United States Court of Appeals FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued January 14, 2020 Decided April 10, 2020
No. 19-1074
GULF SOUTH PIPELINE COMPANY, LP, PETITIONER
v.
FEDERAL ENERGY REGULATORY COMMISSION, RESPONDENT
On Petition for Review of Orders of the Federal Energy Regulatory Commission
Michael E. McMahon argued the cause for petitioner. With him on the briefs were A. Gregory Junge, Sean Marotta, and Matthew J. Higgins.
Beth G. Pacella, Deputy Solicitor, Federal Energy Regulatory Commission, argued the cause for respondent. With her on the brief were Robert H. Solomon, Solicitor, and Carol J. Banta, Senior Attorney. Robert M. Kennedy Jr., Attorney, entered an appearance.
Before: HENDERSON and RAO, Circuit Judges, and RANDOLPH, Senior Circuit Judge.
Opinion for the Court filed by Circuit Judge RAO. 2
RAO, Circuit Judge: Gulf South Pipeline Company filed an application with the Federal Energy Regulatory Commission (“FERC”) in order to build an expansion to its existing pipeline network. Because the expansion facilities will be dramatically more expensive to construct than the surrounding facilities were, Gulf South requested “incremental-plus rates”—also called “additive rates”—under which all natural gas shippers who use the new facilities will be charged a higher rate reflecting the cost of construction. FERC denied the proposed shipping rates. Instead, FERC effectively approved two separate rates for using the expansion facilities. Only Entergy Louisiana, a new shipper that entered into a long-term contract primarily to use the expansion facilities, will pay a higher rate reflecting the cost of the expansion. Gulf South’s existing shippers will pay a fraction of this cost to use the new facilities.
We hold that FERC’s rejection of incremental-plus rates was arbitrary and capricious. Under FERC’s order, materially identical shippers will pay dramatically different rates for the use of the same facilities. FERC failed to justify that disparity, and its decision violated fundamental ratemaking principles— namely, that rates should generally reflect the burdens imposed and benefits drawn by a given shipper. We therefore vacate the part of FERC’s order denying incremental-plus rates and remand for further proceedings consistent with this opinion. We deny Gulf South’s petition for review in all other respects, including the company’s objections related to its initial rate of return and depreciation rate.
I.
Gulf South operates an extensive network of natural gas pipelines in the southeastern United States. This case is about an application filed by Gulf South under Section 7 of the 3
Natural Gas Act, 15 U.S.C. § 717f, which governs the construction or expansion of pipeline facilities. To build an expansion, a company must first receive a “certificate of public convenience and necessity issued by the Commission.” Id. § 717f(c). FERC will grant such a certificate only if it finds the project “is or will be required by the present or future public convenience and necessity.” Id. § 717f(e). FERC may “attach to the issuance of the certificate and to the exercise of the rights granted thereunder such reasonable terms and conditions as the public convenience and necessity may require.” Id. FERC also reviews initial shipping rates proposed by pipeline companies for new facilities in Section 7 proceedings, but the Commission’s orders are meant only “to hold the line” pending more extensive ratemaking proceedings under Section 4 of the Natural Gas Act. Atl. Ref. Co. v. Pub. Serv. Comm’n of State of N.Y., 360 U.S. 378, 391–92 (1959); see also 15 U.S.C. § 717c.
