Coalition of MISO Transmission v. FERC ( 2022 )

United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued February 7, 2022 Decided August 19, 2022
No. 20-1421
COALITION OF MISO TRANSMISSION CUSTOMERS, ET AL.,
PETITIONERS
v.
FEDERAL ENERGY REGULATORY COMMISSION,
RESPONDENT
AMEREN SERVICES COMPANY, AS AGENT FOR UNION ELECTRIC
COMPANY D/B/A AMEREN MISSOURI, AMEREN ILLINOIS
COMPANY D/B/A AMEREN ILLINOIS, AND AMEREN
TRANSMISSION COMPANY OF ILLINOIS, ET AL.,
INTERVENORS
On Petition for Review of Orders of the
Federal Energy Regulatory Commission
Michael R. Engleman argued the cause for petitioners.
With him on the briefs were Robert A. Weishaar, Jr., Kenneth
R. Stark, Robert C. Fallon, and Christina Switzer.
Matthew J. Glover, Attorney, Federal Energy Regulatory
Commission, argued the cause for respondent. With him on
the briefs were Matthew R. Christiansen, General Counsel,
Robert H. Solomon, Solicitor, and Susanna Y. Chu, Attorney.
2
Christopher D. Supino argued the cause for non-
governmental intervenors in support of respondent. With him
on the joint brief were Ilia Levitine, Wendy N. Reed, and
Matthew J. Binette.
William D. Booth, Roxane E. Maywalt, Paul L.
Zimmering, and Noel J. Darce were on the brief for state
governmental intervenors in support of respondent.
Before: ROGERS, MILLETT, and PILLARD, Circuit Judges.
Opinion for the Court filed by Circuit Judge MILLETT.
Opinion dissenting in part and concurring in part filed by
Circuit Judge ROGERS.
MILLETT, Circuit Judge: LS Power Midcontinent, LLC
(“LS Power”) is a transmission developer seeking to build
projects on the electrical grid overseen by the Midcontinent
Independent System Operator, Inc. (“MISO”). LS Power and
two organizations representing electricity consumers
(collectively, “Petitioners”) challenge MISO’s method of
allocating costs for a category of transmission construction
projects called Baseline Reliability Projects. Under MISO’s
approach, 100% of a project’s costs are allocated to the zone in
which the project is physically located, regardless of whether
other zones also would benefit from the project. Importantly,
this cost-allocation decision means that Baseline Reliability
Projects are not subject to competitive bidding. Instead, MISO
assigns construction of the project to the transmission
developer owning the portion of the grid where the project sits.
Those incumbent transmission developers prefer this approach
because they can make a profit on the construction project. See
MISO Transmission Owners v. FERC, 819 F.3d 329, 333 (7th
Cir. 2016).
3
The Federal Energy Regulatory Commission originally
approved this cost-allocation regime in 2013, and, in 2016, the
United States Court of Appeals for the Seventh Circuit rejected
a challenge to the Commission’s decision. MISO Transmission
Owners, 819 F.3d at 335–336.
Petitioners argue that new evidence acquired over the
intervening years shows that MISO’s cost-allocation method
for Baseline Reliability Projects is unjust and unreasonable and
impermissibly favors incumbent transmission owners over
would-be competitors. The Commission contends that
Petitioners lack standing to challenge its orders and, in any
event, Petitioners’ new evidence fails to undermine the
Commission’s previous conclusions.
As a threshold matter, we hold that LS Power has standing
to challenge the Commission’s decision because it has shown
that it is “ready, willing and able” to compete for Baseline
Reliability Projects if allowed, yet the existing cost-allocation
regime categorically deprives LS Power of the opportunity to
do so. LSP Transmission Holdings II, LLC v. FERC (LSP 2022
II), No. 20-1465, slip op. at 13 (D.C. Cir. Aug. 19, 2022)
(citation omitted).
On the merits, though, we agree with the Commission that
Petitioners’ new evidence—which was limited to a relatively
small number of Baseline Reliability Projects—did not
necessitate a categorical finding that location-based cost
allocation is unjust and unreasonable for all Baseline
Reliability Projects. Petitioners’ remaining objections
regarding MISO’s compliance with other regional cost-sharing
requirements and the Commission’s obligation to respond to
arguments on rehearing are likewise unavailing. As a result,
we deny the petition for review.
4
I
A
The Federal Power Act requires the Commission to ensure
that “[a]ll rates and charges made, demanded, or received by
any public utility for or in connection with the transmission or
sale of electric energy” in interstate commerce are “just and
reasonable[.]” 16 U.S.C. § 824d(a). Under Section 206 of the
Act, the Commission may investigate—either on its own
initiative or in response to a third-party complaint—whether a
rate contained in a transmission operator’s existing tariff
remains just and reasonable. Id. § 824e(a); see Public Serv.
Elec. & Gas Co. v. FERC, 989 F.3d 10, 13 (D.C. Cir. 2021).
The proponent of the rate change bears the burden of showing
that the existing rate is unjust or unreasonable. 16 U.S.C.
§ 824e(b). If the proponent does so, then the existing rate is
unlawful, and the Commission “must establish a just and
reasonable replacement rate.” Public Serv. Elec. & Gas Co.,
989 F.3d at 13 (citing 16 U.S.C. § 824e(a)).
The Commission and the courts “have added flesh to [the]
bare statutory bones” of the just-and-reasonable requirement
by “establishing what has become known in Commission
parlance as the ‘cost-causation’ principle.” K N Energy, Inc. v.
FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992); see Old
Dominion Elec. Coop. v. FERC, 898 F.3d 1254, 1255–1256
(D.C. Cir. 2018). The cost-causation principle requires that
“[t]he cost of transmission facilities * * * be allocated to those
within the transmission planning region that benefit from those
facilities in a manner that is at least roughly commensurate with
estimated benefits.” South Carolina Pub. Serv. Auth. v. FERC,
762 F.3d 41, 53 (D.C. Cir. 2014) (per curiam) (citation
omitted). Said more simply, “the burden on ratepayers of
paying for a project should be matched with its benefit to
5
them.” LSP 2022 II, No. 20-1465, slip op. at 3 (formatting
modified and citation omitted); see Midwest ISO Transmission
Owners v. FERC, 373 F.3d 1361, 1368 (D.C. Cir. 2004)
(Roberts, J.) (explaining that compliance with the cost-
causation principle is determined by “comparing the costs
assessed against a party to the burdens imposed or benefits
drawn by that party”).
B
1
In 2011, in anticipation of a “[s]ignificant expansion of the
transmission grid[,]” South Carolina Pub. Serv. Auth., 762 F.3d
at 51 (citation omitted), the Commission issued Order No.
1000, which required every grid operator to establish a
“regional transmission plan” to identify “what new facilities
would best meet regional needs for electricity[,]” Old
Dominion, 898 F.3d at 1256; see Transmission Planning &
Cost Allocation by Transmission Owning & Operating Public
Utilities, 76 Fed. Reg. 49,842 (Aug. 11, 2011) (“Order No.
1000”).
Under Order No. 1000, a grid operator must specify up
front the cost-allocation methods it will use for facilities
included in its regional plan, and those methods must adhere to
the cost-causation principle. Order No. 1000, 76 Fed. Reg. at
49,929 ¶ 558, 49,932 ¶ 586; see South Carolina Pub. Serv.
Auth., 762 F.3d at 53, 83. Transmission providers are
permitted to select different cost-allocation methods for
different types of transmission facilities, such as those designed
to address reliability concerns, to relieve congestion on the
grid, or to achieve public policy goals. Order No. 1000, 76 Fed.
Reg. at 49,944–49,945 ¶ 685. But Order No. 1000 makes clear
that providers cannot fully close off any one type of
transmission facility from regional cost-allocation. Id. at
6
49,945 ¶ 690. For example, some facilities designed to ensure
grid reliability can have their costs allocated locally as long as
the costs of other reliability projects are allocated regionally.
See MISO Transmission Owners, 819 F.3d at 335.
