United States Court of Appeals FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued April 9, 2024 Decided July 19, 2024
No. 22-1059
TENASKA CLEAR CREEK WIND, LLC, PETITIONER
v.
FEDERAL ENERGY REGULATORY COMMISSION, RESPONDENT
BRIGHT CANYON ENERGY CORPORATION, ET AL., INTERVENORS
Consolidated with 22-1336, 23-1076
On Petitions for Review of Orders of the Federal Energy Regulatory Commission
David A. Super argued the cause for petitioner. With him on the briefs were Tyler S. Johnson and Stephen J. Hug.
Beth G. Pacella, Deputy Solicitor, Federal Energy Regulatory Commission, argued the cause for respondent. With her on the brief were Matthew R. Christiansen, General Counsel, and Robert H. Solomon, Solicitor. Matthew W. Estes, Attorney, entered an appearance. 2 Matthew J. Binette argued the cause for respondent- intervenors. With him on the brief were Marnie A. McCormick, Mark Strain, Peter K. Matt, Jecoliah R. Williams, Elizabeth P. Trinkle, William R. Hollaway, Ph.D., Lucas C. Townsend, and Max E. Schulman.
Before: CHILDS and GARCIA, Circuit Judges, and GINSBURG, Senior Circuit Judge.
Opinion for the Court filed by Circuit Judge CHILDS.
CHILDS, Circuit Judge: Petitioner Tenaska Clear Creek Wind, LLC (“Clear Creek”) wants to generate energy by wind turbine for sale to parts of Missouri, southeast Iowa, and northeast Oklahoma. In these consolidated petitions for review of orders of the Federal Energy Regulatory Commission (“Commission”), Clear Creek maintains that the Commission acted arbitrarily, capriciously, and contrary to precedent when it allowed Southwest Power Pool, Inc. (“SPP”), a regional transmission organization (“RTO”), to assign costs of more than $100 million to Clear Creek to pay for upgrades required on SPP’s system to accommodate the interconnection of Clear Creek’s wind turbine-powered electrical generation project (the “Project”). For the reasons set forth below, the court denies Clear Creek’s petitions for review.
I.
A.
The Federal Power Act of 1920, 16 U.S.C. §§ 791a–828c (the “Act”), vests the Commission with regulatory authority over the “transmission of electric energy in interstate commerce and . . . the sale of electric energy at wholesale in interstate commerce,” id. § 824(b)(1), and requires all rates 3 subject to the Commission’s jurisdiction to “be just and reasonable,” id. § 824d(a). As part of the enforcement of the “just and reasonable” requirement, “section 205 [of the Act] requires that utilities file tariffs reflecting their rates and service terms with the Commission for review.” Green Dev., LLC v. FERC, 77 F.4th 997, 1000 (D.C. Cir. 2023) (citing 16 U.S.C. § 824d(c)). “A negatively affected party may challenge a Commission-approved rate by filing a complaint with the Agency, and it carries the burden of demonstrating that the rate is unjust or unreasonable.” Constellation Mystic Power, LLC v. FERC, 45 F.4th 1028, 1035 (D.C. Cir. 2022).