In the Section 7 filing at issue, Gulf South proposed an expansion within its existing Lake Charles Zone in Louisiana. The Westlake Expansion Project will consist of a compressor station, 0.3 miles of pipeline, and a handful of other facilities, all of which will serve a new power plant owned and operated by Entergy Louisiana. Gas cannot be delivered to the new power plant unless a shipper uses the new compressor station, which in turn will be used only if a shipper is delivering gas to the plant. To deliver gas to Entergy’s power plant, a shipper must also use existing Lake Charles facilities—namely, several miles of an existing pipeline known as the Index 198-3 loop. However, after natural gas passes through the new compressor station, it “will, due to pressure differentials, be physically isolated from the rest of the Lake Charles Zone.” Request for Rehearing of Gulf South Pipeline Co., LP, at 6 (June 18, 2019) (“Rehearing Request”). 4
Entergy, which both operates the new power plant and ships natural gas, entered a precedent agreement with Gulf South—i.e., a long-term contract—agreeing to purchase the entire shipment capacity of the expansion facilities for 20 years. Despite that agreement, Gulf South claims existing shippers in the Lake Charles Zone will at times be able to secure access to the expansion facilities and deliver gas to Entergy’s power plant on what is known as a “secondary-firm” basis. Gulf South Br. 7–11. FERC does not dispute that this could occur on at least some occasions. See, e.g., Gulf South Pipeline Co., LP, 166 FERC ¶ 61,089, ¶ 24 (Feb. 1, 2019) (“Rehearing Order”) (noting that existing shippers will have “limited” access). 1
FERC approved Gulf South’s application to construct the expansion facilities but denied three of the company’s requested rates. See Gulf South Pipeline Co., LP, 163 FERC ¶ 61,124 (May 17, 2018) (“Certificate Order”). First, FERC rejected Gulf South’s proposed incremental-plus rates. Under 1 More specifically, Gulf South claims that existing shippers will occasionally be able to “bump” Entergy by taking advantage of FERC’s open-access policy and priority rules. See Transwestern Pipeline Co., 99 FERC ¶ 61,356, ¶ 11–12 (June 27, 2002) (holding that a secondary-firm shipper’s deliveries have priority over primary- firm shippers like Entergy if the latter fails to schedule a delivery early enough). Of course, the expansion facilities will be used exclusively to deliver gas to Entergy’s power plant, so it is not clear why or when secondary-firm shippers would bump Entergy in order to sell to Entergy. See Oral Argument at 8:48–9:45 (discussion in which Gulf South suggested that Entergy might be forced to buy gas from secondary-firm shippers who secure capacity through FERC’s priority rules). In any event, all parties agree that on some occasions shippers other than Entergy might obtain access to the facilities on a secondary-firm basis, so we assume for the purposes of this appeal that it can occur. 5
Gulf South’s proposal, all shippers using the expansion facilities would pay “both the Lake Charles Zone Rates and the Westlake Expansion Rates.” Id. at ¶ 16. In other words, all shippers would pay their normal rates for use of the Lake Charles Zone facilities, but any shipper who uses the expansion facilities would pay an additional rate reflecting the cost of construction. FERC rejected this proposal in favor of a scheme in which only the expansion shipper—i.e., Entergy—would pay an incremental rate, while the zone’s existing shippers would pay only their normal Lake Charles Zone rates, even when they use the expansion facilities. Id. at ¶¶ 21–22. Because the expansion facilities will be far more expensive to construct than the existing facilities, the rate disparity is significant. Entergy will pay more than four times more than other shippers—a rate of $0.1325 per dekatherm of natural gas, while existing shippers who use the expansion facilities will pay a rate of $0.03 per dekatherm. Rehearing Order at ¶ 20.
Next, FERC rejected Gulf South’s requested depreciation rate of 2.86 percent, which is based on an estimated 35 year useful life for the new power plant. Certificate Order at ¶ 19. FERC rejected that proposal in favor of a 1.32 percent rate— the same depreciation rate set for the existing Lake Charles Zone. Id. at ¶ 23. Finally, FERC rejected Gulf South’s proposed initial rate of return. Gulf South had argued that FERC should incorporate recent changes to the company’s capital structure, which would allegedly result in an initial rate of return of 10.81 percent. Id. at ¶¶ 17–18. FERC rejected that proposal, reasoning that Gulf South must continue to use its last approved rate of return. Id. at ¶ 24. FERC set these three initial rates under Section 7; however, Gulf South may request recalculation of these rates when it next files an application under Section 4 of the Natural Gas Act, 15 U.S.C. § 717c, at which point FERC will hold a full evidentiary hearing. 6
Gulf South filed a request for rehearing, which the Commission denied with respect to all three rates. See Rehearing Order at ¶¶ 11–30. Gulf South then filed a petition for judicial review, claiming that FERC’s rejection of these rate proposals was arbitrary and capricious under the Administrative Procedure Act (“APA”). See 5 U.S.C. § 706(2)(A). We have jurisdiction under the Natural Gas Act’s judicial review provision. See 15 U.S.C. § 717r(b).
II.