Order No. 1000 also addressed rights of first refusal, which
incumbent developers that already own parts of the grid often
included in tariffs and agreements to ensure they would have
the “first crack at constructing” transmission projects within
their retail distribution territories, and thereby keep competitors
at bay. MISO Transmission Owners, 819 F.3d at 331; see South
Carolina Pub. Serv. Auth., 762 F.3d at 72. Concerned about
the anti-competitive effect of such provisions, the Commission
directed transmission owners to remove from their tariffs and
agreements any provision creating a federal right of first refusal
over the construction of a new facility included in a regional
transmission plan. Order No. 1000, 76 Fed. Reg. at 49,895–
49,896 ¶ 313. But incumbent transmission owners are
permitted to retain federal rights of first refusal over non-
regional, purely “local transmission facilities[,]” which (1) are
located wholly within the incumbent’s service territory, and (2)
have their costs allocated entirely to the zone in which they are
located. South Carolina Pub. Serv. Auth., 762 F.3d at 73
(formatting modified) (quoting Order No. 1000, 76 Fed. Reg.
at 49,854 ¶ 63, 49,886 ¶ 258).1
2
MISO is the entity that operates, but does not own, the
electrical transmission facilities in fifteen primarily
1
Federal rights of first refusal are exclusive rights to build
contained in tariffs and agreements approved by the Commission.
State and local law may also provide rights of first refusal, which
Order No. 1000 does not affect. See MISO Transmission Owners,
819 F.3d at 336.
7
midwestern states and one Canadian province. See Ameren
Servs. Co. v. FERC, 880 F.3d 571, 572 n.1 (D.C. Cir. 2018).
MISO divides its territorial footprint into 24 “pricing zones[,]”
with each zone roughly corresponding to the transmission
facilities owned by a particular electric utility. Illinois Com.
Comm’n v. FERC, 721 F.3d 764, 773 (7th Cir. 2013); Dynegy
Midwest Generation, Inc. v. FERC, 633 F.3d 1122, 1125 (D.C.
Cir. 2011). In its annual MISO Transmission Expansion Plan,
MISO lists the new transmission facilities that it has approved
and anticipates adding to the grid in the upcoming year.
MISO organizes its transmission facilities into different
categories, each with its own purposes, requirements, and cost-
allocation methods. The Baseline Reliability Projects
category, which is at issue here, encompasses “projects the sole
purpose of which is to solve problems of reliability in electrical
transmission.” MISO Transmission Owners, 819 F.3d at 335.
More specifically, Baseline Reliability Projects are network
upgrades needed to ensure that the transmission system
complies with national, regional, and local reliability standards.
See Midwest Indep. Transmission Sys. Operator, Inc., 114
FERC ¶ 61106, ¶ 26 & n.23 (2006).
Other MISO project categories include “Multi-Value
Projects” and “Market Efficiency Projects.” Multi-Value
Projects are large, expensive, high-voltage projects that “help
MISO members meet state renewable energy requirements, fix
reliability problems, or provide economic benefits in multiple
pricing zones.” Illinois Com. Comm’n, 721 F.3d at 774.
Market Efficiency Projects are upgrades to the transmission
system that satisfy a certain benefit-to-cost ratio, cost at least
$5 million, and surpass a threshold voltage level. LSP 2022 II,
No. 20-1465, slip op. at 5.
8
C
In 2012, MISO submitted a proposal to the Commission to
change its cost-allocation method for Baseline Reliability
Projects. Up to that point, MISO had primarily allocated the
costs of such projects using the “line outage distribution factor”
method (“line-outage analysis”). Line-outage analysis
attempts to quantify the benefits that one transmission zone
reaps from the construction of a new facility in another zone by
calculating electricity flows on the relevant transmission lines
with and without the new facility. MISO would then allocate
costs among pricing zones proportionally to the distribution of
benefits. So, to use a simplified example, if the transmission
zone in which the facility is located (the “local zone”) receives
60% of the benefits as measured by electrical flow, and the
zone next door receives 40% of the benefits, then 60% of the
costs would be allocated to the local zone and 40% would be
allocated to the neighboring zone.
In its 2012 filing, MISO proposed abandoning line-outage
analysis for Baseline Reliability Projects and simply assigning
100% of the costs of all such projects to the local zone.
Experience had shown that “the primary benefits of Baseline
Reliability Projects are realized at the local level[,]” MISO
claimed, reporting that since 2006, 80% of Baseline Reliability
Projects had at least 75% of their costs allocated to the local
zone, and over 50% of such projects had more than 90% of
their costs allocated to the local zone. Midwest Indep.
Transmission Sys. Operator, Inc., 142 FERC ¶ 61215, ¶¶ 486–
487 (2013) (“2013 Order”). Crucially, if accepted, MISO’s
proposal would allow incumbent transmission owners to retain
their federal rights of first refusal over construction of all
Baseline Reliability Projects, since they would qualify as
purely local transmission facilities. So no Baseline Reliability
9
Projects would be open to competitive bidding under MISO’s
new regime.
LS Power, a subsidiary of LSP Transmission Holdings II,
LLC, and other non-incumbent transmission developers
opposed MISO’s proposal, arguing that it represented “an
attempt by MISO to exclude the majority of reliability projects
from the requirements of Order No. 1000[,]” including the
requirement that projects with regional benefits and subject to
regional cost-sharing be subject to competitive bidding. 2013
Order, 142 FERC ¶ 61215, at ¶ 495.
The Commission accepted MISO’s proposal, concluding
that location-based cost allocation for Baseline Reliability
Projects is “just and reasonable” and consistent with the cost-
causation principle. 2013 Order, 142 FERC ¶ 61215, at
¶¶ 518, 520–521. The Commission found “convincing support
for [MISO’s] claim that the pricing zone in which a Baseline
Reliability Project is located receives most of the benefits
provided by that project[,]” so that “assigning all of the
associated costs to that pricing zone results in an allocation of
costs that is roughly commensurate to the distribution of the
project’s benefits.” Id. at ¶ 521.
The Commission also concluded that MISO’s change in
cost allocation for Baseline Reliability Projects would not run
afoul of Order No. 1000’s rule that regional cost allocation be
available in some form for every type of transmission facility,
including those with reliability benefits. See 2013 Order, 142
FERC ¶ 61215, at ¶ 519. The Commission noted that Multi-
Value Projects, which also produce reliability benefits,
continue to have their costs allocated regionally. See id. And
the Commission found “persuasive MISO’s contention that,
going forward, its [Market Efficiency] and [Multi-Value]
10
project categories [would] displace Baseline Reliability
Projects” in satisfying regional transmission needs. Id.After the Commission denied rehearing, LS Power
petitioned the Seventh Circuit for review. See MISO
Transmission Owners, 819 F.3d at 331. The Seventh Circuit
acknowledged that location-based cost allocation for Baseline
Reliability Projects “would be problematic * * * if the benefits
of [such a project] were largely or entirely realized in pricing
zones other than the one in which the project was to be built.”
Id. at 336. But based on the Commission’s calculations, the
court concluded that “the spillover of [Baseline Reliability
Project] benefits to other zones” was “modest enough to make
the local allocation of costs ‘roughly commensurate’ with the
allocation of benefits[,]” and so rejected LS Power’s challenge.
Id. (citation omitted).
After the Seventh Circuit’s decision, MISO submitted
required informational filings to the Commission that detailed
the number of Multi-Value, Market Efficiency, and Baseline
Reliability Projects approved in 2014 and 2015, as well as a
line-outage analysis of the Baseline Reliability Projects
approved in 2014 and 2015. See 2013 Order, 142 FERC
¶ 61215, at ¶ 519. In those filings, MISO reported that 49
Baseline Reliability Projects were approved in 2014 and 2015
that would have previously been eligible for cost-sharing and
competitive bidding. Of those 49, applying line-outage
analysis, 46 would have had at least 75% of their costs
allocated to the local zone, and 45 would have had at least 90%
of their costs allocated to the local zone. As for the other
categories, no Market Efficiency Projects were approved in
2014 and only one was approved in 2015. No Multi-Value
Projects were approved in either year.
11
D
1
In January 2020, LS Power, joined by the Coalition of
MISO Transmission Customers and Industrial Energy
Consumers of America, filed a Section 206 complaint with the
Commission. They again challenged MISO’s use of location-
based cost allocation for Baseline Reliability Projects, and
asked the Commission to reimpose the old line-outage-based
system. Petitioners argued that new “[e]vidence based on
actual experience in the nearly seven years since the
Commission allowed a change in the cost allocation for
Baseline Reliability Projects” showed that allocating project
costs exclusively based on physical location is unjust and
unreasonable. Coalition of MISO Transmission Customers,
Complaint of Coalition of MISO Transmission Customers et
al. at 24, EL20-19-000 (Jan. 21, 2020) (“Complaint”) (Joint
Appendix (“J.A.”) 42).