When a power generator like Clear Creek builds a new facility, it must connect that location to the power grid. Green Dev., 77 F.4th at 1001. To create a new connection to the electric grid, the power generator asks to “interconnect” to the transmission system by submitting an interconnection request to a transmission system operator, at which point the generator is assigned a position in a queue. Standardization of Generator Interconnection Agreements & Procs. (“Order No. 2003”), 104 FERC ¶ 61,103 at P 35 (July 24, 2003). Transmission system operators review the requests in the queue in chronological order, either individually or in clusters. During the review process, the transmission system operator conducts studies to assess the impact of the new energy source on the preexisting electric grid. These studies identify any new facilities and equipment that may be needed to accommodate the new interconnection. In some instances, the interconnection has an impact beyond the local system. When this occurs, an affected system operator will conduct a study to evaluate the impact of the interconnection on its system. Throughout this entire process, a study may be revised or redone if the generator cancels its proposed project, thereby impacting the upgrades required for the other proposed projects in the queue. 4 When completing an interconnection request, power generators are required to choose the level of interconnection service they require. There are two levels for interconnection service that power generators may choose from: Network Resource Interconnection Service (“NRIS”), or “firm” service, and Energy Resource Interconnection Service (“ERIS”), or “non-firm” or “interruptible” service. As we have previously explained,
Electric utilities often distinguish between “firm” service, under which customers can demand power or transmission at any time, and “interruptible” service, which the utility is entitled to shut off at any point when there is not enough excess capacity beyond that required to guarantee the needs of the utility’s firm customers. Interruptible service is typically offered at a significant discount because the utility’s ability simply to cut off service at peak demand periods alleviates its need to plan for and finance additional capacity to offer the service.
Fort Pierce Utils. Auth. v. FERC, 730 F.2d 778, 785–86 (1984).
B.
The Project is a 242-megawatt facility in northwest Missouri and comprises 111 Vestas turbines across approximately 31,000 acres. Prior to beginning operation, Clear Creek sought to connect the Project to the electric grid. It submitted an interconnection request to transmission system operator Associated Electric Cooperative, Inc. (“AECI”), an electric generation and transmission cooperative based in Springfield, Missouri that provides wholesale power to parts of 5 Missouri, southeast Iowa, and northeast Oklahoma. The level of interconnection service Clear Creek requested was NRIS.
While conducting its interconnection study, AECI identified two RTOs,1 SPP and Midcontinent Independent System Operator, Inc. (“MISO”), that could be affected by Clear Creek’s interconnection.2 AECI directed Clear Creek to coordinate affected system studies with SPP and MISO. On August 20, 2018, Clear Creek asked SPP to conduct an affected system study of the interconnection.3 SPP informed Clear Creek that the affected system study should take between four to five weeks to complete.
SPP’s interconnection study procedures are outlined in its Tariff. See SPP, Open Access Transmission Tariff, attach. V (“Tariff”). When an interconnection request is submitted to SPP, SPP assigns an initial queue position and evaluates all valid interconnection requests submitted in the same 180- calendar-day window in a Definitive Interconnection System Impact Study (“DISIS”) cluster. Requests in the same DISIS cluster are evaluated together at equal priority for SPP to determine if upgrades are needed to fulfill the requests. To
1 RTOs “are independent organizations that manage the transmission of electricity over the electric grid and ensure electricity is reliably available for consumers.” Advanced Energy Mgmt. All. v. FERC, 860 F.3d 656, 659 (D.C. Cir. 2017). 2 SPP is a non-profit RTO that provides transmission service in fourteen states: “Arkansas, Iowa, Kansas, Louisiana, Minnesota, Missouri, Montana, Nebraska, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, and Wyoming.” Comm’n’s Br. 9. “MISO is an RTO that serves the central United States.” City of Lincoln v. FERC, 89 F.4th 926, 934 n.10 (D.C. Cir. 2024). 3 MISO determined that no network upgrades were necessary on its transmission system to accommodate the interconnection to the AECI transmission system. 6 perform each study, SPP evaluates the base case and transfer case. The base case shows SPP’s system before any interconnection is done, while the transfer case shows SPP’s system after the interconnection.
If the transfer case indicates constraints and that network upgrades are necessary to alleviate those constraints to accommodate the interconnection of a project or projects, SPP determines the cost allocation of those network upgrades and assigns costs to each interconnection customer that contributed to the need for a specific network upgrade on a pro rata basis.
Order Granting in Part and Denying in Part Complaint, 177 FERC ¶ 61,200 at P 2 (Dec. 16, 2021) (“Complaint Order”) (JA222).
