Document ID: s3://data.kl3m.ai/documents/govinfo/USCOURTS/USCOURTS-caDC-23-01076/USCOURTS-caDC-23-01076-0/pdf.json

Parties Involved:
Federal Energy Regulatory Commission
Respondent
Tenaska Clear Creek Wind, LLC
Petitioner

Document Text:

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. 

USCA Case #23-1076 Document #2065510 Filed: 07/19/2024 Page 1 of 21
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Matthew J. Binette argued the cause for respondentintervenors. 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 

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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. 

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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 

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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. 

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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 

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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 

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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 

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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. 

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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). 

A.

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 

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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). 

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(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. 

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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). 

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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 

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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 

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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 pretransfer 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, 

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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 

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from two SPP experts, id., and the 2022 Restudy, which 

included only upgrades required to address SPP’s costallocation 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 

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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 

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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. 

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discretion to independent system operators, and to not secondguess 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.

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