
Jersey is PJM-member PSE&G. Across the Hudson River, the
New York grid is managed by the New York Independent
System Operator, Inc. (“NYISO”). Electricity in New York
City is transmitted and sold by the Consolidated Edison
Company of New York, Inc. (“ConEd”) and the New York
Power Authority (“NYPA”), among other utilities.
The PJM and NYISO grids are interconnected, with large
quantities of electricity flowing between New Jersey and New
York across the jurisdictional line. Two of the longstanding
connections between these grids are central to the petitions
before us. First, beginning in the 1970s, PSE&G entered into
an electricity swapping agreement with ConEd. The parties
clarified the terms of this “wheeling agreement” most recently
in a 2009 settlement. See PJM Interconnection, LLC, 132
FERC ¶ 61,221 (2010) [ConEd-PSE&G Settlement Order].
Under the settlement, ConEd agreed to redirect 1,000
megawatts of electricity from upstate New York into PSE&G’s
transmission network in northern New Jersey; in return,
PSE&G agreed to route the same amount of electricity from
New Jersey into New York City. Id. at P 23. This wheeling
agreement allowed ConEd to serve its customers in New York
City without having to build a new transmission line into the
city. See id. at P 2.
Second, because the prices of electricity on the PJM and
NYISO grids sometimes diverge, a handful of “merchant
transmission facilities” have sprung up to capitalize on the
arbitrage opportunity. Two such facilities—Linden VFT, LLC
7
(“Linden”) and Hudson Transmission Partners, LLC
(“Hudson”)—are petitioners here. When prices in New Jersey
are lower, Linden and Hudson reroute electricity from New
Jersey into the New York market and resell it at a profit. 1 In
order to provide reliable, on-demand service to their New York
customers, Linden and Hudson have historically held “firm
transmission withdrawal rights,” which permit them to extract
an agreed-upon amount of electricity from the PJM grid at
(almost) any time.
2.
One of PJM’s primary responsibilities is overseeing the
coordinated development of the mid-Atlantic grid and
apportioning the costs of major grid improvements among its
member utilities.
In 2011, FERC’s “Order No. 1,000” directed each
planning region to select an ex ante “method, or set of methods,
for allocating the costs of new transmission facilities selected
in [its] regional transmission plan,” and to submit their chosen
method for FERC’s approval. Transmission Planning and
Cost Allocation by Transmission Owning and Operating
Public Utilities, 136 FERC ¶ 61,051 at P 558 (2011) [Order
No. 1,000]; see id. at P 603. The Commission gave each region
leeway to design its own cost allocation method, id. at PP 605–
06, but set out six general cost allocation principles that are
binding on all planning regions. As relevant here, Order No.
1,000 requires that every region’s cost allocation method
reflect the Federal Power Act’s cost causation principle
(Principle 1), and that the costs of any new project be assigned
1
Hudson’s primary customer is NYPA. By contract, NYPA is
responsible for the full costs of any improvements to the PJM grid
that are assigned to Hudson.
8
only to parties within the project’s planning region, unless a
party outside the region agrees to assume costs (Principle 4).
Id. at PP 622, 657. Order No. 1,000 required each region to use
its ex ante cost allocation method only for “regional plan”
projects—that is, projects undertaken to meet the region’s
minimum transmission capacity and grid reliability criteria.
See Old Dominion, 898 F.3d at 1256.
Pursuant to Order No. 1,000, PJM developed an ex ante
cost allocation method and incorporated it into its Open Access
Transmission Tariff. For projects that improve grid reliability,
PJM’s method allocates half the costs of high-voltage facilities,
and all the costs of low-voltage facilities, through a “flow-
based method” called “solution-based distribution-factor
analysis,” or “DFAX.” See PJM Tariff, Sched. 12(b)(iii). As
explained further below, see infra Part IV.A.1, “[t]he flow-
based method assigns costs based on how much each utility
uses the facility in question over time,” Long Island Power
Auth. v. FERC, 27 F.4th 705, 711 (D.C. Cir. 2022); see
Artificial Island, 989 F.3d at 14. Using proprietary software,
the DFAX method models how electricity will flow across a
new transmission facility at moments of peak grid use (i.e., at
“peak load”), and assigns costs proportionally, based on the
projected use of the facility by utilities in each “zone” of the
PJM grid. PJM spreads the DFAX costs of regional plan
projects over a number of years, to account for utilities’
evolving use of the grid.
The DFAX method also assigns costs to entities that
withdraw electricity from the PJM grid. Merchant
transmission facilities like Linden and Hudson are assigned
DFAX costs based on their firm withdrawal rights. See PJM
Tariff, Sched. 12(b)(iii)(A)(3). In other words, the DFAX
method assumes that when the grid is running at peak load,
merchant transmission facilities will extract the full amount of
9
electricity to which they are entitled. Similarly, the DFAX
method assigns ConEd costs based on the assumption that,
pursuant to its wheeling agreement with PSE&G, ConEd will
withdraw 900 megawatts from the PJM grid when it is at peak
load. See id. Sched. 12(b)(xi); ConEd-PSE&G Settlement
Order, 132 FERC ¶ 61,221 at P 13.
FERC approved PJM’s cost allocation method in 2013.
See PJM Interconnection, LLC, 142 FERC ¶ 61,214 (2013).
C.
This brings us to the two projects at issue here. In 2013,
PJM approved 26 related improvements to the transmission
corridor between PSE&G’s Bergen and Linden switching
stations (collectively, “the Bergen project” or “Bergen”). The
purpose of the Bergen project was not to increase the total
amount of electricity that can flow across the PJM grid; rather,
the project was approved to mitigate the risk of short circuits
on PSE&G’s facilities. Because the anticipated short circuits
would overwhelm any commercially available circuit breaker,
PJM directed PSE&G to expand the corridor into a double-
circuit line capable of transmitting electricity at higher
voltages. This solution to PSE&G’s short-circuit issue
incidentally protected the corridor against thermal overloads.
Around the same time, PJM approved three low-voltage
subprojects to repair aging infrastructure in and around
PSE&G’s Sewaren substation (“the Sewaren project” or
“Sewaren”). Hurricane Sandy had exposed Sewaren’s
vulnerability to inclement weather. These upgrades were
meant to harden it against future storms and protect it from
short circuits. Like Bergen, the Sewaren project was not
approved to increase the overall transmission capacity of the
PJM grid. Rather, both were “reliability projects” intended to
make the grid’s existing infrastructure more resilient.
10
D.
In 2014, PJM first assigned the costs of the Bergen and
Sewaren projects in two section 205 filings. Those initial cost
allocations triggered a long-running series of FERC
proceedings that only recently concluded, giving rise to the
petitions under review.
1.
We begin at the beginning, with PJM’s 2014 rate filings.
Pursuant to its Tariff, PJM allocated most of the costs of the
Bergen project ($763 million, out of a total cost of $1.2 billion),
and all the costs of the Sewaren project ($125 million), via
DFAX. 2 PJM’s 2014 filings assigned most of the DFAX costs
for Bergen to ConEd ($629 million), with the remainder spread
between Hudson ($69 million), PSE&G ($52 million), and
Linden ($13 million). The costs of Sewaren, meanwhile, were
split between ConEd ($64 million) and Linden ($61 million).
In two subsequent 2015 and 2016 filings, PJM reallocated
Bergen’s DFAX costs to reflect the project’s evolving design
and updated grid-use data. 3
2
Most of the Bergen subprojects were high-voltage; a few were low-
voltage. For the former, half the costs were allocated on a pro rata
basis—“based on the level of customer demand within each zone”
on the PJM grid—rather than through DFAX. Old Dominion, 898
F.3d at 1256; see PJM Tariff, Sched. 12(b)(i)(A)(1). Those pro rata
cost allocations are not at issue in the petitions before us.
