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 nongovernmental 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 costcausation 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 nonregional, 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 costallocation 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 costcausation 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 MultiValue 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 locationbased 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 socalled “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 MultiValue 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 locationbased 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 MultiValue 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 lineoutage 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 costcausation 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 costcausation 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 costcausation 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 asapplied 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 costallocation 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 costcausation 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 “asapplied” 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 asapplied 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.