SPP performs the study of each interconnection request on the level of interconnection service the requester asked for from the host system, ERIS or NRIS. After the studies are completed, SPP “assigns responsibility for network upgrades needed to mitigate a constraint based on whether an interconnection request impacts the constraint by at least the applicable [transfer distribution factor (TDF)] threshold and if the transmission facility is overloaded greater than 100% of its line rating.” Order Addressing Arguments Raised on Rehearing and Denying Motion for Stay, 182 FERC ¶ 62,090 at P 9 (Feb. 16, 2023) (“Rehearing Order”) (JA575). The TDF threshold is based on the customer’s request on the host system for ERIS or NRIS service. “If the impact of an interconnection request is below the TDF threshold, then SPP considers the generating facility’s impact de minimis (even if a transmission line is overloaded beyond its line rating) and does not assign 7 network upgrades for that transmission facility to the interconnection customer.” Id.
SPP issued its first affected system impact study regarding Clear Creek on October 5, 2018, identifying $31.2 million in upgrades required on its system using 2017 integrated transmission planning (ITP) models. On November 5, 2018, SPP issued a revised study, which did not make any substantive changes to the results of the first study. Thereafter, SPP issued affected system studies on February 12, 2019 ($16.3 million in upgrades), March 21, 2019 ($33.017 million in upgrades), and April 8, 2019 ($33.535 million in upgrades).
Clear Creek requested NRIS on the AECI transmission system, so SPP conducted the study under both ERIS and NRIS as was their practice for those requests. SPP did not find any NRIS-related network upgrades in their initial study, only upgrades related to ERIS. Believing the system studies were ending, Clear Creek began construction of the Project in the spring of 2019.
On November 1, 2019, SPP notified Clear Creek that SPP was going to restudy the Project using 2019 ITP models because of the withdrawal of several higher-queued projects in the cluster. At this point, Clear Creek had already installed 50 wind turbines and committed $266 million pursuant to their belief the studies were ending. On November 2, 2020, SPP provided the initial results of the restudy, which stated system upgrade costs of $763 million. “The dramatic increase in upgrade costs reflected the assignment of cost responsibility to Tenaska Clear Creek for approximately 20 additional network upgrades.” Compl. at 13–14 (JA036–JA037). On December 18, 2020, SPP provided an updated study lowering the cost of upgrades to $106.8 million. Entering 2021, SPP continued to make adjustments to the upgrade amount, lowering it to $93 8 million on January 9, 2021, then to $91 million on February 26, 2021, and raising it to $99 million on March 25, 2021.
On May 5, 2021, Clear Creek filed a complaint with the Commission to end SPP’s “multi-year affected system study process” and direct it “to respect the results of the initial studies of the Clear Creek Project.” Id. at 1 (JA024), 3 (JA026). Seven months later, the Commission granted in part and denied in part Clear Creek’s complaint, finding that
SPP appropriately applied its authority under the SPP Tariff to restudy the Project after the withdrawal of one or more higher-queued projects; that correcting the omission of 4.5 GW of higher-queued generation was appropriate; and that SPP appropriately used the NRIS standard to evaluate the impacts of the Project on the SPP system.
Complaint Order at P 18 (JA227). The Commission also found that “SPP’s use of the 2019 ITP models in the restudy was unduly discriminatory or preferential,” id., because SPP was “continuing to use the 2017 ITP models for similarly situated customers,” id. at P 62 (JA247). Thus, the Commission required SPP “to restudy the Project using the 2017 ITP models” updated to incorporate “the 4.5 GW of missing generation,” and “to make a compliance filing” after “the completion of the restudy.” Id. at P 18 (JA227). After the Commission denied Clear Creek’s request for rehearing by operation of law, see Notice of Denial of Rehearing by Operation of Law and Providing for Further Consideration, 178 FERC ¶ 62,087 (Feb. 14, 2022) (“Denial Order 1”) (JA309), SPP submitted compliance filings with the results of the restudy in March 2022 (“2022 Restudy”), which stated that 9 necessary upgrades assigned to Clear Creek were reduced to $88 million.