For the reasons discussed below, we conclude that FERC failed to reasonably explain its denial of incremental-plus rates. FERC’s precedent suggests that incremental-plus rates are appropriate when it is possible to track which shippers are using expansion facilities, thus ensuring that a pipeline company will not over recover its construction costs. FERC denied incremental-plus rates here even though Gulf South will indisputably be able to track which shippers use the expansion facilities. FERC’s sole rationale for doing so was that the expansion facilities and existing facilities will be operated as a single integrated system, but the Commission failed to explain why that fact supported the denial of incremental-plus rates. We therefore vacate the Commission’s order in part. However, we uphold FERC’s denial of Gulf South’s proposed initial rate of return and depreciation rate. In Section 7 proceedings governing a project’s initial approval, FERC’s general policy is to adopt a company’s last approved initial rate of return and last approved depreciation rate until a full hearing can be held in the company’s next Section 4 rate case. Gulf South does not challenge that policy as a general matter, and it has not shown that a departure was warranted in this case. 7
A.
FERC rejected Gulf South’s proposed incremental-plus rates under its general policy of disallowing such rates in “integrated” systems—that is, in systems where the old and new facilities are operated as a single system. Gulf South challenges FERC’s integration finding and also argues in the alternative that FERC should have approved incremental-plus rates regardless of whether the integration finding was correct. Although we determine that the record includes substantial evidence supporting FERC’s factual finding regarding integration, we hold that FERC did not adequately explain why this finding justified rejecting incremental-plus rates.
FERC developed the concept of “integration” to guide its discretion in setting rates for pipeline systems, but it is not a statutory term. See Battle Creek Gas Co. v. Fed. Power Comm’n, 281 F.2d 42, 46 (D.C. Cir. 1960) (explaining that “the Commission has … a general preference for [considering integration] whenever it may equitably be” done because there are “apparent advantages” to “recogniz[ing] that a gas pipeline … is not just a collection of discrete pieces and parts, but an integrated system serving all of its customers”). Whether facilities are integrated is a question of fact we review under the Natural Gas Act’s substantial evidence standard. See Chippewa & Flambeau Imp. Co. v. FERC, 325 F.3d 353, 360 (D.C. Cir. 2003); Fla. Mun. Power Agency v. FERC, 315 F.3d 362, 367 (D.C. Cir. 2003). “The finding of the Commission as to the facts, if supported by substantial evidence, shall be conclusive.” 15 U.S.C. § 717r(b). The standard “requires more than a scintilla, but can be satisfied by something less than a preponderance of the evidence.” Minisink Residents for Envtl. Pres. & Safety v. FERC, 762 F.3d 97, 108 (D.C. Cir. 2014) (citation and quotation marks omitted). 8
Facilities are integrated when “the pipeline operate[s] the new facilities and the old facilities as a single system.” Tenn. Gas Pipeline Co., 80 FERC ¶ 61,070, 61,209 (July 18, 1997). “Put another way, an expansion facility is integrated when existing facilities effectuate service on the expansion facility, or vice versa.” Equitrans, LP, 155 FERC ¶ 61,194, ¶ 10 (May 20, 2016). “Conversely, an expansion facility is not integrated when it is operationally isolated and does not rely on existing facilities to effectuate service.” Id. at ¶ 10 n.19 (citing Colo. Interstate Gas Co., 122 FERC ¶ 61,256, ¶ 60 (Mar. 21, 2008)). FERC has said that integration “is commonly illustrated by: (1) an inability to know whether old or new [shippers] are using either old or new facilities at any particular time; and (2) the ability of either the old or new customers to take service from either set of facilities if either set of facilities breaks down.” Tenn. Gas Pipeline, 80 FERC ¶ 61,070 at 61,209; see also Battle Creek, 281 F.2d at 47 (describing an integrated system as one where the “new gas is to be commingled with the old gas, and both are to be distributed together to all customers”). That said, FERC has explained that while those two characteristics are illustrative, the “test for integration is broader” and focuses more generally on whether the old and new facilities are operated as a single system. Equitrans, 155 FERC ¶ 61,194 at ¶ 10.
Gulf South argues that the system will not be integrated because the company is able to determine who is using the expansion facilities and because old and new shippers cannot take service from either set of facilities if one breaks down— the two features that “commonly illustrate[ ]” integration. Tenn. Gas Pipeline, 80 FERC ¶ 61,070 at 61,209. While this system does not share those characteristics, there was enough evidence “under our deferential standard of review,” Fla. Mun. Power, 315 F.3d at 367, for FERC to find that the facilities will 9
be integrated. There is no dispute that gas delivered to Entergy’s new power plant will travel almost entirely through existing pipelines. It is also undisputed that the new facilities will be segmented by existing facilities. That is, natural gas will flow back into existing facilities after it passes through the new compressor station, even if it is kept physically isolated due to pressure differentials.