3
In early 2015, PJM changed its Tariff’s cost allocation method for
projects, like Sewaren, that are added to the regional plan to meet the
planning standards of individual utilities. See PJM Interconnection,
LLC, 154 FERC ¶ 61,096 at PP 2, 12 (2016). Beginning in 2015,
therefore, PJM ceased assigning Sewaren’s costs via DFAX.
11
Over the protests of ConEd, Linden, Hudson, and NYPA,
FERC accepted each of the four cost allocations. The
protestors argued that the DFAX method was built on certain
modeling conventions that systematically distorted the cost
assignments for the Bergen and Sewaren projects, minimizing
PSE&G’s cost responsibility and magnifying theirs. 4 See infra
Part IV. More fundamentally, they argued that PJM’s rate
filings violated the cost causation principle: the goal of these
projects was to make PSE&G’s infrastructure more reliable,
yet parties other than PSE&G had been assigned the vast
majority of the costs. Finally, they protested that the Tariff
gave PJM discretion to adjust any “objectively unreasonable”
DFAX cost allocation, but that PJM had unfairly declined to
exercise that discretion in the filings at issue. PJM Tariff,
Sched. 12(b)(iii)(G).
In response, FERC explained that it had previously
approved DFAX as a just and reasonable cost allocation
method. PJM had properly applied this cost allocation method
in the contested filings, so they were per se just and reasonable.
Because “[t]he reasonableness of the Solution-Based DFAX
methodology is beyond the scope of [a section 205]
proceeding,” FERC declined to scrutinize the DFAX method’s
modeling conventions. PJM Interconnection, LLC, 147 FERC
¶ 61,028 at P 43 (2014). Finally, FERC agreed with PJM that
4
The protestors argued that, by design, the DFAX method arbitrarily
favors large utilities like PSE&G at the expense of smaller entities.
More specifically, they insisted that it was not just and reasonable for
PJM’s Tariff (1) to exempt from DFAX costs any utility whose flows
across a facility are de minimis compared to its overall flows on the
PJM grid; (2) to “net” total flow, such that a utility’s positive and
negative electric flows cancel each other out; and (3) to base DFAX
costs on how electricity flows across the grid at peak load.
12
the Tariff did not give it the discretionary authority to adjust
DFAX costs ex post.
2.
Meanwhile, shortly after PJM made its initial 2014 filings,
ConEd and Linden each lodged section 206 complaints. First,
they again objected to the structural assumptions on which the
DFAX method was built. Second, they argued that it was not
just and reasonable to use DFAX to assign the Bergen and
Sewaren projects’ costs. Most projects selected for PJM’s
regional plan are “flow-based”—they are approved in response
to pent-up transmission demand and expand the total amount
of electricity that can flow across the PJM grid. DFAX was
designed with such projects in mind, on the grounds that
utilities should pay for grid expansions based on their use of
the grid’s increased capacity. But Bergen and Sewaren were
categorically distinct; they are “non-flow-based.” The short-
circuit issues they resolved were not caused by excessive
electricity flows across PSE&G’s facilities, and the utilities
who benefited from their resolution were different from those
whose electricity flows across the upgraded facilities. The
DFAX method therefore failed to match the costs of these
projects to their beneficiaries, as required by the Federal Power
Act.
FERC addressed ConEd’s complaint first. The policy
behind Order No. 1,000, it explained, was to establish a clear,
ex ante cost allocation method for major infrastructure projects
in each planning region. To that end, PJM’s Tariff did not give
it discretion to apply different cost allocation methods to
different kinds of reliability projects. FERC also found that the
DFAX method reasonably identified the beneficiaries of non-
flow-based projects, and so rejected the argument that the
DFAX method was unsuited to Bergen and Sewaren. See
13
Consol. Edison Co. of N.Y., Inc., 151 FERC ¶ 61,227 at PP 54–
55 (2015) [ConEd Complaint Order].
In 2016, FERC reaffirmed this position on rehearing, see
Consol. Edison Co. of N.Y., Inc., 155 FERC ¶ 61,088 at PP 40–
42 (2016) [ConEd Complaint Rehearing Order], and rejected
Linden’s complaint for the same reasons, see Linden VFT,
LLC, 155 FERC ¶ 61,089 at PP 54–58 (2016) [First Linden
Complaint Order]. In addition, FERC upheld the DFAX
method’s modeling conventions as just, reasonable, and not
unduly discriminatory. See ConEd Complaint Rehearing
Order, 155 FERC ¶ 61,088 at PP 45–46, 49.
Importantly, at the same time it rejected ConEd and
Linden’s complaints, FERC also affirmed the use of DFAX in
a closely related proceeding, which concerned the costs of a
third non-flow-based project in southern New Jersey (“the
Artificial Island project” or “Artificial Island”). See Del. Pub.
Serv. Comm’n, 155 FERC ¶ 61,090 at PP 65–73 (2016)
[Artificial Island Order].
3.
Soon after FERC denied its rehearing application, ConEd
notified PSE&G that it planned to allow their wheeling
agreement to lapse. PJM thereafter submitted a fifth cost
allocation, to take effect after the wheeling agreement ended.
This 2017 filing eliminated ConEd’s cost liability entirely,
placing Bergen’s DFAX costs onto Hudson ($634 million),
Linden ($132 million), and PSE&G ($128 million). The New
Jersey Board of Public Utilities (“the Board”) objected to the
filing on behalf PSE&G’s customers; Linden, Hudson, and
NYPA objected as well. Linden also lodged a section 206
complaint, protesting the cost reallocation. FERC
preliminarily accepted PJM’s 2017 filing, but did not
14
substantively address the cost allocation or Linden’s second
complaint for another three years.
Meanwhile, Hudson and Linden also took steps to
extricate themselves from cost liability for the Bergen project.
PJM’s Tariff assigns DFAX costs to merchant transmission
facilities only if they hold firm withdrawal rights, which entitle
them to extract electricity from the PJM grid on demand. See
PJM Tariff, Sched. 12(b)(iii)(A)(3). Hudson and Linden asked
PJM to convert their firm withdrawal rights to non-firm ones,
which would absolve them of DFAX costs for Bergen going
forward. The New Jersey Board intervened in the ensuing
proceedings, protesting that the proposed conversions would
unfairly foist Bergen’s entire cost onto PSE&G. But FERC
found “no reasonable basis” for preventing Hudson and Linden
from converting their withdrawal rights to non-firm ones.
Linden VFT, LLC, 161 FERC ¶ 61,264 at P 24 (2017) [Linden
Conversion Order]; PJM Interconnection, LLC, 161 FERC
¶ 61,262 at P 42 (2017) [Hudson Conversion Order].
Soon thereafter, the New Jersey Board brought a section
206 complaint. It argued that although ConEd, Linden, and
Hudson were Bergen’s primary beneficiaries, PJM had unfairly
allowed them to evade cost responsibility after construction
had begun, leaving local ratepayers to foot the bill. FERC
disagreed. Under Order No. 1,000, PJM had no authority to
place Bergen’s costs on ConEd—a utility based outside the
PJM region—after the wheeling agreement lapsed. FERC also
approved the part of PJM’s Tariff allocating DFAX costs only
to merchant transmission facilities with firm withdrawal rights.
Since PJM does not have to account for non-firm withdrawal
rights in planning its grid, it made sense to exempt facilities
with such rights from DFAX costs. FERC concluded that the
Tariff’s cost allocation method was just and reasonable and had
been properly applied in the circumstances. See N.J. Bd. of
15
Pub. Utils., 163 FERC ¶ 61,139 at P 50 (2018) [Board
Complaint Order], reh’g denied, 170 FERC ¶ 61,180 (2020)
[Board Complaint Rehearing Order].
4.