The crown jewel of Petitioners’ new evidence was the so-
called “Pterra Report.” That report contained a line-outage
analysis of 29 Baseline Reliability Projects approved by MISO
between 2013 and 2018. Of those 29, the report identified
twelve for which line-outage analysis showed that “zones other
than the zone where the Baseline Reliability Project is
physically located received more than de minimis benefits from
the project.” Complaint at 26 (J.A. 44). In particular, for these
twelve Baseline Reliability Projects, zones other than the local
zone received 38%, 36%, 100%, 30%, 31%, 61%, 69%, 57%,
58%, 64%, 28%, and 43% of the project benefits as measured
by line-outage analysis.
Petitioners also pointed to MISO’s own informational
filings showing that only one Market Efficiency Project and
zero Multi-Value Projects were approved in 2014 and 2015.
12
Data from subsequent years told a similar story. Between 2016
and 2019, only two Market Efficiency Projects and zero Multi-
Value Projects were approved, all while hundreds of Baseline
Reliability Projects were greenlit. Based on these numbers,
Petitioners argued that a key premise underlying the
Commission’s 2013 Order had been undermined—namely, the
prediction that the Market Efficiency and Multi-Value Project
categories that are open to competitive bidding would displace
the Baseline Reliability Project category for projects with
regional benefits.
In response, MISO argued that Petitioners were launching
an impermissible collateral attack on the 2013 Order, and that
they had not shown any new or changed circumstances calling
into question the Commission’s prior conclusion that location-
based cost allocation for Baseline Reliability Projects is just
and reasonable. Additionally, MISO attacked the credibility of
the Pterra Report, asserting that it relied on a narrow and
unrepresentative sample of projects, was characterized by
numerous errors, and relied on a methodology that was
inherently flawed because line-outage analysis “is a measure of
impacts rather than benefits.” Coalition of MISO Transmission
Customers, Answer of the Midcontinent Independent System
Operator, Inc. at 23, WL20-19-000 (May 1, 2020) (“Answer”)
(J.A. 283). Even accepting the Pterra Report’s validity, MISO
countered that “the fact that, in some circumstances, some
[Baseline Reliability Projects] may provide some alleged
benefits beyond the pricing zone in which they are located does
not indicate that the underlying cost allocation methodology”
violates cost-causation principles. Id. at 27 (J.A. 287). Rather,
MISO insisted, Baseline Reliability Projects are
quintessentially local projects designed to address reliability
problems that are “highly localized” and “specific to individual
transmission facilities[,]” justifying local cost allocation. Id. at
35 (J.A. 295).
13
With respect to the miniscule number of Market Efficiency
and Multi-Value Projects authorized, MISO responded that
Petitioners “ignore[d] a number of important developments” in
MISO and the industry generally. Answer at 5 (J.A. 265). For
instance, MISO attributed the non-existence of new Multi-
Value Projects between 2014 and 2019 to the fact that a large
portfolio of seventeen Multi-Value Projects had been approved
in 2010 and 2011, obviating the need for projects of that type
in the following years. MISO also argued that “[d]eclining
natural gas prices and resource portfolio evolution from largely
coal to natural gas and renewables” had made it difficult to
“cost-justify” additional Market Efficiency Projects. Id. at 25
(J.A. 285). But it assured the Commission that it was working
to relax the minimum voltage threshold for Market Efficiency
Projects, which would theoretically increase the number of
such projects.2
2
In July 2020, the Commission denied Petitioners’
complaint, holding that they had “not met their burden under
[S]ection 206 of the [Federal Power Act] to demonstrate that
the current [Baseline Reliability Project] cost allocation
method is unjust [or] unreasonable[.]” Coalition of MISO
Transmission Customers, 172 FERC ¶ 61099, ¶ 81 (2020)
(“Order Denying Complaint”) (J.A. 527). In the Commission’s
view, the evidence and arguments advanced by Petitioners did
not undermine the Commission’s 2013 finding that “the
[transmission] pricing zone in which a [Baseline Reliability
Project] is located receives most of the benefits provided by
2
MISO’s change to the voltage threshold for Market Efficiency
Projects is at issue in a related case argued on the same day as this
one: LSP Transmission Holdings II, LLC v. FERC, No. 20-1465
(D.C. Cir. Aug. 19, 2022).
14
that project[.]” Id. (first alteration in original) (quoting 2013
Order, 142 FERC ¶ 61215, at ¶ 521) (J.A. 527–528). Nor did
it contradict the Seventh Circuit’s finding that the “spillover of
benefits to other zones is modest enough to make the local
allocation of costs ‘roughly commensurate’ with the allocation
of benefits[,]” for purposes of the cost-causation principle. Id.(quoting MISO Transmission Owners, 819 F.3d at 336) (J.A.
528).
The Commission gave little weight to the Pterra Report,
concluding that “the value and meaning of the findings in the
Pterra Report are mixed[,]” and that “the sample of projects
analyzed in the * * * Report is highly selective.” Order
Denying Complaint ¶ 87 (J.A. 531). The Commission also
credited MISO with having made “compelling arguments that
* * * the Pterra Report may contain significant errors.” Id.
Turning to MISO’s informational filings, the Commission
found that the data they contained did “not contradict the
information that the Commission relied upon” when it
approved location-based cost allocation in 2013. Order
Denying Complaint ¶ 88 (J.A. 531). It pointed to statistics
showing that, under line-outage analysis, 80% of the Baseline
Reliability Projects approved in 2014 and 2015 would have had
100% of their costs allocated to the local pricing zone and more
than 90% of such projects eligible for cost-sharing would have
had at least 90% of their costs allocated to the local zone.
While acknowledging that “MISO’s predictions on the
development of Multi-Value Projects and Market Efficiency
Projects [had] not to date materialized,” and that those
predictions were a “key factor” in the 2013 decision, the
Commission agreed with MISO that “there is potential for
expanded Market Efficiency Project opportunities in the
future[,]” citing MISO’s efforts to lower the voltage threshold
15
for Market Efficiency Projects. Order Denying Complaint ¶ 89
& n.254 (J.A. 532 & n.254).
3
Petitioners sought rehearing. After 30 days had passed,
the Commission issued a one-page order deeming the request
denied by operation of law. Coalition of MISO Transmission
Customers, 172 FERC ¶ 62179 (2020) (citing 16 U.S.C.
§ 825l(a); Allegheny Def. Project v. FERC, 964 F.3d 1 (D.C.
Cir. 2020) (en banc)) (J.A. 586).
Petitioners then filed for review in this court. MISO and a
number of incumbent transmission owners operating in MISO,
as well as several state governmental entities, intervened in
support of the Commission’s decision.
II
Under 16 U.S.C. § 825l, this court has statutory
jurisdiction to review petitions challenging a final order of the
Commission. The Commission asserts that we nonetheless
lack Article III jurisdiction because Petitioners have failed to
establish the injury-in-fact requirement of standing. The
Commission pressed a similar argument in LSP 2022 II, which
was rejected by this court. See No. 20-1465, slip op. at 13–16.
For much the same reasons, we hold that one of the Petitioners
in this case, LS Power, has sufficiently demonstrated standing.
LS Power is an independent transmission developer that
endeavors to compete for electrical utility construction
projects, including Baseline Reliability Projects, within MISO.
It has been certified as a MISO “Qualified Transmission
Developer[,]” meaning it has submitted “considerable
documentation” demonstrating its capability and experience in
transmission project development. Petitioners Reply Br. 9.
16
As this court ruled in LSP 2022 II, to establish the type of
injury that Article III requires for standing in this context, LS
Power need only show that (1) it “was ready, willing and able
to perform” the construction contracts for which it wished to
compete, and (2) the challenged action “deprived the company
of the opportunity to compete for the work.” No. 20-1465, slip
op. at 13 (internal quotation marks omitted) (quoting LSP
Transmission Holdings II, LLC v. FERC (LSP 2022 I), 28 F.4th
1285, 1288–1289 (D.C. Cir. 2022)). LS Power has met both
requirements.3
First, LS Power has made clear that it is “ready, willing
and able” to compete for Baseline Reliability Projects. LSP
2022 II, No. 20-1465, slip op. at 13 (citation omitted). It is
undisputed that LS Power is an active transmission
development company “that is qualified to participate in
MISO’s Order [No.] 1000 competitive transmission process.”
Petitioners Opening Br. 27. There is also good reason to think
that LS Power would actually compete for transmission
projects within MISO if given the opportunity to do so. In one
of only two competitive solicitations that MISO has held since
Order No. 1000 issued, an LS Power affiliate won the contract.