In April 2022, Clear Creek filed an amended complaint with the Commission and then filed its first petition in this court seeking review of the Complaint Order and Denial Order 1. Subsequently, SPP filed an amended restudy reducing network upgrade costs to $79 million on May 13, 2022, and a notice raising costs to $102 million on August 16, 2022.
In September 2022, the Commission issued an Order finding that SPP complied with the Commission’s directive to restudy the Project and that the “assignment of network upgrade costs to the Project pursuant to the 2022 Restudy [wa]s just and reasonable, not unduly discriminatory or preferential, and consistent with the ‘but for’ cost allocation.” Order on Compliance and Addressing Arguments Raised on Rehearing, 180 FERC ¶ 61,160 at P 30 (Sept. 9, 2022) (“Compliance Order”) (JA491). After the Commission denied Clear Creek’s request for rehearing by operation of law, see Notice of Denial of Rehearing by Operation of Law and Providing for Further Consideration, 181 FERC ¶ 62,090 (Nov. 7, 2022) (“Denial Order 2”) (JA569), Clear Creek filed its second petition in this court seeking review of the Compliance Order and Denial Order 2.
Again, in February 2023, the Commission determined that SPP’s assignment of network upgrade costs to Clear Creek was “just and reasonable, not unduly discriminatory or preferential, and consistent with ‘but for’ cost allocation.” Rehearing Order at P 31 (JA584). Clear Creek timely filed a third petition for review of the Compliance Order, Denial Order 2, and the Rehearing Order. 10 II.
The court has jurisdiction to review the Commission’s orders pursuant to § 313(b) of the Act. 16 U.S.C. § 825l(b) (“Any party to a proceeding . . . aggrieved by an order issued by the Commission . . . may obtain a review of such order in the . . . United States Court of Appeals for the District of Columbia” and “[u]pon the filing of such petition such court shall have jurisdiction.”). The court reviews the Commission’s orders under the familiar arbitrary and capricious standard of the Administrative Procedure Act. See Entergy Servs., Inc. v. FERC, 568 F.3d 978, 981 (D.C. Cir. 2009) (citing 5 U.S.C. § 706(2)(A)). The court is empowered “to reverse any agency action that is ‘arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.’” Hoopa Valley Tribe v. FERC, 913 F.3d 1099, 1102 (D.C. Cir. 2019) (citation omitted). However, the court will uphold the Commission’s determination if it “examine[d] the relevant data and articulate[d] a satisfactory explanation for its action including a ‘rational connection between the facts found and the choice made.’” Motor Vehicle Mfrs. Ass’n of U.S. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983) (quoting Burlington Truck Lines, Inc. v. United States, 371 U.S. 156, 168 (1962)). The Commission “must demonstrate that it has made a reasoned decision based upon substantial evidence in the record, and the path of its reasoning must be clear.” Seminole Elec. Coop., Inc. v. FERC, 861 F.3d 230, 234 (D.C. Cir. 2017) (cleaned up).
Before turning to the merits of Clear Creek’s claims, we first address whether we lack subject matter jurisdiction because the appeal is moot. AECI, SPP, and several other companies (collectively “Respondent-Intervenors”) argued 11 that the court should deny Clear Creek’s petitions as moot because: (1) Clear Creek voluntarily downgraded to ERIS and, as a result, no longer must pay the $102 million in current upgrade costs associated with NRIS; and (2) in the event Clear Creek reinstates NRIS, that $102 million upgrade total would be void and the reinstatement would require a new interconnection study which would not necessarily result in the same mix of upgrades and costs.4 At oral argument, the Commission agreed with Respondent-Intervenors that mootness provided another basis for denying the petitions. Clear Creek responds that its petitions are not moot because a favorable decision can reverse harm caused by an unjust Commission policy that allows the use of the more-demanding NRIS standard in affected system studies.