In 2018, FERC granted rehearing in the Artificial Island
proceeding—the same complaint it had earlier rejected. See
Artificial Island, 989 F.3d at 15–16 (recounting FERC’s volte-
face). The Artificial Island project was intended to stabilize
three nuclear generators in southern New Jersey. Like the
short-circuit issues remedied by the Bergen and Sewaren
projects, the stability issue that prompted the Artificial Island
project was not caused by pent-up transmission demand. All
three projects, in other words, were “non-flow-based.” After
reconsidering its initial Artificial Island order, FERC
determined that the beneficiaries of at least some non-flow-
based projects—namely, those addressing stability issues—are
“not necessarily captured” by the DFAX method. Del. Pub.
Serv. Comm’n, 164 FERC ¶ 61,035 at P 41 (2018) [Artificial
Island Rehearing Order], reh’g denied, 166 FERC ¶ 61,161
(2019) [Artificial Island Second Rehearing Order]. It therefore
directed PJM to adopt a different cost allocation method for
stability related projects. See Artificial Island Rehearing
Order, 164 FERC ¶ 61,035 at P 42; Artificial Island Second
Rehearing Order, 166 FERC ¶ 61,161 at P 43.
In 2020, FERC disposed of the outstanding filings and
complaints related to the Bergen and Sewaren projects. First,
it denied rehearing of Linden’s first complaint, which
challenged PJM’s 2014 cost allocations. FERC continued to
find that the DFAX method’s modeling conventions were just,
reasonable, and nondiscriminatory, and that DFAX reasonably
captured the beneficiaries of short-circuit projects like Bergen
and Sewaren. See Linden VFT, LLC, 170 FERC ¶ 61,122 at
16
PP 41, 44, 47 (2020) [First Linden Complaint Rehearing
Order].
Second, FERC approved PJM’s 2017 cost reallocation—
the cost distribution that came into effect after the end of
ConEd’s wheeling agreement—and denied Linden’s second
complaint (protesting the same cost allocation). See PJM
Interconnection, LLC, 170 FERC ¶ 61,124 at PP 33–35 (2020)
[Cost Reallocation Order]; Linden VFT, LLC, 170 FERC
¶ 61,123 at PP 31–35 (2020) [Second Linden Complaint
Order]. In a rehearing application contesting both orders,
Linden argued that “the use of the solution-based DFAX
method to allocate costs for a non-flow-based project was
unjust and unreasonable.” PJM Interconnection, LLC, 172
FERC ¶ 61,176 at P 14 (2020) [Second Linden Complaint
Rehearing Order]. The Bergen project “addresses a non-flow
related reliability issue,” just like the non-flow-based stability
issue in Artificial Island, but FERC had treated the two projects
differently. Id. at P 22. In response, FERC explained that it
had made a one-time exception in Artificial Island for stability
related projects, and that no such carve-out was warranted for
short-circuit projects. See id. at PP 22–24. FERC also
reiterated that the DFAX method’s modeling conventions were
just, reasonable, and nondiscriminatory. See id. at PP 27–29.
E.
As FERC successively denied their rehearing applications,
ConEd, Linden, Hudson, and NYPA (collectively, “the New
York entities”) petitioned for review of FERC’s orders
approving PJM’s five cost allocations from 2014 to 2017, as
well as its orders denying ConEd’s complaint and Linden’s two
complaints. Before they had extricated themselves from cost
liability for the Bergen and Sewaren projects, the New York
entities had been assessed approximately $115 million in costs.
17
The petitions in Consolidated Edison Co. of New York, Inc. v.
FERC (“ConEd v. FERC”) challenge FERC’s approval of
those already-paid costs. The City of New York and the New
York State Public Service Commission have intervened on
behalf of the New York entities, arguing against the cost
allocations; a group of transmission owners, including PSE&G,
have intervened on behalf of FERC, arguing in favor of the cost
allocations.
The New Jersey Board petitioned for review of FERC’s
orders permitting Linden and Hudson to convert their firm
withdrawal rights to non-firm ones, as well as its orders
denying the Board’s complaint. The petitions in New Jersey
Board of Public Utilities v. FERC (“New Jersey Board v.
FERC”) concern PJM’s reassignment of Bergen’s DFAX costs
to PSE&G—and, by extension, New Jersey ratepayers—
beginning in 2017. ConEd, Linden, Hudson, NYPA and
NYISO have intervened on FERC’s behalf, in favor of the post-
2017 cost allocations; PSE&G has intervened on the Board’s
behalf, arguing against the post-2017 cost allocations.
The New York entities and New Jersey Board both claim
that FERC’s myriad orders ran afoul of the APA and violated
the Federal Power Act’s cost causation and nondiscrimination
principles. With two inconsequential exceptions, we have
jurisdiction over their petitions under 16 U.S.C. § 825l(b). 5
5
The petition in No. 20-1269 sought review of the Second Linden
Complaint Order after the parties’ application for rehearing was
deemed denied by operation of law. See 16 U.S.C. § 825l(a).
Because that petition was untimely filed, we dismiss it for lack of
jurisdiction. See id. § 825l(b). That dismissal has no practical
consequence, however, because after FERC affirmatively rejected
the parties’ application for rehearing of the same order years later,
18
II.
This court must set aside any order of the Commission that
is “arbitrary, capricious, an abuse of discretion, or otherwise
not in accordance with law.” 5 U.S.C. § 706(2)(A). “In matters
of ratemaking, our review is highly deferential, as issues of rate
design are fairly technical and, insofar as they are not technical,
involve policy judgments that lie at the core of the regulatory
mission.” Alcoa Inc. v. FERC, 564 F.3d 1342, 1347 (D.C. Cir.
2009) (cleaned up). FERC’s ratemaking orders will not stand,
however, if they are “either unreasonable or inadequately
explained.” Artificial Island, 989 F.3d at 17 (cleaned up).
FERC’s reasoning must be grounded in “substantial evidence,”
16 U.S.C. § 825l(b), which is “such relevant evidence as a
reasonable mind might accept as adequate to support a
conclusion,” Myersville Citizens for a Rural Cmty., Inc. v.
FERC, 783 F.3d 1301, 1309 (D.C. Cir. 2015) (cleaned up).
III.
The New York entities argue that FERC failed to
reasonably explain why the DFAX method should be used to
they again petitioned for review—this time in a timely fashion, in
No. 20-1351.
Similarly, we dismiss the petition in No. 20-1077, which seeks
review of FERC’s orders preliminarily accepting PJM’s 2017 cost
reallocation, for lack of jurisdiction. “The decision to accept a rate
filing” without approving its lawfulness “is undeniably
interlocutory” and therefore unreviewable. Papago Tribal Util.
Auth. v. FERC, 628 F.2d 235, 240 (D.C. Cir. 1980). Again, however,
this dismissal is inconsequential, since FERC’s final approval of
PJM’s 2017 filing is properly before us in No. 20-1382, which seeks
review of the Cost Reallocation Order.
19
allocate the costs of the Bergen and Sewaren projects, but
should not be used to allocate the costs of a similar project in
Artificial Island. We agree.
A.
In 2016, FERC determined that DFAX was an appropriate
method of assigning costs for all the projects selected for PJM’s
regional plan, whether they were flow-based or non-flow-
based. Within that latter category, FERC specifically found
that DFAX was appropriate even if “a short-circuit or stability
violation is the [project’s] primary driver.” ConEd Complaint
Rehearing Order, 155 FERC ¶ 61,088 at P 41. It therefore
reasoned that PJM had properly used the DFAX method to
assign the costs of the three non-flow-based projects before
it—Bergen and Sewaren (short-circuit projects) and Artificial
Island (a stability project). “The solution-based DFAX
method,” FERC explained, does not turn on “the immediate
[problem] that drove the need for the project.” Id. at P 40.
While “the initial nature of the problem may not necessarily be
related or entirely related to flows,” DFAX still identifies the
utilities that will use the new facilities and appropriately
assigns them costs. Id. FERC therefore refused to create new
cost allocation methods for different kinds of non-flow-based
projects (stability projects, short-circuit projects, etc.). “[S]uch
a case-by-case … approach,” it found, “would create the same
uncertainty that ex ante cost allocation is intended to avoid.”