3 The separate opinion’s concerns are well taken as we all agree
“that a bare assertion that a petitioner is ‘ready, willing, and able’ to
compete is [not] sufficient to establish Article III injury-in-fact.” Op.
of Rogers, J. at 3; see also id. at 5. Instead, a petitioner must also
show that agency action has “deprived [it] of the opportunity to
compete for the work.” LSP 2022 I, 28 F.4th at 1289 (internal
quotation marks and citation omitted). And it must substantiate its
standing by pointing to record evidence or submitting new evidence.
Sierra Club v. EPA, 292 F.3d 895, 899–900 (D.C. Cir. 2002). As we
explain below, LS Power has done just that by showing both that it
has competed for the rare project open to it, and that the challenged
rule now categorically excludes it from competing for all Baseline
Reliability Projects going forward.
17
See Petitioners Opening Br. 27–28; see also Petitioners Reply
Br. 10; LSP 2022 I, 28 F.4th at 1289 (“[LS Power]
demonstrated its readiness when its subsidiary bid on the only
one of thirty-one recent reliability projects open to competitive
bidding.”).
Second, LS Power has shown that the Commission’s
decision to allow MISO to retain location-based cost allocation
for Baseline Reliability Projects has “deprived the company of
the opportunity to compete for the work.” LSP 2022 II, No.
20-1465, slip op. at 13 (internal quotation marks and citation
omitted). LS Power explains that “[b]ecause all Baseline
Reliability Projects are subject to a local cost allocation
requirement, * * * LS Power has been prohibited from
competing for any of the more than 500 Baseline Reliability
Projects approved since the cost allocation change and will
continue to be excluded” under MISO’s current regime.
Petitioners Opening Br. 27. As a result, LS Power alleges,
MISO’s “inaccurate cost allocation scheme for Baseline
Reliability Projects has the direct and intended effect of
prohibiting competition for all Baseline Reliability Projects[,]
foreclosing opportunities for LS Power.” Petitioners Reply Br.
9 (formatting modified) (citing Complaint at 20 (J.A. 38)); cf.
Northeastern Fla. Chapter of the Associated Gen. Contractors
of America v. City of Jacksonville, 508 U.S. 656, 668 (1993)
(finding standing based on petitioner’s allegations “that its
members regularly bid on construction contracts in
Jacksonville, and that they would have bid on contracts set
aside pursuant to the city’s ordinance were they so able”).
The Commission relies on this court’s unpublished
judgment in LSP Transmission Holdings, LLC v. FERC (LSP
2017), 700 F. App’x 1 (D.C. Cir. 2017) (per curiam), to argue
that LS Power’s alleged injury is impermissibly speculative
because LS Power has failed to identify a specific project on
18
which it would bid. That decision “has no bearing on this
case.” LSP 2022 I, 28 F.4th at 1289; see LSP 2022 II, No. 20-
1465, slip op. at 14–15. LS Power need not point to one
specific project it has been deprived of the opportunity to
compete for because there can “be no doubting [LS Power’s]
assertion that it has been denied the ability to bid” on all
Baseline Reliability Projects, full stop. LSP 2022 I, 28 F.4th at
1289; see LSP 2022 II, No. 20-1465, slip op. at 15. In other
words, LS Power has shown that it has been walled off from an
entire category of projects for which it is qualified, prepared,
and eager to compete.
In any event, LS Power has pointed to specific Baseline
Reliability Projects it alleges would have been open to bidding
but for the local allocation of costs. LS Power pinpointed
twelve Baseline Reliability Projects in the Pterra Report that it
claims have significant regional benefits and should have been
competitively bid. See Petitioner Opening Br. 12; see also
Complaint at 26–29 (J.A. 44–47). In its complaint, LS Power
also identified 113 Baseline Reliability Projects included in the
then-upcoming 2019 MISO Transmission Expansion Plan that
it alleged were highly likely to have regional benefits. See
Complaint at 47 (J.A. 65). And those are the very projects for
which LS Power says it desires to compete. See Petitioners
Opening Br. 27–28.
So like in LSP 2022 I and LSP 2022 II, LS Power has
demonstrated a concrete injury that is caused by the
Commission’s continued approval of MISO’s cost-allocation
system, and that would be remedied by an order of this court
overturning the Commission’s decision.4
4
As was true in LSP 2022 II, we need not and do not rely on
the supplemental briefing and affidavits in concluding that LS Power
19
III
A
We review Commission orders under the familiar arbitrary
and capricious standard, see ESI Energy, LLC v. FERC, 892
F.3d 321, 329 (D.C. Cir. 2018) (citing 5 U.S.C. § 706(2)), and
regard the Commission’s factual findings as conclusive as long
as they are supported by substantial evidence, 16 U.S.C.
§ 825l(b). Arbitrary and capricious review is “narrow”—we
are “not to ask whether a regulatory decision is the best one
possible or even whether it is better than the alternatives.”
FERC v. Electric Power Supply Ass’n, 577 U.S. 260, 292
(2016) (quoting Motor Vehicle Mfrs. Ass’n of U.S., Inc. v. State
Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983)). Rather, we
must uphold the agency’s decision as long as it has
“examine[d] the relevant data and articulate[d] a satisfactory
explanation for its action.” State Farm, 463 U.S. at 43. And
we defer to the Commission’s “predictive judgments about
areas that are within [its] field of discretion and expertise * * *,
as long as they are reasonable.” Wisconsin Pub. Power, Inc. v.
has established standing, although we agree with the concurring
opinion that they soundly establish standing in this case. See No. 20-
1465, slip op. at 16 n.3. Likewise, because LS Power has standing
to raise each of Petitioners’ claims, we need not address whether
organizational petitioners Coalition of MISO Transmission
Customers and Industrial Energy Consumers of America have
established standing in their own right. See Food & Water Watch v.
FERC, 28 F.4th 277, 284 (D.C. Cir. 2022) (“[W]hen multiple
petitioners bring claims jointly, only one petitioner needs standing to
raise each claim.”) (citation omitted).
20
FERC, 493 F.3d 239, 260 (D.C. Cir. 2007) (per curiam)
(citation omitted).
“The statutory requirement that rates be ‘just and
reasonable’ is obviously incapable of precise judicial
definition,” affording the Commission leeway in its ratemaking
decisions, Morgan Stanley Cap. Group Inc. v. Public Util. Dist.
No. 1, 554 U.S. 527, 532 (2008), especially when, as here, the
matters at issue are “either fairly technical or involve policy
judgments that lie at the core of the [Commission’s] regulatory
mission[,]” South Carolina Pub. Serv. Auth., 762 F.3d at 54–
55 (internal quotation marks and citation omitted).
In enforcing the cost-causation principle, “we have never
required a ratemaking agency to allocate costs with exacting
precision.” Midwest ISO, 373 F.3d at 1369. In other words,
the Commission “is not bound to reject any rate mechanism
that tracks the cost-causation principle less than perfectly[.]”
Sithe/Independence Power Partners, L.P. v. FERC, 285 F.3d 1,
5 (D.C. Cir. 2002). “It is enough, given the standard of review
* * *, that the cost allocation mechanism not be ‘arbitrary or
capricious’ in light of the burdens imposed or benefits
received.” Midwest ISO, 373 F.3d at 1369.
B
To Petitioners’ credit, they have demonstrated a
significant mismatch between costs and benefits for at least
some of the projects identified in the Pterra Report. But the
Petitioners’ argument has some mismatch of its own. Their
new evidence is of limited scope, exposing a cost-causation
problem for, at most, twelve out of approximately 400 projects.
And yet the relief they seek is expansive—they argue that
location-based cost allocation is no longer just and reasonable
for the entire category of Baseline Reliability Projects. Given
that imbalance, it was not arbitrary or capricious for the
21
Commission to deny Petitioners’ complaint and retain the
current cost-allocation regime for Baseline Reliability
Projects.5
1
The Commission gave location-based cost allocation its
stamp of approval in 2013 based on its determination that “the
pricing zone in which a Baseline Reliability Project is located
receives most of the benefits provided by that project[.]” 2013
Order, 142 FERC ¶ 61215, at ¶ 521. The Seventh Circuit, in
affirming the Commission’s decision, agreed that “the
spillover of [Baseline Reliability Project] benefits” to zones
other than the local zone “is modest enough” not to run afoul
of the cost-causation principle. MISO Transmission, 819 F.3d
at 336.