“Article III, Section 2 of the Constitution permits federal courts to adjudicate only ‘actual, ongoing controversies.’” McBryde v. Comm. to Rev. Cir. Council Conduct & Disability Ords. of the Jud. Conf. of the U.S., 264 F.3d 53, 55 (D.C. Cir. 2001) (quoting Honig v. Doe, 484 U.S. 305, 317 (1988)). “If events outrun the controversy such that the court can grant no meaningful relief, the case must be dismissed as moot.” Id.; see also Pub. Utils. Comm’n of the State of Cal. v. FERC, 236 F.3d 708, 714 (D.C. Cir. 2001) (“For that reason, if events occur while a case is pending on appeal that make it impossible for the court to grant any effectual relief whatever to a prevailing party, the appeal must be dismissed as moot.”
4 Respondent-Intervenors also argue that we lack jurisdiction, characterizing Clear Creek’s argument as a time-barred collateral challenge to the Commission’s settled “but for” policy. Intervenors’ Br. 34–35. But Clear Creek’s challenge is not to the “but for” standard generally; instead, Clear Creek challenges a particular result of SPP’s de minimis threshold cost allocation. Accordingly, this poses no obstacle to our exercise of jurisdiction in this appeal. See S. Co. Servs., Inc. v. FERC, 416 F.3d 39, 44 (D.C. Cir. 2005). 12 (cleaned up)). “This requirement applies independently to each form of relief sought.” McBryde, 264 F.3d at 55. The “heavy burden of proving mootness” is with the party asserting a case is moot. Maldonado v. District of Columbia, 61 F.4th 1004, 1006 (D.C. Cir. 2001).
Here, Respondent-Intervenors and the Commission have not shown that the events have outrun the controversy such that we could not grant meaningful relief. First, when Clear Creek downgraded its level of service to ERIS to avoid bankruptcy, it negotiated with AECI a contractual right to re-open the matter of its service level if its present petitions were to prevail. Indeed, our granting of Clear Creek’s petitions would undoubtedly bring it “effectual relief,” because it would allow Clear Creek to obtain NRIS service without taking on the $88 million in upgrade costs assigned to it in SPP’s second restudy. The prospect of such substantial relief therefore demonstrates that Clear Creek’s voluntary downgrade to ERIS service has not mooted this case.
Second, SPP’s assertion that it will do an interconnection restudy if Clear Creek renews its request for NRIS service similarly would not impact this court’s ability to grant effectual relief. SPP’s argument that the upgrade costs of NRIS or ERIS in a restudy will change is not effective. Clear Creek is not only disputing the costs SPP imposed, but additionally is disputing the method used to calculate those costs. Since SPP and the Commission have stated intentions to allocate costs in the same way Clear Creek challenges in this appeal, the issue cannot be moot. Since Respondent-Intervenors and the Commission are unable to meet their burden of proving mootness, we turn to the merits of Clear Creek’s petitions. 13 B.
Clear Creek makes several challenges to the Commission’s orders. None persuade us.
1.
First, Clear Creek argues that the Commission’s orders violate the cost causation principle, thereby allowing SPP to assign upgrade costs for “transmission facilities that were overloaded prior to the interconnection of the Project.” Pet’r’s Br. 19. Clear Creek further complains that the Commission’s orders are inconsistent with cost causation because they cast “Clear Creek as the sole cause and beneficiary of the[] upgrades,” id. 25, when the payments of costs “to remedy preexisting overloads . . . bring[s] disproportionate benefits to others,” id. 30.