ConEd Complaint Order, 151 FERC ¶ 61,227 at P 55.
By the time FERC issued its 2020 orders regarding the cost
allocations for Bergen and Sewaren, however, it had reversed
its position regarding the Artificial Island project. On
rehearing in 2018, FERC distinguished between flow-based
projects on the one hand and stability related projects like
Artificial Island on the other. Flow-based problems, such as
20
“thermal overload and voltage related reliability issues,” are
caused by excessive electricity flows across a facility, and are
therefore resolved by expanding the grid’s transmission
capacity. Artificial Island Rehearing Order, 164 FERC
¶ 61,035 at P 39. As a result, “the change in power flows [is]
consistent with the intended solution.” Id. (quoting a PJM
filing). DFAX reasonably picks out the beneficiaries of such a
project because the utilities that use the upgraded facility are
the same ones whose ability to transmit electricity was
formerly constrained. See id.
By contrast, FERC explained that a stability related
problem like the one in Artificial Island is not caused by
excessive demand (i.e., it is “non-flow-based”). While such a
problem can be solved by expanding the grid’s overall
transmission capacity, the utilities that use that new capacity
are not necessarily the beneficiaries of a stability related
project. Thus, although the “DFAX method will reveal parties’
use of the new transmission facility, such use is neither
connected with the need for the project, nor provides benefits
to the parties being assigned cost responsibility.” Artificial
Island Second Rehearing Order, 166 FERC ¶ 61,161 at P 38.
FERC therefore concluded that while DFAX is just and
reasonable for allocating the costs of flow-based projects, it
was not similarly appropriate for allocating the costs of non-
flow-based projects addressing stability issues. Artificial
Island Rehearing Order, 164 FERC ¶ 61,035 at PP 38–41.
B.
The New York entities argue that FERC should have
extended this same logic to the Bergen and Sewaran projects.
FERC, they say, failed to explain why it continued to apply the
DFAX method to Bergen and Sewaren, even after directing
PJM to use a different method for Artificial Island. All three
21
projects addressed non-flow-based issues, so their costs should
all have been allocated similarly. 6 “A fundamental norm of
administrative procedure requires an agency to treat like cases
alike. If the agency makes an exception in one case, then it
must either make an exception in a similar case or point to a
relevant distinction between the two cases.” Westar Energy,
Inc. v. FERC, 473 F.3d 1239, 1241 (D.C. Cir. 2007).
6
The New York entities raised this objection directly in their
application for rehearing of the Second Linden Complaint Order and
the Cost Reallocation Order. See Second Linden Complaint
Rehearing Order, 172 FERC ¶ 61,176 at P 22. However, they did
not similarly cite Artificial Island when applying for rehearing of the
First Linden Complaint Order, instead arguing generally that “a
flow-based method is the wrong way to measure benefits for non-
flow based reliability concerns, such as the short-circuit concerns
underlying [Bergen and Sewaren].” First Linden Complaint
Rehearing Order, 170 FERC ¶ 61,122 at P 41.
Ordinarily, we lack jurisdiction to consider an argument not
raised before FERC on rehearing “with specificity.” Ameren Servs.
Co. v. FERC, 893 F.3d 786, 793 (D.C. Cir. 2018) (cleaned up). In
this case, however, FERC did not change its position in Artificial
Island until after the parties had applied for rehearing of the First
Linden Complaint Order, so they have a “reasonable ground” for
failing to specifically raise the issue. 16 U.S.C. § 825l(b). At the
time FERC issued the First Linden Complaint Rehearing Order, it
had been considering Artificial Island’s cost allocations alongside
Bergen’s and Sewaren’s for six years and had only recently changed
its approach in Artificial Island. In that context, the parties’ general
argument that DFAX is unsuited to non-flow-based projects was
sufficient to alert FERC to the need to distinguish its recent decision
in Artificial Island from the position it initially took with respect to
Bergen and Sewaren in 2016. We therefore have jurisdiction to
consider whether, in the First Linden Complaint Rehearing Order,
FERC acted arbitrarily in treating Bergen and Sewaren differently
from Artificial Island.
22
In attempting to distinguish the Bergen and Sewaren
projects from Artificial Island, FERC claimed it had “not
ma[de] a generalized finding regarding all non-flow-based
constraints,” Second Linden Complaint Rehearing Order, 172
FERC ¶ 61,176 at P 23, but instead had made a narrow
exception for stability related projects, which are “analytically
unique,” id. at P 24 (citing Artificial Island Rehearing Order,
164 FERC ¶ 61,035 at P 40). FERC explained that in order to
resolve the short-circuit issues on the Bergen-Linden corridor,
PSE&G had expanded the corridor into a double-circuit line
capable of greater electricity flows. This “reconfigur[ation]
[of] the transmission system” was “similar to the planning
process for resolving thermal overloads,” which are flow-
based. Id.; cf. First Linden Complaint Rehearing Order, 170
FERC ¶ 61,122 at P 41. According to FERC, in other words,
the solution PJM adopted for Bergen made it like a flow-based
project, and DFAX was therefore an appropriate way to assign
its costs. Second Linden Complaint Rehearing Order, 172
FERC ¶ 61,176 at P 24.
But in Artificial Island, FERC did not find that stability
projects are “analytically unique” in the abstract. Rather, it
found that “stability is analytically unique compared to voltage
or thermal overload problems,” which are both flow-based.
Artificial Island Rehearing Order, 164 FERC ¶ 61,035 at P 38
(emphasis added). In other words, FERC contrasted the mine-
run of flow-based projects on the PJM grid on the one hand
with the specific, non-flow-based stability project at Artificial
Island on the other. But in the Artificial Island proceeding
FERC said nothing about whether—like stability projects—
short-circuit projects should also be treated differently from
flow-based projects. In fact, the testimony on which it relied
recognized both “the short circuit issue and the stability issue”
as awkward fits for the DFAX method, because neither are
23
flow-based. J.A. 1091–92. 7 Therefore, FERC could not
rationally explain its decision to treat Bergen and Sewaren
differently from Artificial Island by simply pointing to its
earlier finding that “stability is analytically unique compared
to voltage or thermal overload problems.” Instead, FERC
needed to explain why stability is “analytically unique”
compared to short-circuit issues.
FERC failed to do so. It conceded that, like the stability
issue at Artificial Island, “short-circuit problems are not
directly caused by flow overloads on a facility.” First Linden
Complaint Rehearing Order, 170 FERC ¶ 61,122 at P 41.
Nonetheless, FERC reasoned that DFAX should still be used
to assign Bergen’s costs because Bergen was similar to a
thermal overload project. FERC did not adequately explain
why that similarity mattered. Short-circuit issues, not thermal
overloads, were the primary impetus for Bergen. While Bergen
expanded the grid’s overall capacity, the same is true of
Artificial Island. In both cases, the increased capacity
incidentally benefited the utilities whose electricity flows
across the new facilities. Critically, however, other parties also
benefited in both cases. After Bergen’s completion, PSE&G
benefited from facilities that are resistant to short circuits,
while other grid users also benefited from protection against
the second-order effects of short circuits. Likewise, in
Artificial Island, FERC recognized that the utilities that relied
on the generators at issue benefited from their improved
stability. See Artificial Island Second Rehearing Order, 166
FERC ¶ 61,161 at P 39.
Pointing to those other beneficiaries, FERC concluded in
Artificial Island that the utilities whose electricity flows across
7
In this Part and Part IV, citations to the joint appendix refer to the
one in ConEd v. FERC.
24
facilities built to address stability issues should not be assigned
costs via DFAX; instead, it reallocated Artificial Island’s
DFAX costs to the utilities that depended on the newly
stabilized nuclear generators. See id. at PP 13, 43. Here, by
contrast, FERC used DFAX to assign the costs of Bergen and
Sewaren to the utilities whose electricity flows across
PSE&G’s facilities—even though, like Artificial Island, those
projects also conferred non-flow-based benefits to other
entities. Given the similarities between the projects, basic rule
of law principles required FERC to justify its different
treatment of the projects. It needed to explain why, in contrast
to Artificial Island, the costs of Bergen and Sewaren should be
assigned via DFAX to the utilities whose electricity flows
across the upgraded facilities, rather than to the projects’ other
beneficiaries.