Petitioners have upended those determinations—at least
for a small subset of Baseline Reliability Projects. Recall that
in the Pterra Report, Petitioners identified twelve Baseline
Reliability Projects for which zones other than the local zone
received 38%, 36%, 100%, 30%, 31%, 61%, 69%, 57%, 58%,
64%, 28%, and 43% of the project benefits as measured by line-
outage analysis. These percentage spillovers can hardly be
5
As a threshold matter, the Commission asserts that Petitioners
are levying an impermissible collateral attack on the Commission’s
2013 Order that originally approved location-based cost allocation
for Baseline Reliability Projects. The Commission is wrong.
Petitioners’ relevant arguments are based on new evidence derived
from actual experience since 2013, placing them outside the rule
barring collateral attacks on previous orders. See Blumenthal v.
FERC, 552 F.3d 875, 881 n.2 (D.C. Cir. 2009) (finding no improper
collateral attack where petition relied on “factual developments” that
were “unanticipated” at the time of the original orders).
22
characterized as “modest[.]” MISO Transmission, 819 F.3d at
336. In fact, Petitioners calculated that, taken together, these
projects represented over $275 million in misallocated costs.
One might quibble over whether a spillover in the 30% range
is significant, but the local zone certainly does not receive
“most of the benefits[,]” 2013 Order, 142 FERC ¶ 61215, at
¶ 521, provided by a project if over 50% of its benefits flow to
other zones, which is exactly the case for six projects identified
in the Pterra Report. If Zone A is paying 100% of a project’s
costs, but Zone B is receiving 58%, 64%, or even 69% of the
benefits, then costs are not being allocated in a manner that is
“at least roughly commensurate” with benefits, as the cost-
causation principle mandates. South Carolina Pub. Serv.
Auth., 762 F.3d at 53 (citation omitted).
In Old Dominion, this court characterized benefit
spillovers of 53% and 57% as representing a “severe
misallocation of * * * costs[.]” 898 F.3d at 1261. That degree
of misalignment between costs incurred and benefits received
did “not amount to a quibble about ‘exacting precision,’” but
rather “a wholesale departure from the cost-causation
principle[.]” Id. (quoting Midwest ISO, 373 F.3d at 1369).
Given that several of the projects highlighted in the Pterra
Report are plagued by percentage spillovers exceeding those at
issue in Old Dominion, location-based cost allocation is
inconsistent with the cost-causation principle at least for those
projects.
The Commission did not wholly disregard the Pterra
Report. But it accorded the Report scant weight, concluding
“that the value and meaning of the findings in the * * * Report
are mixed.” Order Denying Complaint ¶ 87 (J.A. 531). For
one thing, the Commission criticized the Report for using a
small and “highly selective” sample of projects, consisting of
23
just 29 out of at least 400 Baseline Reliability Projects from the
relevant period. Id. ¶ 87 & n.248 (J.A. 531 & n.248).
That may be true. It is also beside the point. Petitioners
never claimed to be presenting a representative sample of
Baseline Reliability Projects in the Pterra Report. Their claim
was merely that costs and benefits were significantly
misaligned for all twelve of the specific projects they had
identified, and that those twelve bad apples were enough to
spoil the whole methodology.
The Commission also noted that MISO made “compelling
arguments” that the Report “may” have “significant errors.”
Order Denying Complaint ¶ 87 (J.A. 531). But the
Commission itself did not actually name multiple or significant
errors. Instead, it pointed to a single mistake where the
complaint had misidentified the pricing zone for one project,
so the percentage of benefits accruing outside the local zone
should have been listed as 31% rather than 98%. Id. ¶ 87 n.249
(J.A. 531 n.249). Petitioners insist that this error traced back
to inaccurate information supplied by MISO. Anyhow, they
have used the correct 31% figure in all subsequent filings.
More to the point, substituting a 31% spillover for a 98%
spillover is not so significant as to affect the upshot of the
Pterra Report—that there are at least some Baseline Reliability
Projects for which the current cost-allocation regime produces
results inconsistent with the cost-causation principle.
Before this court, the Commission advances a more global
methodological critique of the Pterra Report. It argues that
line-outage analysis—the method MISO formerly used to
allocate costs and that Petitioners used to produce the Pterra
Report—is not a measure of benefits but rather a measure of
impacts, which can be beneficial, neutral, or detrimental.
While MISO urged this point below, the Commission did not
24
adopt it in its order denying the complaint. So we give that
rationale no weight in evaluating the Commission’s reasoning.
See SEC v. Chenery Corp., 332 U.S. 194, 196 (1947); Calpine
Corp. v. FERC, 702 F.3d 41, 46 (D.C. Cir. 2012) (“[I]t is
axiomatic that agency decisions may not be affirmed on
grounds not actually relied upon by the agency.”).6
Beyond that, the Commission itself had previously
instructed MISO to include data generated through line-outage
analysis in its informational filings, and then used that data to
support its conclusion that location-based cost allocation for
Baseline Reliability Projects remains sound. See, e.g., Order
Denying Complaint ¶ 88 (J.A. 531–532) (“[T]he 2016 and
2017 Informational Filings indicate that 80% of [Baseline
Reliability Projects] approved in the [2014 and 2015 cycles]
would have had 100% of costs allocated to the * * * local
pricing zone under the previous [line-outage] method.”). The
Commission cannot have it both ways, using line-outage
analysis to buttress its decision but casting it aside when it cuts
the other way.
The Commission separately justifies its conclusion that
location-based cost allocation for Baseline Reliability Projects
remains just and reasonable on the ground that the purpose of
Baseline Reliability Projects is to address “specific and
localized” reliability issues. Order Denying Complaint ¶ 86
(J.A. 531). That hardly moves the ball forward. Even if the
intended purpose of a transmission project is to fix a reliability
6
In its brief, the Commission claims that there were analytical
errors pertaining to a few other projects in the Pterra Report’s overall
pool. But the Commission did not cite these alleged errors in its
orders, so this argument suffers from the same Chenery problem.
25
problem in one zone, that does not mean its benefits will be
limited to that zone.
Also, the notion that the benefits of a new transmission
facility are confined to the artificial boundaries of the local
pricing zone “ignores the interconnected nature of the grid.”
Coalition of MISO Transmission Customers, Responsive
Testimony of Ricardo R. Austria at 10, EL20-19-000 (June 8,
2020) (J.A. 486). Take the Pterra Report projects. Even if they
were initially commissioned to resolve specific and localized
problems, a significant percentage of their benefits flow
outside the local zone. When it comes to evaluating
compliance with the cost-causation principle, it is the
distribution of benefits, not the original impetus for the project,
that matters. See Old Dominion, 898 F.3d at 1262 (“[T]he cost-
causation principle focuses on project benefits, not on how
particular planning criteria were developed.”).
2
Petitioners also point to the disparity between the number
of Market Efficiency and Multi-Value Projects—projects that
would be open to competitive bidding—that MISO originally
forecast and the number that actually arose as further evidence
that the categorical bar on regionally allocating costs of
Baseline Reliability Projects should be revisited. The
Commission fares better on this front.
The Commission acknowledged that “MISO’s predictions
on the development of Multi-Value Projects and Market
Efficiency Projects [had] not to date materialized,” yet it held
firmly to its bottom-line conclusion that Baseline Projects need
never be cost-allocated on a regional basis. Order Denying
Complaint ¶ 89 (J.A. 532). The Commission reasoned that
industry conditions had “significantly affected trends” in
26
project development, and there was “potential for expanded
Market Efficiency Project opportunities in the future.” Id.
Given the Commission’s expertise and first-hand
experience with trends in the energy industry, its judgment that
the dearth of Market Efficiency and Multi-Value Projects in
past years will not necessarily persist going forward warrants
deference. See Wisconsin Pub. Power, 493 F.3d at 260.
Factors like the shifting economics of natural gas and coal, and
the completion of the large portfolio of Multi-Value Projects
approved in 2010 and 2011, could lead to renewed demand for
Market Efficiency and Multi-Value Projects. See Order
Denying Complaint ¶¶ 55, 89 (J.A. 518, 532). Similarly, the
Commission’s assessment that recent changes to the MISO
tariff—like the decrease in voltage threshold for Market
Efficiency Projects at issue in LSP 2022 II—will bolster the
number of regionally beneficial projects eligible for
competitive bidding is reasonable. Of course, if the number of
competitively bid Multi-Value and Market Efficiency Projects
continues to hover near zero, while the number of Baseline
Reliability Projects closed off from competition continues to
climb, the Commission may be obligated to reassess. But for
now, it is entitled to the benefit of the doubt.
3
To sum up so far, the Commission sufficiently explained
why the low number of Multi-Value and Market Efficiency
Projects does not currently warrant a change in the Baseline
Reliability Project cost-allocation method. But it did not
adequately rebut evidence from the Pterra Report indicating
that, for at least some Baseline Reliability Projects, costs are
being allocated in a manner that is not roughly commensurate
with benefits.