The Act incorporates a cost causation principle in its just and reasonable standard. See City of Lincoln v. FERC, 89 F.4th 926, 930 (D.C. Cir. 2024). This 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.” S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 53 (D.C. Cir. 2014) (per curiam). “And undue discrimination occurs when similarly situated entities are charged different rates for no good reason.” Consol. Edison Co. of N.Y., Inc. v. FERC, 45 F.4th 265, 282 (D.C. Cir. 2022). “But nothing requires the Commission to ensure full or perfect cost causation.” S.C. Pub. Serv. Auth., 762 F.3d at 88. “Rather, the cost causation principle requires that ‘all approved rates reflect to some degree the costs actually caused by the customer who must pay them.’” Id. (citation omitted). 14 In response to Clear Creek’s cost causation challenge, the Commission explains why it did not find Clear Creek’s arguments persuasive. First, the Commission cites to “longstanding policy” that “interconnection customers are responsible for network upgrade costs that would not be needed ‘but for’ the interconnection customer’s request to reliably interconnect its generating facility.” Rehearing Order at P 32 (JA584); see also Reform of Generator Interconnection Procs. & Agreements, 166 FERC ¶ 61,137 at P 78 (Feb. 21, 2019) (“[I]t would be inconsistent with the cost causation principle to exempt an interconnection customer from interconnection facility and network upgrade costs that would not be necessary but for that interconnection request.”). Next, the Commission specified that
the network upgrades identified in the 2022 Restudy were necessary for the Project to interconnect to the transmission system. As such, allocating the costs of the network upgrades to [Clear Creek] is consistent with the cost causation principle and the Commission’s policy of assigning network upgrade costs to the interconnection customer who caused the need for the network upgrades. Clearly, it is [Clear Creek] that has caused these costs and, therefore, [Clear Creek] who should bear them.
Rehearing Order at P 32 (JA585). The Commission’s reasoning is simply that the Project caused operational issues for SPP that did not arise prior to its operation, so it is reasonable to assign the costs of mitigation to Clear Creek, the initiator of those costs. It is clear from the record that SPP’s system is functional in the pre-transfer case, even though it is technically “overloaded.” In the pre-transfer case, therefore, the upgrades at issue were not “necessary” to the continued 15 functioning of SPP’s system. Put differently, if SPP were to install no upgrades at all, then nothing would change for those prior customers whose interconnections were deemed de minimis; the current capability of the system would remain sufficient for their needs. It therefore follows that Clear Creek is the “but for” cause (and the chief beneficiary) of the system upgrades for which SPP made it responsible.
Clear Creek argues that two of our recent cases support its position: Consol. Edison, 45 F.4th 265, and Old Dominion Elec. Coop. v. FERC, 898 F.3d 1254 (D.C. Cir. 2018). Reply Br. 15. Neither case does, as the Commission explained. Rehearing Order at PP 34 (JA586–JA587 & n.81), 37 (JA588– JA589). Consolidated Edison involved a de minimis threshold, but one that operated wholly differently from SPP’s here. 45 F.4th at 281–82. And, in contrast to Old Dominion, the upgrades here are not part of the regional transmission plan (base case), nor did the Commission find the upgrades here would provide significant regional benefits. 898 F.3d at 1256– 59. These distinctions demonstrate why neither case indicates that cost causation is violated here and neither prevents the Commission from approving SPP’s de minimis cost allocation methodology. Therefore, because the Commission’s explanation for its findings comports with its precedent and the cost causation principle, the Commission’s decision is based on reasoned decision-making.
2.
Clear Creek next complains that SPP’s allocation of costs is inconsistent with the Commission’s “but for” policy.
Under the “but for” standard, “generation developers are to be allocated the costs for transmission system upgrades that would not have been made but for the interconnection of the 16 developers, minus the cost of any facilities that the [transmission operator]’s regional plan dictates would have been necessary anyway for load growth and reliability purposes.” Midwest Indep. Transmission Sys. Operator, Inc., 129 FERC ¶ 61,019 at P 23 (Oct 9, 2009) (citation omitted).
The Commission’s opposition to this challenge starts with Order No. 2003, wherein the Commission reasoned that “it is appropriate for the Interconnection Customer to pay initially the full cost of . . . Network Upgrades that would not be needed but for the interconnection.” Id. at P 694. The Commission then can resort to its explanation of how “SPP assigns responsibility for network upgrades needed to mitigate a constraint based on whether (1) an interconnection request impacts the transmission facility by at least the applicable TDF threshold; and (2) if the transmission facility is overloaded greater than 100% of its line rating.” Compliance Order at P 98 (JA526). “If the impact of an interconnection request is below the TDF threshold, then SPP considers the generating facility’s impact de minimis (even if a transmission line is overloaded beyond its line rating), and SPP does not assign network upgrades for that transmission facility to the interconnection customer.” Id.