We do not hold that the use of the DFAX method for short-
circuit projects violates the cost causation principle per se. On
remand, FERC may be able to provide a more satisfactory
explanation of the distinction between stability related projects
and those that address short-circuit issues and to articulate why
DFAX cost allocations are appropriate for the latter but not the
former. But the Commission “must provide an adequate
explanation to justify treating similarly situated parties
differently.” Comcast Corp. v. FCC, 526 F.3d 763, 769 (D.C.
Cir. 2008). It failed to do so here.
IV.
In addition to challenging the application of the DFAX
method generally, the New York entities attack three specific
conventions used in it: the de minimis threshold, netting, and
the peak-load assumption.
25
A.
We begin with the de minimis threshold.
1.
The DFAX method divides the costs of a transmission
facility among zones in proportion to each zone’s use of the
facility. See First Linden Complaint Rehearing Order, 170
FERC ¶ 61,122 at P 7. For the facility in question, PJM first
uses certain models, which estimate the flow of electricity at
peak demand, to determine what it calls the “distribution
factor” of each zone. The distribution factor for a zone
represents the zone’s use of the facility divided by the zone’s
total load or use of all facilities on the PJM grid. PJM Tariff,
Sched. 12(b)(iii)(A). For example, if a zone uses 1,000
megawatts of electricity from a facility and its total load is
10,000 megawatts, then its distribution factor for the facility is
0.1 or 10%.
PJM then performs various arithmetic calculations to
assign costs based on each zone’s use of the facility at issue.
First, it multiplies the distribution factor of a zone by its total
load, which yields the zone’s use of the facility. Id. Sched.
12(b)(iii)(B)(1). In the example above, the zone’s use of the
facility would be 1,000 megawatts. Second, PJM divides that
number by all zones’ use of the facility. Id. Sched.
12(b)(iii)(B)(2). For example, if a zone uses 1,000 of the 5,000
megawatts from a facility, PJM calculates a quotient of 0.2.
Third, PJM multiplies that quotient by the total cost of the
facility to produce the relevant cost allocation. Id. Sched.
12(b)(iii)(B)(5). If the facility in this example costs $1 million,
PJM would allocate $200,000 in costs to the zone.
The de minimis threshold adds an important qualification
to this process. In FERC’s view, zones that receive very small
26
benefits from a facility should be assigned no costs for it. First
Linden Complaint Rehearing Order, 170 FERC ¶ 61,122 at
P 44. To that end, zones with a distribution factor below 1%
are deemed to have no flows over the facility and thus are
assigned no costs. PJM Tariff, Sched. 12(b)(iii)(A)(6).
Because distribution factors measure a zone’s use of a facility
relative to its total load, the de minimis exception depends on
the size of the zone, not on the zone’s share of the facility’s
total flow. For example, suppose a zone uses 9 megawatts of a
facility’s total flow of 30 megawatts. Although the zone uses
nearly a third of total flow, its use will be deemed de minimis
if, say, the zone itself has a total load of 1,000 megawatts
(which corresponds to a distribution factor of 0.9%). In that
event, the sheer size of the zone will cause it to be assigned no
costs.
2.
As implemented through distribution factors, the de
minimis threshold thus operates as a too-big-to-pay rule. We
agree with the New York entities that this violates the cost
causation principle and causes undue discrimination. The cost
causation principle requires “comparing the costs assessed
against a party to the burdens imposed or benefits drawn by
that party.” Midwest ISO Transmission Owners v. FERC, 373
F.3d 1361, 1368 (D.C. Cir. 2004). And undue discrimination
occurs when similarly situated entities are charged different
rates for no good reason. Mo. River Energy Servs., 918 F.3d at
958. As explained above, the de minimis threshold exempts
zones from bearing any costs based on their load size—a
quality unrelated to the burdens they impose on or the benefits
they receive from any individual facility. And in so doing, it
unduly discriminates against small zones, which must absorb
higher cost allocations after large zones are exempted.
27
Peak load sizes vary greatly across the relevant zones,
which makes the de minimis exception border on absurd. For
instance, the peak load of PSE&G is about 11,000 megawatts,
whereas PJM assigned Linden and Hudson peak loads of only
330 and 320 megawatts respectively. So if PSE&G used 100
megawatts of flow across a transmission facility (yielding a
distribution factor slightly under 1%), and if Hudson had 4
megawatts of flow across the same facility (yielding a
distribution factor slightly over 1%), then PSE&G but not
Hudson would be exempt from paying any of the facility’s
costs, even though PSE&G derived 25 times more of the
benefits. And because the large PSE&G would not have to pay
any costs of the facility, the small Hudson would have to bear
a substantially greater share of those costs.
PJM’s allocations for the Bergen project illustrate this
dynamic. For one subproject, the DFAX method determined
that PSE&G received 65.5% of the benefits, while ConEd and
Hudson together received only about 16%. Yet after applying
the de minimis threshold, PSE&G was removed from the cost
allocation, and so ConEd and Hudson were assigned 99.98%
of the upgrade costs. J.A. 1018–20. And after ConEd
withdrew from its wheeling agreement, PSE&G received
72.7% of the subproject’s benefits and Hudson only 6%. Yet
the de minimis threshold excluded PSE&G from any cost
allocation, and Hudson then became responsible for 99.98% of
the upgrade costs. Id. at 1404–07. Other examples abound.
See, e.g., id. at 1022–23 (PSE&G received 46% of a
subproject’s benefits and ConEd only 27%, yet ConEd was
allocated 100% of its costs); id. at 1295 (listing nine
subprojects for which Hudson received between 6% and 16%
of the benefits, but was allocated over 99% of the costs); id. at
1408–09 (subproject for which Linden and Hudson received
33% of the benefits, but were allocated 100% of the costs).
This scheme plainly violates the rule that FERC “may not
28
single out a party for the full cost of a project, or even most of
it, when the benefits of the project are diffuse.” Old Dominion,
898 F.3d at 1255 (cleaned up). Because the de minimis
threshold regularly produces “wholesale departure[s] from the
cost-causation principle,” it cannot be considered just and
reasonable. See id. at 1261.
3.
FERC asserted three justifications for the de minimis
threshold, but none is persuasive.
First, it observed that the threshold identifies “entities that
have relatively little use of the transmission facility relative to
their load.” First Linden Complaint Rehearing Order, 170
FERC ¶ 61,122 at P 44. Similarly, the intervenors supporting
FERC characterize the threshold as a measure of relative
reliance—i.e., the degree to which a zone depends on one
facility instead of others—as opposed to relative use. These
are accurate statements of how the threshold works, but they
are not justifications for a threshold keyed to the relative size
of the zone, rather than to the relative use of the facility.
Second, FERC denied that the de minimis threshold
depends on a zone’s size. Id. at P 45. The Commission is
correct that the threshold is keyed to a distribution factor,
which measures the shift in power over a transmission facility
when a zone’s peak load is increased by one megawatt,
regardless of its size. PJM Tariff, Sched. 12(b)(iii)(A). But
this measurement is done precisely because the resulting
distribution factor will measure “use by the load of each Zone.”
Id. (emphasis added). FERC’s second rationale is thus wrong
as well as inconsistent with its first, which claimed support
from the fact that the de minimis threshold identifies zones with
small use relative to their load.
29
Third, FERC noted that the DFAX analysis is performed
annually, so “the zones that qualify for the de minimis
exemption may change” over time. First Linden Complaint
Rehearing Order, 170 FERC ¶ 61,122 at P 45. We are at a loss
to understand how that fact, reflecting the truism that things
change, bears on whether the exception here is reasonably
related to project costs or benefits.