27
Even so, the Commission argues, location-based cost
allocation still produces a result consistent with the cost-
causation principle for “the overwhelming majority” of
Baseline Reliability Projects, and so the method remains just
and reasonable. Commission Br. 40 (citation omitted).
Petitioners argue that it is not enough for a cost-allocation
regime to satisfy the cost-causation principle “most of the
time” because the Federal Power Act requires that all rates be
just and reasonable. Petitioners Opening Br. 41 (citing 16
U.S.C. §§ 824d–824e).
We agree with Petitioners that the Commission is under a
statutory mandate to ensure that all rates are just and
reasonable, and Petitioners have shown that rates are not
presently just and reasonable for a small number of Baseline
Reliability Projects. But that does not get the Petitioners home.
That is because their petition for review does not seek as-
applied relief just for those Baseline Reliability Projects that
they have shown run afoul of the cost-causation principle.
Instead, Petitioners asked the Commission to invalidate
location-based cost allocation for the entire category of
Baseline Reliability Projects, even though Petitioners
themselves admit that allocating costs to the local zone is
appropriate for “most” Baseline Reliability Projects.
Petitioners Reply Br. 5 (emphasis omitted). The validity of an
overall cost-allocation rule need not be determined “on a
project-by-project basis, which would unravel the framework
of” specifying cost-allocation methods for categories of
projects ex ante “established by Order No. 1000 and approved
by this Court.” Long Island Power Auth. v. FERC, 27 F.4th
705, 715 (D.C. Cir. 2022). In essence, Petitioners’ evidence—
limited as it is to a few Baseline Reliability Projects—is
insufficient to upset the Commission’s continued
determination, which is still supported by record evidence, that
28
the general rule of location-based cost allocation for Baseline
Reliability Projects conforms with the cost-causation principle.
Petitioners argue that this court in Old Dominion, and the
Commission itself in Delaware Public Service Commission,
166 FERC ¶ 61161 (2019), aff’d sub nom. Public Service
Electric & Gas. Co., 989 F.3d at 13, rejected the notion that a
cost-allocation method is just and reasonable as long as it
works “most of the time.” Petitioners Opening Br. 41–42.
Petitioners misunderstand both cases.
In Old Dominion, this court held that it was arbitrary and
capricious for the Commission to allow one of MISO’s peers,
PJM Interconnection, LLC, to eliminate regional cost-sharing
for an entire group of high-voltage projects when the
Commission itself had previously made a factual finding that
all “high-voltage transmission facilities have significant
regional benefits that accrue to all members of the PJM
transmission system.” 898 F.3d at 1257 (citation omitted); see
also id. at 1261.
Petitioners claim that Old Dominion is on all fours with the
present case. Not so. In Old Dominion, the petitioners
challenged a change in cost-allocation method that affected
only high-voltage projects after the Commission had already
found that such projects, as a category, produce significant
regional benefits. Here, by contrast, Petitioners are challenging
a cost-allocation method applicable to all Baseline Reliability
Projects, based on a showing that only a handful of Baseline
Reliability Projects do not fit the model. Said another way, in
Old Dominion the scope of the petitioners’ challenge matched
the scope of their evidence. Here, Petitioners’ challenge far
overreaches their evidence.
As for Delaware Public Service Commission, in that case,
PJM approved a project to help improve the stability of a set of
29
nuclear power plants in New Jersey by providing new outlets
for their electricity flows terminating at a substation in
Delaware. Public Serv. Elec. & Gas Co., 989 F.3d at 14–15.
The Commission rejected PJM’s proposal to assign nearly 90%
of the costs to the Delaware-Maryland zone because the
primary beneficiary was the New Jersey zone containing the
nuclear generators in need of stabilization. Id. at 14–16. The
Commission explained that, in the “analytically unique”
context of stability-based grid problems, PJM’s cost-allocation
method premised on electrical flows failed to identify the true
beneficiaries. Id. at 18 (citation omitted). This court sustained
the Commission’s decision, agreeing that leaving the
Delaware-Maryland zone—the “unlucky zone that happened to
end up as the sink point for the project”—to pick up 90% of the
check was inconsistent with the cost-causation principle. Id.
(formatting modified and citation omitted).
Observing that the Commission in Delaware Public
Service Commission found a cost-allocation methodology
inappropriate where the zone bearing the costs had not caused
the need for, or received commensurate benefits from, the
project, Petitioners assert that “[f]or the twelve projects
identified in the Complaint, that was precisely the showing[.]”
Petitioners Opening Br. 41 (emphasis added).
Maybe so. But in Delaware Public Service Commission,
the Delaware and Maryland agencies demonstrated a violation
of the cost-causation principle applicable to all stability-related
projects, and the Commission ordered a change in the cost-
allocation method for that “analytically unique” category.
Public Serv. Elec. & Gas Co., 989 F.3d at 17–18 (citation
omitted). Here, by contrast, Petitioners have demonstrated a
violation of the cost-causation principle for, at most, twelve
Baseline Reliability Projects, but are seeking a change in the
cost-allocation method for all Baseline Reliability Projects. So
30
like Old Dominion, Delaware Public Service Commission
simply accentuates the gap between the scope of Petitioners’
evidence and the relief they seek.
4
To be clear, that Petitioners’ facial challenge to the
Commission’s ongoing endorsement of location-based cost
allocation for the entire category of Baseline Reliability
Projects falls short does not mean that an “as-applied”
challenge to the application of location-based cost allocation to
a particular Baseline Reliability Project or subset of Baseline
Reliability Projects would meet the same fate. Cf. Public Serv.
Elec. & Gas Co., 989 F.3d at 12–13; BNP Paribas Energy
Trading GP v. FERC, 743 F.3d 264, 265–266 (D.C. Cir. 2014)
(rejecting Commission’s conclusion that the cost-allocation
method for a single gas storage field complied with the cost-
causation principle).
For the statutory requirement of just-and-reasonable rates
to have meaningful effect in this context, there must be a
feasible means by which affected parties like Petitioners can
challenge a cost-allocation method as applied to a specific
project, and a means by which they can do so before the horse
has left the barn—that is, while the transmission owner
assigned to the project and the distribution of costs can still be
altered. Regulated parties should also have timely access to the
data necessary for them to determine whether to bring an “as-
applied” cost-causation challenge in the first place, such as the
project models that Petitioners used to produce the Pterra
Report analysis. See Complaint at 47 (J.A. 65) (“MISO models
available in February 2020 will determine whether” the
Baseline Reliability Projects in the 2019 plan “have regional
benefits.”); see also Oral Arg. Tr. 25:17–19 (MISO “doesn’t
release the models until after the fact[.]”). Nothing the
31
Commission represented here suggests that such “as-applied”
challenges are incompatible with its regulatory framework.
See Oral Arg. Tr. 47:18–19 (Commission counsel stating, “I do
think that the rate structure would provide for that sort of as-
applied challenge.”).
C
Petitioners next object that the Commission failed to
explain how MISO’s retention of location-based cost allocation
for Baseline Reliability Projects remains consistent with Order
No. 1000’s prohibition on excluding an entire type of
transmission facility—here, reliability projects—from regional
cost allocation. The reasons provided were reasoned enough.
In 2013, the Commission determined that eliminating
regional cost allocation for Baseline Reliability Projects was
compatible with Order No. 1000 since Multi-Value Projects
also produced reliability benefits and remained eligible for
regional cost-sharing and competitive bidding. 2013 Order,
142 FERC ¶ 61215, at ¶ 519; see also MISO Transmission, 819
F.3d at 335 (“It’s true that [the Commission] is not allowed to
exempt all reliability projects from cost sharing, * * * but it can
exempt some as long as other types of transmission projects
that yield reliability benefits, such as [M]ulti-[V]alue
[P]rojects, can be included in a regional plan for purposes of
cost allocation.”). Emphasizing that not a single Multi-Value
Project was approved between 2014 and 2019, Petitioners
assert that, in reality, MISO has “no viable regional cost
allocation mechanism available for reliability based projects,
in direct violation of Order [No.] 1000.” Petitioners Opening
Br. 53.
As explained earlier, the Commission adequately justified
its conclusion that temporary and sui generis conditions in the
region and industry account for the absence of new Multi-
32
Value Projects in recent years, and that such conditions are
unlikely to continue in the future. See Section III.B.2, supra.