Relying on this method, the Commission reasonably extrapolated that (1) “SPP’s practice of assigning network upgrades when a transmission facility is overloaded in the pre- transfer case prior to the addition of the interconnection request under study is just and reasonable,” id. at P 99 (JA527); (2) “the assignment of costs for the network upgrades to mitigate . . . Overloaded NRIS Facilities to Tenaska is just and reasonable,” id. at P 100; and (3) “the costs of the network upgrades necessary to mitigate constraints on the . . . Overloaded NRIS Facilities are [Clear Creek]’s ‘but for’ costs because such network upgrades are required to interconnect the Project and, 17 absent the Project, those network upgrades would not be required,” id. at P 101.
The Commission also reasonably explained why it found SPP’s methodology just and reasonable. The Commission reasoned that Clear Creek was assigned costs only for overloads that have “significant impacts on the transmission system” and that were not based on upgrades required by regional transmission system planning. Compliance Order at P 103 (JA528). As for SPP setting the NRIS threshold at 3%, the Commission concluded that “[s]ome form of distribution factors to determine cost responsibility for network upgrades is a common practice among public utilities,” id., and that the 3% threshold “cuts both ways,” including for Clear Creek here, id. at P 104 (JA528–JA529); see also Rehearing Order at P 33 (JA585).
In response to Clear Creek’s argument that the Commission failed to distinguish its “but for” precedent in Jeffers South, LLC v. Midwest Indep. Transmission Sys. Operator, Inc., 139 FERC ¶ 63,002 (2012), order on initial decision, 144 FERC ¶ 61,033 (2013), order on reh’g, 153 FERC ¶ 61,190 (2015), and Midwest Indep. Transmission Sys. Operator, Inc., 122 FERC ¶ 61,113 (2008), the Commission explained that those decisions identify violations of the “but for” principle on the basis that the interconnection customer was being assigned upgrades intended in part to resolve regional transmission needs, i.e., needs not related to that customer’s interconnection. Rehearing Order at P 39 (JA591); Compliance Order at PP 42–44 (JA498–JA500 & n.70), 103 (JA528). Substantial evidence supports the Commission’s determination here that the disputed upgrades were not intended to address regional transmission planning (base case), as opposed to interconnection, needs. Rehearing Order at PP 38–40 (JA589–JA592 & nn.102–104). Citing to affidavits 18 from two SPP experts, id., and the 2022 Restudy, which included only upgrades required to address SPP’s cost- allocation criteria, the Commission reasoned that this “definitionally excludes costs of transmission constraints existing in the base case model,” id. at P 38 (JA590). Clear Creek’s argument, Pet’r’s Br. 50–51, that SPP should nonetheless have identified these upgrades in its regional planning process and violated North American Electric Reliability Corporation standards by failing to do so does not change that analysis because Clear Creek did not offer any evidence of such a violation, Rehearing Order at P 40 (JA591– JA592), and SPP’s expert affidavit indicated the contrary, id.
Accordingly, the Commission concluded that SPP’s methodology comports with the “but for” principle and that determination is consistent with reasoned decision-making.
3.
Finally, Clear Creek contends that the Commission failed to address the fact that SPP’s interconnection study and cost allocation practices used NRIS when “Clear Creek is neither taking service on the SPP system nor seeking deliverability on the SPP system.” Pet’r’s Br. 53. Clear Creek further asserts that the Commission’s failure has allowed SPP to artificially inflate upgrade costs and foist them “onto a generator outside SPP’s system and where those upgrades will provide substantial benefits to SPP by addressing well documented issues in a heavily congested region within SPP’s grid.” Id. 53–54.