B.
We now turn to netting. For zones with many delivery
points, PJM “nets” the flows to each delivery point to calculate
total flow. PJM Tariff, Sched. 12(b)(iii)(A)(4). Electricity can
flow in both positive and negative directions. PJM assigns a
negative value to flows in the negative direction, which
decreases a zone’s total flow. For instance, a zone with one
delivery point that receives +100 megawatts and another that
receives +50 megawatts will be deemed to have net flows of
+150 megawatts. But a zone with one delivery point that
receives +100 megawatts and another that receives −50
megawatts will be deemed to have net flows of only +50
megawatts. The New York entities challenge this offsetting of
positive and negative flows.
1.
The New York entities contend that netting violates the
cost causation principle and unduly discriminates against them.
Transmission facilities benefit zones by bringing electricity to
their delivery points, and this benefit is the same regardless of
whether the electricity flows in the positive or negative
direction. But netting causes markedly different cost
allocations. If a zone with one delivery point receives +150
megawatts, while another with two delivery points receives
flows of +100 and −50 megawatts at each point respectively,
the former zone will pay three times as much as the latter for
30
the same benefit. The New York entities contend that this
discrepancy systematically favors large zones like PSE&G,
which have many delivery points and so are more likely to have
offsetting positive and negative flows. In contrast, each
merchant transmission facility has only one delivery point and
so cannot benefit from netting.
FERC approved netting because it produces a different
benefit by creating extra capacity for the transmission line.
Because “power flows in opposite directions offset each other,”
a zone’s “negative flows decrease the amount of power flowing
over the line and make additional capacity available.” First
Linden Complaint Rehearing Order, 170 FERC ¶ 61,122 at
P 49. For instance, a transmission facility with 75 megawatts
of capacity cannot accommodate +100 megawatts of flows in
the absence of counterflows. But with the addition of −50
megawatts of counterflows, the net flow is only +50
megawatts, and the facility can accommodate all the flows.
FERC concluded that zones with flows in only one direction
should bear more costs for using up more capacity.
This conclusion is reasonable. Because counterflows
increase capacity, FERC could reasonably treat them as
benefits that the zones confer on the facility, rather than
benefits that they derive from it. So understood, counterflows
can reasonably be considered a basis for discounting rather
than increasing a zone’s cost allocation. On this point, we do
not suggest that FERC’s approach is the only reasonable one.
But because it is reasonable, we must uphold it on deferential
review. See Old Dominion, 898 F.3d at 1260.
The New York entities raise two further objections. They
contend that FERC’s defense of netting is inconsistent with
PJM’s rationale for replacing its previous cost allocation
method with the present DFAX method. And they claim it is
31
unduly discriminatory to net within a zone but not across
zones. The entities did not raise either objection in their
applications for rehearing, so we do not have jurisdiction to
consider them. 16 U.S.C. § 825l(b); see Ameren Servs. Co. v.
FERC, 893 F.3d 786, 793 (D.C. Cir. 2018).
2.
After FERC issued the orders under review, another
merchant transmission facility owner filed a section 206
complaint challenging the netting and de minimis provisions of
PJM’s Tariff. Neptune Reg’l Transmission Sys., LLC, 175
FERC ¶ 61,247 at PP 1, 4, 8 (2021). Following its preliminary
review in Neptune, FERC undertook to “look anew” at whether
both provisions “have become unjust and unreasonable,” and it
ordered further proceedings to do so. Id. at PP 45–46.
The New York entities request a remand for FERC to
reconsider netting here, given its Neptune order. But we
evaluate agency action “at the time of decision,” PBGC v. LTV
Corp., 496 U.S. 633, 654 (1990), and an agency decision “is
not arbitrary or capricious merely because it is not followed in
a later adjudication,” MacLeod v. ICC, 54 F.3d 888, 892 (D.C.
Cir. 1995). Despite this, the entities note, we have sometimes
remanded if the agency has changed the rule underlying a
decision pending review. See Williston Basin Interstate
Pipeline Co. v. FERC, 165 F.3d 54, 62–63 (D.C. Cir. 1999).
But FERC did not reject netting in Neptune; it merely ordered
further proceedings to examine the practice in greater detail. A
remand here is thus unwarranted.
We hold only that FERC reasonably explained its decision
to approve netting in these proceedings. In doing so, we do not
prejudge Neptune, and we do not foreclose the Commission
from reconsidering its position on netting given whatever
evidence and arguments may be developed in that case.
32
C.
Finally, we address the peak-load assumption. When
modeling the flow of electricity, PJM assumes that each zone
is at its peak demand. For merchant transmission facilities, this
means PJM assumes that they are exercising their full firm
withdrawal rights. PJM Tariff, Sched. 12(b)(iii)(A)(3). The
merchant transmission facilities object that this assumption
overestimates their use of the transmission facilities, because
they generally do not reroute electricity into New York City
when demand in New Jersey is at its peak. FERC
acknowledged that merchant transmission facilities may be less
likely than other zones to exercise full delivery rights at times
of peak demand. Nonetheless, it found the assumption
reasonable because PJM must be able to meet peak load to
guarantee system reliability. First Linden Complaint
Rehearing Order, 170 FERC ¶ 61,122 at P 15. The entities
complain this explanation is inconsistent with FERC’s defense
of netting, which the Commission justified as “realistically
reflect[ing] how energy flows on an integrated transmission
system.” Id. at P 14. If FERC evaluates netting based on how
electricity realistically flows, the challengers contend, it should
do the same for the peak-load assumption.
We see no inconsistency. Maintaining grid reliability is
one of a system operator’s most important goals, Blumenthal v.
FERC, 552 F.3d 875, 879 (D.C. Cir. 2009), so PJM could
reasonably plan for a worst-case scenario in which all zones
exercise their full delivery rights. But even under that scenario,
positive and negative flows still would offset each other and
thus create additional capacity. As explained above, FERC
may reasonably take that fact into account in deciding whether
to add or subtract opposite-direction flows.
33
V.
Finally, the New York entities challenge FERC’s
interpretation of the PJM Tariff. They contend that the Tariff
requires a departure from the DFAX method if its application
would violate the cost causation principle. We disagree.
The interpretive dispute centers on the interplay between
Schedule 12(b)(iii) of the Tariff, which outlines how to carry
out the DFAX analysis, and paragraph (G) of that provision,
which confers some discretion to depart from the prescribed
methodology. Under that paragraph, if PJM “determines in its
reasonable engineering judgment that … the DFAX analysis
cannot be performed or that the results of such DFAX analysis
are objectively unreasonable,” it “may use an appropriate
substitute proxy for the Required Transmission Enhancement
in conducting the DFAX analysis.” The New York entities
maintain that “objectively unreasonable” results include ones
that do not conform to the cost causation principle. And in their
view, an “appropriate substitute proxy” includes a different
cost allocation methodology.
FERC read paragraph (G) differently. It objects that the
New York entities invite an ex post allocation inquiry that is
both standardless and contrary to Order No. 1,000’s
requirement that costs be assigned ex ante. First Linden
Complaint Rehearing Order, 170 FERC ¶ 61,122 at P 55.
According to FERC, results of the DFAX analysis are
“objectively unreasonable” only if the flows it models “are not
consistent with the normal expected flow results that an
engineer would expect to see.” Id. And because PJM engineers
“had no difficulty determining flows across” the Bergen and
Sewaren projects, the DFAX analysis results were not
objectively unreasonable. Id. Moreover, paragraph (G) gives
PJM discretion only to use “‘an appropriate substitute proxy
34
for the Required Transmission Enhancement in conducting the
DFAX analysis,’” not general discretion to modify the
method’s “cost responsibility assignments.” Id. at P 56
(quoting PJM Tariff, Sched. 12(b)(iii)(G)).