So the Commission has determined, based on its relevant
expertise, that Multi-Value Projects remain a viable category
of projects subject to regional cost-sharing. On this record, we
lack a sufficient basis to second-guess that determination.
D
Finally, the Commission did not shirk its requirement of
reasoned decisionmaking by failing to issue a substantive
response to Petitioners’ rehearing request, issuing instead a
one-page order stating that the request was denied by operation
of law. The rehearing request merely reiterated arguments
raised earlier and already addressed by the Commission in its
order denying the complaint. So the Commission was under
no obligation to say again what it had said before.
Petitioners counter that their rehearing request “rais[ed]
five distinct specifications of error.” Petitioners Opening Br.
56. It certainly did. But every one of those five is simply a
repackaged version of an argument previously raised either in
Petitioners’ complaint or in their response to MISO’s answer,
as evidenced by Petitioners’ practice of repeatedly referring
back to those earlier filings. For example, in the rehearing
request, Petitioners argue that the Commission wrongly
determined “that Baseline Reliability Projects are designed to
address specific and localized issues.” Coalition of MISO
Transmission Customers, Request for Rehearing at 22, EL20-
19-000 (Aug. 27, 2020) (“Request for Rehearing”) (J.A. 559)
(emphasis omitted). That is apparently so for reasons
“established in the Complaint[.]” Id. at 23 (J.A. 560). But the
Commission had already explained in its order denying the
complaint that it found more persuasive MISO’s contention
that “the type of reliability issue that a [Baseline Reliability
33
Project] is designed to address is typically specific to a
particular transmission facility or set of facilities owned by the
same transmission owner.” Order Denying Complaint ¶ 86
(J.A. 531). In that same way, Petitioners rinse and repeat for
all five asserted errors.7
Under these circumstances, nothing in the APA or the
Federal Power Act obligated the Commission to duplicate in a
rehearing order the analytical work it had already done. Nor
can Petitioners show prejudice from the Commission’s failure
to parrot its earlier responses. After all, the purpose of
requiring an agency to explain itself is to “provide a considered
response to the losing party and an opportunity for intelligent
review by the courts.” Cities of Bethany v. FERC, 727 F.2d
1131, 1144 (D.C. Cir. 1984). The Commission’s order denying
the complaint both furnished an answer to each of Petitioners’
objections and supplied this court with enough explanation to
facilitate meaningful review.
7
Compare Request for Rehearing at 8–15 (J.A. 545–552), with
Complaint at 25–30 (J.A. 43–48), and Coalition of MISO
Transmission Customers, Motion to Answer and Answer of
Complainants at 3–7, 12–15, EL20-19-000 (June 8, 2020)
(“Response to Answer”) (J.A. 403–407, 412–415) (first specification
of error); Request for Rehearing at 22–27 (J.A. 559–564), with
Response to Answer at 43–47 (J.A. 443–447) (second specification
of error); Request for Rehearing at 27–30 (J.A. 564–567), with
Complaint at 17–19 (J.A. 35–37) (third specification of error);
Request for Rehearing at 30–42 (J.A. 567–579), with Complaint at
25–30, 35–39 (J.A. 43–48, 53–57), and Response to Answer at 48–
57 (J.A. 448–457) (fourth specification of error); Request for
Rehearing at 42–45 (J.A. 579–582), with Complaint at 30–32 (J.A.
48–50), and Response to Answer at 35–43 (J.A. 435–443) (fifth
specification of error).
34
IV
For all those reasons, the petition for review is denied.
So ordered.
ROGERS, Circuit Judge, dissenting in part and concurring
in part. LSP petitions for review of FERC orders in two cases,
contending that it has been denied the opportunity to bid on
transmission projects. A threshold issue was whether LSP
demonstrated that it has standing under Article III of the
Constitution to bring these challenges. At oral argument in
both cases LSP’s experienced counsel asserted that standing
was self-evident, but candidly acknowledged in response to
questions1 that LSP’s filings did not include specific evidence
of its injury-in-fact, as required to establish standing.2 Because
detailed averments in LSP’s supplemental affidavits filed in
response to the court’s order, see Am. Orders, No. 20-1421 &
No. 20-1465 (Feb. 28, 2022) (Rogers, J., not joining), suffice
to demonstrate standing, I concur in holding LSP has standing
and in rejecting LSP’s merits challenges to FERC’s orders.
I.
To establish standing under Article III, a party “must have
(1) suffered an injury in fact, (2) that is fairly traceable to the
challenged conduct of the defendant, and (3) that is likely to be
redressed by a favorable judicial decision.” Twin Rivers Paper
Co. LLC v. SEC, 934 F.3d 607, 612 (D.C. Cir. 2019) (quoting
Spokeo, Inc. v. Robins, 136 S. Ct. 1540 (2016)). “The party
invoking the federal courts’ jurisdiction bears the burden of
establishing each of those elements.” Util. Workers Union of
Am. Local 464 v. FERC, 896 F.3d 573, 577 (D.C. Cir. 2018)
(quoting Lujan v. Defs. of Wildlife, 504 U.S. 555, 561 (1992)).
Where, as here, the petitions challenge FERC’s orders directly,
the petitioner’s “burden of production” is “the same as that of
a plaintiff moving for summary judgment in the district court:
it must support each element of standing ‘by affidavit or other
evidence,’ including whatever evidence the administrative
1
See OA Tr. No. 20-1421, at 14; OA Tr. No. 20-1465, at 11-12.
2
See OA Tr. No. 20-1421, at 14; OA Tr. No. 20-1465, at 11-12, 21-
23.
2
record may already contain.” Id. (quoting Sierra Club v. EPA,
292 F.3d 895, 899-900 (D.C. Cir. 2002)). More is “requir[ed]”
than “representations of counsel” in briefs, Sierra Club, 292
F.3d at 901, or a party’s “bare assertions,” Util. Workers Union,
896 F.3d at 578. Standing may be self-evident “if the
complainant is ‘an object of the action (or foregone action) at
issue.’” Sierra Club, 292 F.3d at 900 (quoting Lujan, 504 U.S.
at 561-62). But when, as here, “a petitioner is not directly
regulated by the challenged [order],” Am. Fuel & Petro. Mfrs.
v. EPA, 3 F.4th 373, 379 (D.C. Cir. 2021), standing is
“ordinarily ‘substantially more difficult’ to establish,” Ass’n of
Am. Physicians & Surgeons, Inc. v. Schiff, 23 F.4th 1028, 1032
(D.C. Cir. 2022) (quoting Lujan, 505 U.S. at 562). More
specifically, if standing is not “self-evident,” then there must
either be evidence in the administrative record of the requisite
injury or petitioners must file sworn affidavits with the opening
briefs “substantiat[ing]” these injuries. Sierra Club, 292 F.3d
at 900; see D.C. Circuit Rule 28(a)(7) (incorporating Sierra
Club, 292 F.3d at 900-01).
It is well settled that the petitioner invoking this court’s
jurisdiction has the burden to provide evidence that it suffers
an injury “that is both ‘concrete and particularized’ and ‘actual
or imminent, not conjectural or hypothetical,’” New England
Power Generators Ass’n, Inc. v. FERC, 707 F.3d 364, 368
(D.C. Cir. 2013) (quoting Lujan 504 U.S. at 560-61), because
the injury “has either transpired or is ‘imminent.’” No Gas
Pipeline v. FERC, 756 F.3d 764, 767 (D.C. Cir. 2014) (citing
Occidental Permian Ltd. v. FERC, 673 F.3d 1024, 1026 (D.C.
Cir. 2012)). The imminence requirement “ensure[s] that the
alleged injury is not too speculative for Article III purposes,”
Union of Concerned Scientists v. Dep’t of Energy, 998 F.3d
926, 929 (D.C. Cir. 2021) (quoting Clapper, 568 U.S. at 409),
so assertions of incurring harm “some day,” Kans. Corp.
Comm’n v. FERC, 881 F.3d 924, 930 (D.C. Cir. 2018) (quoting
3
Lujan, 504 U.S. at 564), or dependent upon an “attenuated
chain” of interim steps, id. (quoting Clapper, 568 U.S. at 410),
are insufficient. Rather, the petitioner must “show a
‘substantial probability’ that all of these steps will occur and, if
so, when.” Id. (quoting Am. Petroleum Inst. v. EPA, 216 F.3d
50, 63 (D.C. Cir. 2000)).
Neither the Supreme Court nor this court has held that a
bare assertion that a petitioner is “ready, willing, and able” to
compete is sufficient to establish Article III injury-in-fact.