As to this challenge, the Commission reasonably explains why Clear Creek cannot meet its burden of demonstrating that SPP’s use of NRIS in its interconnection study is unjust, unreasonable, unduly discriminatory, or preferential. First, the 19 Commission identified precedent finding that it is just and reasonable for SPP to use NRIS modeling criteria for a NRIS interconnection request arising from a neighboring transmission system. See Midcontinent Indep. Sys. Operator, Inc., 171 FERC ¶ 61,275 at P 59 (June 30, 2020). That order explained why SPP’s use of NRIS standards in its affected system study was not unjust or unreasonable, id. at PP 59–60, and Clear Creek provides no substantive response to that reasoning in this appeal.
Next, the Commission expertly pointed out how Clear Creek’s own conduct—specifically its request for NRIS on AECI’s system and acknowledgement that the Project’s energy output flows onto SPP’s transmission system—supports SPP’s stated justification for conducting its interconnection study at the NRIS level if that is the level of interconnection service requested:
Interconnection customers requesting NRIS expect the interconnected transmission system to be capable of providing that level of service whether the wires are in SPP or the neighboring transmission system. To study all neighboring system NRIS requests using ERIS thresholds would expose SPP’s members to negative impacts, could undermine reliability, and result in inappropriate and discriminatory cost allocation to SPP Interconnection Customers who have requested a comparable level of service. If SPP were to evaluate neighboring NRIS interconnection requests using ERIS standards and thresholds, the studies could understate their impact because doing so would not take into account the impacts of the higher level of service being requested. This could 20 disadvantage other Interconnection Customers or other Transmission System users in SPP and result in the inappropriate allocation of costs to other customers or users rather than to the appropriate Interconnection Customer.
Answer, Kelley Aff. ¶ 11 (JA169–JA170). Because SPP’s focus is on how to avoid undermining reliability, the Commission’s support for SPP’s NRIS standard is supported by substantial evidence and is consistent with reasoned decision-making.5 Cf. Big Sandy Peaker Plant, LLC v. PJM Interconnection, LLC, 154 FERC ¶ 61,216 at P 50 (Mar. 17, 2016) (“The Commission has recognized that it may be appropriate to provide operational and reliability-related
5 About six months after issuing its rehearing order in this case, the Commission issued a final rule that substantially revised its pro forma interconnection request procedures in 18 C.F.R. Part 35. The new procedures specify, among other things, that a transmission provider should not use the NRIS level of service when it studies an “affected system” interconnection request. See Order No. 2023, Improvements to Generator Interconnection Procs. & Agreements, 184 FERC ¶ 61,054 at P 1277 (July 28, 2023). Clear Creek asserts this new rule demonstrates the error in the Commission’s decision to allow SPP to study its affected system request under the NRIS standard. Clear Creek is mistaken. We have repeatedly held “[a]n agency’s decision is not arbitrary and capricious merely because it is not followed in a later adjudication.” Xcel Energy Servs. Inc. v. FERC, 41 F.4th 548, 560 n.2 (D.C. Cir. 2022); Brooklyn Union Gas Co. v. FERC, 409 F.3d 404, 406 (D.C. Cir. 2005); MacLeod v. ICC, 54 F.3d 888, 892 (D.C. Cir. 1995). For similar reasons, an agency’s adoption of a new rule does not retroactively invalidate a prior adjudication that followed the prior rule. Altamont Gas Transmission Co. v. FERC, 965 F.2d 1098, 1102 (D.C. Cir. 1992) (“[A] later change . . . cannot retroactively invalidate a decision that was sound when made.”). Thus, the Commission’s new rule casts no doubt upon the reasonableness of its decision in this matter. 21 discretion to independent system operators, and to not second- guess their decisions in that regard.”).
***** For the foregoing reasons, Clear Creek fails to demonstrate that the Commission’s decision regarding the assignment of costs to Clear Creek was arbitrary, capricious, or contrary to precedent. We therefore deny Clear Creek’s consolidated petitions.
So ordered.