We review FERC’s tariff interpretations with a “Chevron-
like analysis.” La. Pub. Serv. Comm’n v. FERC, 10 F.4th 839,
845–46 (D.C. Cir. 2021) (cleaned up). Under that framework,
we enforce unambiguous tariff language but defer to FERC’s
reasonable interpretation of ambiguous text. Id. at 846.
FERC’s interpretation is permissible. Any determination
of unreasonableness by PJM must be “objective[]” and the
product of PJM’s “engineering judgment,” which suggests a
purely technical determination. Judging whether the method
accurately models the flow of electricity fits that description.
Ensuring compliance with the cost causation principle does
not. Aligning project costs and benefits necessarily includes
questions of fairness and the need to balance “competing
goals.” S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 88 (D.C.
Cir. 2014) (per curiam). And courts have long recognized that
ratemaking is “much less a science than an art,” Ala. Elec.
Coop., Inc. v. FERC, 684 F.2d 20, 27 (D.C. Cir. 1982),
requiring “both technical understanding and policy judgment,”
FERC v. Elec. Power Supply Ass’n, 577 U.S. 260, 295 (2016).
Moreover, even when PJM finds objectively unreasonable
results, it does not have discretion to abandon the DFAX
method. Paragraph (G) allows PJM to use a “substitute proxy”
only “for the Required Transmission Enhancement,” i.e., the
transmission facility, and only “in conducting the DFAX
analysis.” It does not permit a proxy method. In other words,
PJM can look past modeled flows that seem objectively
unreasonable, replace them with flows from a comparable
35
facility that the DFAX analysis can more accurately model, and
then rerun the analysis. Nothing more.
Two other textual clues reinforce this view. The
immediately preceding paragraph of the Tariff speaks of using
a “proxy” in precisely this way. When the facility to be
modeled is a direct-current facility, it “shall be replaced in the
model with a comparable proxy [alternating-current] facility.”
PJM Tariff, Sched. 12(b)(iii)(F)(1). Additionally, whenever
PJM uses a proxy under paragraph (G), it must “state in a
written report … a recommendation as to what changes, if any,
should be considered in conducting the DFAX analysis.” Id.
Sched. 12(b)(iii)(G) (emphasis added). This presupposes that
even if PJM uses a proxy facility, it will not abandon the DFAX
method altogether.
Finally, FERC’s interpretation fits better with the principle
of ex ante cost allocation established by Order No. 1,000.
Under FERC’s reading, PJM must apply all the existing cost
allocation rules unless doing so is infeasible because the DFAX
analysis does not accurately model flows. When that is the
case, PJM’s discretion is limited to identifying a proxy facility
to which the existing rules will otherwise apply. Under the
New York entities’ reading, PJM must decide in each case
whether to apply the existing rules or entirely new ones, based
on its own view of the fairness of the results produced by the
existing rules. Such an approach is ex ante in name only.
VI.
For its part, the New Jersey Board seeks review of FERC’s
order affirming the reallocation of the New York entities’ costs
for the Bergen project to PSE&G after they relinquished their
rights to withdraw electricity from the PJM grid, as well as its
orders permitting Linden and Hudson to convert their firm
withdrawal rights to non-firm ones. The Board raises three
36
main arguments. First, the Board claims that FERC erred in
determining that ConEd’s cost responsibility for the project
ended when its transmission service agreements ceased. This
was so since the project was built to benefit ConEd and ConEd
previously agreed to accept its share of costs. Second, it is
argued that Linden unreasonably evaded cost allocations for
the project by the device of pairing non-firm transmission
withdrawal rights and firm point-to-point transmission service,
which ensures Linden retains the same benefits from the
project. Third, the Board also contends that FERC did not
properly consider whether the cumulative effect of relieving
the New York entities of cost responsibility resulted in an
unjust and unreasonable rate.
A.
We start with the New Jersey Board’s first argument that
ConEd was obliged to continue to pay project costs even after
it ceased receiving service upon the termination of the ConEd-
PSE&G power exchange transmission service—“wheeling”—
agreement.
The 2009 settlement between PSE&G and ConEd, which
clarified the parties’ rights and obligations under the wheeling
agreement, was signed by the New Jersey Board, ConEd, PJM,
NYISO, and PSE&G. Under that agreement, ConEd “shall pay
Transmission Enhancement Charges during the term of
its … service.” J.A. 614. 8 But the agreement makes clear that
“ConEd shall have no liability for Transmission Enhancement
Charges … after the termination of[] said term of service.” Id.
8
In this Part, citations to the joint appendix refer to the one in New
Jersey Board v. FERC.
37
FERC approved the settlement. 9 See ConEd-PSE&G
Settlement Order, 132 FERC ¶ 61,221 at P 23. Here, ConEd’s
service agreements expired on April 30, 2017, and it did not
renew them.
Under the PJM Tariff, ConEd’s cost responsibility for PJM
regional plan projects “shall be in accordance with the terms
and conditions of the settlement” and “shall be adjusted at
the … termination of service under the ConEd Service
Agreements.” PJM Tariff, Sched. 12(b)(xi)(A)–(B). FERC
relied on the settlement agreement and its incorporation into
the PJM Tariff to support its cost allocation decision. See
Board Complaint Order, 163 FERC ¶ 61,139 at P 56 & n.94.
Similarly, FERC recognized that the Joint Operating
Agreement (“JOA”) between PJM and NYISO, which
established protocols to improve the reliability and market
operations of their systems, precluded the continued allocation
of the Bergen project’s costs to ConEd. Id. at PP 2, 54–55.
FERC noted that, under JOA section 35.10.6, “neither the
NYISO Region nor the PJM Region shall be responsible for
compensating another region” for project costs unless both
NYISO and PJM jointly decide to undertake an interregional
project together. Id. at P 54; Board Complaint Rehearing
Order, 170 FERC ¶ 61,180 at PP 12, 14. FERC correctly
explained that the Bergen project was planned solely by PJM.
Board Complaint Order, 163 FERC ¶ 61,139 at P 54; Board
Complaint Rehearing Order, 170 FERC ¶ 61,180 at P 12. That
cost allocation provision applies even where, as here, PJM and
NYISO share mutual benefits between their systems that derive
9
We note that the New Jersey Board participated in the settlement
negotiations and signed the settlement agreement. If the Board took
issue with these provisions, it should not have agreed to the
settlement.
38
simply from their interconnection. Board Complaint Order,
163 FERC ¶ 61,139 at P 55. FERC recognized that “the JOA
specifically states that ‘PJM and NYISO shall not charge one
another for such [mutual benefits].’” Id.
Accordingly, under these three agreements, FERC
correctly determined that ConEd did not have to pay project
costs after the termination of the service agreements.
The New Jersey Board contends that all of this misses the
point. The relevant question, it says, is not whether a cost
allocation complies with previously approved agreements or
orders, but whether the resulting cost allocation,
notwithstanding those agreements, is unjust and unreasonable.
And, it points out that previously approved cost allocation
methods can be unjust and unreasonable as applied to a
particular rate decision.
As a general principle, under FERC’s Order No. 1,000,
which implements the cost causation principle, costs must be
allocated roughly in accordance with benefits. Order No.
1,000, 136 FERC ¶ 61,051 at P 612. But that order also
provides—in Principle 4—that “[t]he allocation method for the
cost of a transmission facility selected in a regional
transmission plan must allocate costs solely within that
transmission planning region unless another entity outside the
region or another transmission planning region voluntarily
agrees to assume a portion of those costs.” Id. at P 657. Here,
after ConEd’s service agreements expired, it no longer agreed
to pay costs. And, as noted, the Bergen project was planned
solely by PJM.
The New Jersey Board responds that there is tension
between Principle 4 and the general cost causation principle
because it may allow some project beneficiaries—here,
39
ConEd—to avoid all cost responsibility. That is true. But it
appears to us that Principle 4 is a permissible limitation on the
cost causation principle. Indeed, we have concluded as much,
as FERC points out. Board Complaint Order, 163 FERC
¶ 61,139 at P 54 n.83.