Contra No. 20-1421, slip op. at 16; No. 20-1465, slip op. at 14.
Nor was this argument advanced by LSP in its opening briefs.
Cf. Schneider v. Kissinger, 412 F.3d 190, 200 n.1 (D.C. Cir.
2005). As the court recently reiterated, “general averments,
conclusory allegations, and speculative some day intentions are
inadequate to demonstrate injury in fact.” Finnbin, LLC v.
Consumer Prod. Safety Comm’n, No. 21-1180 (Aug. 2, 2022)
(slip op. at 13) (quoting Worth v. Jackson, 451 F.3d 854, 858
(D.C. Cir. 2006)). Thus, in LSP Transmission Holdings, LLC
v. FERC (“LSP I”), 700 F. App’x 1 (D.C. Cir. 2017), the court
found no standing where petitioners “identified no specific
project” for which they were prevented from competing. Id. at
*2. By contrast, in LSP Transmission Holdings II, LLC v.
FERC (“LSP II”), 28 F.4th 1285 (D.C. Cir. 2022), the court
held petitioners had standing when they “identified” “thirty []
projects” for which they were “denied the ability to bid.” Id. at
1289.
II.
Although this court has identified limited circumstances
where it may exercise its discretion to request that parties
submit supplemental affidavits to establish their standing,
those circumstances did not exist in the instant cases. For
example, “if the parties reasonably, but mistakenly, believed
4
that the initial filings before the court had sufficiently
demonstrated standing, the court may . . . request supplemental
affidavits and briefing to determine whether the parties have
met the requirements for standing.” Ams. For Safe Access v.
DEA, 706 F.3d 438 (D.C. Cir. 2013) (citing Pub. Citizen, Inc.
v. Nat’l Highway Traffic Safety Admin., 489 F.3d 1279, 1296–
97 (D.C. Cir. 2007)). And although LSP’s counsel in both
cases acknowledged the insufficiency of their initial filings,
they never requested that the court allow them to provide
supplemental affidavits, as had occurred in American Library
Ass’n v. FCC, 401 F.3d 489, 492 (D.C. Cir. 2005). See Cmtys.
Against Runway Expansion, Inc. v. FAA, 335 F.3d 678, 684
(D.C. Cir. 2004). Indeed it appears that LSP’s reluctance, in
the absence of a court order to supplement the record here may
stem from interim action by the Commission to afford
petitioners like LSP the relief they sought, namely for the
Commission to reconsider its requirements for approving
transmission development plans. See Advance Notice of
Proposed Rulemaking (July 15, 2021) (“2021 ANPR”), RM21-
17-000, where there is a broad and comprehensive inquiry into
the effects of its Orders on transmission planning and
development, see 2021 ANPR, at 26, where LSP has submitted
lengthy comments; No. 20-1421, Pet’rs’ Br. at 21-25; No. 20-
1465, Pet’rs’ Br. at 26-30.
Consequently, upon expanding circumstances for
supplemental filings, the court ordered LSP to file
supplemental submissions “to explain and substantiate their
claim of standing.” See Am. Orders, at 1 (Feb. 28, 2022)
(Rogers, J., not joining). 3 In the two cases now before the
3
LSP’s supplemental briefs in combination with its counsels’
statements at oral argument suggest that petitioners “reasonably, but
mistakenly, believed” that their initial filings were adequate to
demonstrate Article III Standing. See Am. Orders, at 1-2 (Feb. 28,
2022) (Rogers, J., not joining); OA Tr. No. 20-1421, at 6, 13, 22-23,
5
court, LSP’s initial submissions were insufficient to establish
standing because they “failed to identify a ‘specific project’”
for which petitioners were prevented from competing. LSP II,
28 F.4th at 1289 (quoting LSP I, 700 F. App’x at *2). Being
“ready, willing, and able” is not the standard under relevant
precedent. This was clear at oral argument when LSP’s
counsel could not identify evidence of its standing in either
case. In No. 20-1421, the court inquired where it could find
evidence that LSP “would have bid on” specific projects that
were “erroneously” categorized. OA Tr. No. 20-1421, at 14.4
Counsel responded citing pages in the record that do not
identify such projects. Id. And when the court asked counsel
where the record stated that LSP “competes on all projects,” he
did not point the court to the information it requested. Id. at
14. Likewise in No. 20-1465, counsel for LSP did not cite
record evidence when asked to identify specific projects for
which his client would compete, OA Tr. No. 20-1465, at 11-12,
and did not assist the court when he was later prompted to
“help” it find standing. Id. at 21-23.
In both cases, however, LSP’s supplemented records
rectify the deficiencies of its initial filings. In No. 20-1421,
71; Supp. Br. Standing, No. 20-1421, at 3, 7, 9 (Mar. 9, 2022); OA
Tr. No. 20-1465, at 11, 20; Supp. Br. Standing, No. 20-1465, at 3-4,
6, 8 (Mar. 9, 2022).
4
Judge Pillard asked counsel “But where can I find a statement such
as a manager declaration or, you know, CEO declaration, saying, we
would have bid on these, these ones that are, that are erroneously
treated as local rather than regional?” OA Tr. No. 20-1421, at 14.
Judge Rogers asked counsel where in the record it stated that his
client “competes on all projects.” Id. at 14. Judge Pillard also asked
counsel “Where did you identify that those were projects that your
clients would bid on?” OA Tr. No. 20-1465, at 11-12.
6
LSP’s President Paul Thessen avers that LSP would have
competed on twelve specific projects identified in the
complaint had the projects been subjected to competition: “I
can state with confidence that had MISO conducted a
competitive solicitation process for Baseline Reliability
Projects providing regional benefits, such as the 12 projects
referenced in the complaint, LS Power Midcontinent would
have submitted proposals and constructed any awarded
projects when and where permitted to do so.” Thessen Aff.,
No. 20-1421, at 8 (Mar. 9, 2022). Additionally, Thessen
averred that LSP would have competed for 113 projects
approved by MISO in 2019 if competition had been available,
and that LSP “would have competed on 2020 and 2021 projects
when and where permitted had any been subject to
competition.” Id. at 4. In No. 20-1465, Thessen’s affidavit
avers “unequivocally yes,” that LSP’s affiliates
“would . . . submit proposals if regionally beneficial economic
projects between 100 kV and 229 kV or Market Efficiency
Projects that are coupled with a Baseline Reliability Project
were available for competition.” Thessen Aff., No. 20-1465,
at 10 (Mar. 9, 2022).
Further, Thessen points to projects at pages 11-13 of LSP’s
Complaint as ones that have been excluded from competition
due to their classification by the Midcontinent System
Operator, Inc. (“MISO”) in the “Other Project Category.” Id.
at 9. Thessen avers “with confidence that had MISO conducted
a competitive solicitation process for some or all the economic
projects that are the subject of the Complaint,” LSP’s affiliates
“would have submitted proposals and constructed any awarded
projects when and where permitted to do so.” Id. at 11.
Thessen’s affidavits thereby suffice under the relevant
precedent to establish LSP’s Article III standing by identifying
specific projects for which LSP would compete, see LSP II, 28
7
F.4th at 1289 (citing LSP I, 700 F. App’x at 2), such that it is
actually or imminently harmed by the challenged orders, see
Clapper, 568 U.S. at 409-10. In both cases, therefore,
Thessen’s declarations establish an imminent harm as a result
of the challenged orders by “distinguish[ing]” LSP from “any
other party who might someday wish to build” a facility. N.Y.
Reg’l Interconnect, Inc. v. FERC, 634 F.3d 581, 587-88 (D.C.
Cir. 2011).
III.
In view of the supplemented record establishing LSP’s
Article III standing under binding precedent, I reach the merits
of the challenges to FERC’s orders. For the reasons stated by
the court in No. 20-1421, slip op. at 19-34 and No. 20-1465,
slip op. at 17-34, I conclude that the petitions for review lack
merit because FERC’s decisions were not arbitrary and
capricious. Rather, while acknowledging flaws in some of
LSP’s arguments on appeal, the court concluded that the
Commission provided reasoned explanations for denying
LSP’s petitions for review. For instance, noting the strength of
LSP’s new evidence to show spillover of Baseline Reliability
Project benefits to zones other than the local zone under the
location cost-based allocation approach, it was a sufficiently
small subset of projects (twelve out of 400) that the
Commission, in light of its experience and expertise and
responses to LSP’s arguments, could reasonably conclude that
setting aside the cost-allocation method for all the projects was
not required. See No. 20-1421, slip op. Part II.B, at 20.
Accordingly, I dissent in part and concur in part.