Coalition of MISO Transmission v. FERC

45 F.4th 1004

• Court: Court of Appeals for the D.C. Circuit
• Decided: August 19, 2022
• Docket: 20-1421
• Status: Published

Opinion

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

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

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

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

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).

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

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.

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

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.”).

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.

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.

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.