In South Carolina Public Service Authority v. FERC,
Petitioners argued that Principle 4 was inconsistent with the
cost causation principle because it did not fully allocate costs
to out-of-region entities who still received some benefits. 762
F.3d at 88. We held that, even if Principle 4 “may lead to some
beneficiaries escaping cost responsibility,” there are other
geographic policy considerations in play and FERC may
permissibly approve a rate that does not perfectly track cost
causation. Id.; see also Carnegie Nat. Gas Co. v. FERC, 968
F.2d 1291, 1293–94 (D.C. Cir. 1992) (noting that there is “no
requirement in the Act itself that rates precisely match cost
causation and responsibility” and that instead “the Commission
may rationally emphasize other, competing policies and
approve measures that do not best match cost responsibility and
causation”). We noted that FERC developed Principle 4 in
light of concerns about the monitoring costs, efficiency, and
feasibility of involuntary interregional cost allocation. S.C.
Pub. Serv. Auth., 762 F.3d at 88–89. Accordingly, we
concluded that Principle 4 is an important qualification on the
cost causation principle. It reflects FERC’s reasonable
considered judgment about how best to balance its competing
policy goals on a ratemaking matter, which we review with
deference. Id.; see also Artificial Island, 989 F.3d at 17.
Therefore, we think that FERC reasonably relied on Order
No. 1,000 and its Principle 4 to determine that it was just and
reasonable for ConEd to be released from costs for the Bergen
project going forward.
40
B.
Next, the New Jersey Board contends that “FERC’s
decision to allow Linden to avoid cost allocations for the
Corridor Project” was “arbitrary” because “the Commission
did not grapple with the interaction between firm Point-to-
Point service and non-firm Withdrawal Rights.” The Board
notes that, at the same time Linden renounced its firm
withdrawal rights, it separately bargained for and received firm
“point-to-point” transmission service from utilities on the PJM
grid. The Board therefore argues—and it is a powerful
argument—that, as a practical matter, Linden’s relinquishment
of its firm withdrawal rights and its election of firm point-to-
point service allowed Linden to receive the same benefits from
the Bergen project without any of the costs. 10 FERC insists
that we cannot consider this argument because it was not
adequately presented in its requests for rehearing.
Under 16 U.S.C. § 825l(b), “[n]o objection to [an] order of
the Commission shall be considered by the court unless such
objection shall have been urged before the Commission in the
application for rehearing ….” The argument the New Jersey
Board makes before us, unfortunately, appears nowhere in its
requests for rehearing before FERC. Instead, the Board’s
10
That is because PJM, despite being able to curtail service to a
customer with non-firm withdrawal rights, cannot curtail service to
that same customer if it has firm point-to-point rights. So even
though Linden does not have to pay costs under PJM’s Tariff because
DFAX cost allocations are linked to firm withdrawal rights, it
continues to receive the same service as it did when it held firm
withdrawal rights by subscribing to firm point-to-point service.
Once that power is transmitted to Linden’s facility, PJM cannot
prevent Linden from exporting that power in the exact same way as
it had before converting from firm to non-firm withdrawal rights,
including into NYISO’s market.
41
rehearing requests generally challenge FERC’s handling of the
cost allocation issue. But we have held that a petitioner “must
raise each argument with ‘specificity’; objections may not be
preserved either ‘indirectly,’ or ‘implicitly.’” Ameren Servs.
Co., 893 F.3d at 793 (citations omitted). Accordingly, we lack
jurisdiction to consider the Board’s challenge to Linden’s cost
allocations. 11
C.
Finally, it will be recalled, the New Jersey Board claims
that FERC conducted a “siloed analysis” that did not consider
the “total effect” of its orders on the rates for New Jersey
ratepayers. Taken together, that the project was built in part to
serve New York customers, ConEd did not renew its
transmission service agreements, and Hudson and Linden
converted their withdrawal rights have led to an unjust and
unreasonable cost allocation, the Board says. Essentially, the
Board protests that its ratepayers pay an “exceedingly
disproportionate share” of the costs of the project.
But FERC did perform the kind of back-end analysis that
the New Jersey Board claims was required. FERC recognized
that the Bergen project was planned by PJM, and relied on
PJM’s statement that the project would still be needed in New
Jersey “even if there were no flows on the transmission
facilities interconnecting New York and New Jersey.” Board
Complaint Order, 163 FERC ¶ 61,139 at P 54 n.85. In its order
denying the Board’s complaint, FERC, applying Principle 4,
11
Although the New Jersey Board generally seeks judicial review of
FERC’s orders concerning Hudson’s post-2017 cost allocation, it
does not make this particular argument as to Hudson. Instead, the
Board asks us to consider the Hudson cost allocation only as part of
its “total effect” claim, which we address in Part VI.C.
42
concluded that because the Bergen project “was planned by a
single region, i.e., PJM, and without a voluntary commitment
to share cost responsibility by the other region, i.e., NYISO, it
is just and reasonable for the costs of the project to be allocated
solely within that region, PJM.” Id. at P 54. And, in denying
rehearing on this very argument, FERC noted that “[t]he fact
that New Jersey ratepayers now pay higher rates as a result of
a combined set of permissible circumstances does not by itself
render such rates unjust and unreasonable.” Board Complaint
Rehearing Order, 170 FERC ¶ 61,180 at P 12.
Thus, looking at the matter from the stratosphere, FERC
did consider the “total effect” of its decision and permissibly
concluded—after evaluating who incurred the costs and who
reaped the benefits of the project—that the overall cost
allocation for the New York entities was not unjust or
unreasonable. FERC’s cost allocation determination was
therefore neither “unreasonable” nor “inadequately explained.”
Artificial Island, 989 F.3d at 17.
VII.
In light of the foregoing, we deny the petitions for review
in New Jersey Board v. FERC, and we grant in part and deny
in part the petitions in ConEd v. FERC.
In denying the New York entities’ applications for
rehearing of both the First and Second Linden Complaint
Orders, FERC failed to adequately distinguish its decision in
Artificial Island from its treatment of the Bergen and Sewaren
projects. In addition, FERC upheld the de minimis threshold,
which we have found to be unlawful, in its orders denying
rehearing of the First and Second Linden Complaint Orders and
the ConEd Complaint Order. We therefore vacate FERC’s
denial of Linden’s two complaints and remand for further
43
proceedings on both issues. We likewise vacate its denial of
ConEd’s complaint and remand for further proceedings solely
on the de minimis issue.
With one exception, we leave in place all the section 205
orders approving PJM’s cost allocations. In all but one of those
orders, FERC determined that when PJM files cost allocations
under section 205, its role is limited to determining whether
PJM correctly applied the methodology required by its Tariff
rather than examining the lawfulness of that methodology. The
New York entities do not challenge this procedural ruling,
which forms an independent basis for rejecting their
challenges. 12 We do vacate, however, the Cost Reallocation
Order and remand on both the Artificial Island and de minimis
issues. FERC did not raise a procedural bar to the New York
entities’ challenges there, instead rejecting them on the merits
for reasons we have found defective. See Cost Reallocation
Order, 170 FERC ¶ 61,124 at P 32; Second Linden Complaint
Rehearing Order, 172 FERC ¶ 61,176 at P 18. On remand,
FERC may consider in the first instance whether the challenges
to PJM’s 2017 cost reallocation are procedurally barred.
So ordered.
12
FERC argues that we lack jurisdiction over the petitions in Nos.
15-1183 and 15-1188—which seek review of its 2014 order
approving PJM’s initial cost allocations for Bergen—because that
order was nonfinal. But we indisputably have jurisdiction over at
least one “companion case” raising the same objections as those in
Nos. 15-1183 and 15-1188, and so may reject those petitions on the
merits without reaching the jurisdictional argument FERC presses.
Steel Co. v. Citizens for a Better Env’t, 523 U.S. 83, 98 (1998)
(emphasis omitted) (citing Norton v. Mathews, 427 U.S. 524, 530–
31 (1976)).