FERC has repeatedly emphasized in prior cases that integration depends largely on whether the new facilities will rely on the old facilities to effectuate service. See, e.g., Colo. Interstate, 122 FERC ¶ 61,256 at ¶ 61 (finding that facilities were not integrated because the “system will not use any existing pipeline segment on [the existing] mainline system and there are no interconnections between the facilities that would allow gas to flow from one system to another” and “the existing compression facilities on [the existing] mainline system [will not] be used to effectuate [the expansion project’s] receipts and deliveries”); Equitrans, 155 FERC ¶ 61,194 at ¶ 12 (finding that facilities were integrated because “expansion service is made possible by the existing system”). The Commission’s factual conclusion regarding integration was consistent with its precedents in emphasizing that existing facilities will be used to effectuate service. We should hesitate to displace agency expertise on complex factual questions, and substantial evidence supports FERC’s integration finding here.
That factual finding does not, however, end the matter. Our review turns on whether FERC’s order was reasonable, and the agency cannot use the term “integration” as a placeholder for reasoned decisionmaking. We will uphold FERC’s order only if it “articulate[d] … a rational connection between the facts found and the choice made.” FERC v. Elec. Power Supply Ass’n, 136 S. Ct. 760, 782 (2016). FERC has 10
failed to articulate that connection here. Most importantly, the usual justifications for denying incremental-plus rates in integrated systems do not apply in this case. In its rehearing order, FERC offered this explanation for its general policy:
The Commission allows incremental plus pricing for service utilizing non-integrated facilities because for such facilities, the Commission can distinguish which customers are using the new facilities and which customers are using the existing facilities, making it possible to ensure that a company is not over-recovering its actual costs. For integrated expansions, where it is unclear which customers are using the new or old facilities, the Commission has found the appropriate means for preventing the over- recovery of costs is to authorize pipelines to charge only an incremental rate to customers subscribing the expansion service.
Rehearing Order at ¶ 8. That justification has no bearing in this case. No one disputes that FERC can easily distinguish which customers are using the new facilities and which are using the old. The compressor station will be used by every shipper delivering gas to Entergy’s power plant—and only those shippers. As a result, there is no risk that incremental-plus rates will impact existing customers’ service. To the contrary, existing customers will be charged a higher rate only if they choose to use the new facilities to ship gas to the new power plant. No shippers will be charged more for their existing services, and FERC has failed to explain why there is a risk that Gulf South will over recover its costs for the expansion.
In addition, Gulf South argues that FERC’s conclusion was inconsistent with fundamental principles of cost causation, 11
which hold that rates should reflect “the burdens imposed or the benefits drawn by” a given shipper. BNP Paribas Energy Trading GP v. FERC, 743 F.3d 264, 267 (D.C. Cir. 2014). We agree FERC’s order was inconsistent with those principles. As a general rule, the Commission “may not single out a party for the full cost of a project, or even most of it, when the benefits of the project are diffuse.” Id. at 268. Instead, “[p]roperly designed rates should produce revenues from each class of customers which match, as closely as practicable, the costs to serve each class or individual customer.” Ala. Elec. Co-op., Inc. v. FERC, 684 F.2d 20, 27 (D.C. Cir. 1982). While “the Commission may rationally emphasize other, competing policies and approve measures that do not best match cost responsibility and causation,” Carnegie Nat. Gas Co. v. FERC, 968 F.2d 1291, 1294 (D.C. Cir. 1992), cost-causation principles are the default, and “we have approved the Commission’s departure from traditional cost-causation principles in only limited circumstances,” United Distrib. Cos. v. FERC, 88 F.3d 1105, 1186 (D.C. Cir. 1996). Here, the rates set by FERC do not reflect the benefits drawn by a given shipper. When Entergy uses the expansion facilities, it will pay a rate of $0.1325 per dekatherm. When existing shippers use the same facilities, they will pay their existing Lake Charles rate of $0.03 per dekatherm.
FERC has offered three responses to Gulf South’s cost causation argument. While FERC is permitted to depart from strict cost causation to further competing policies, see Carnegie Nat. Gas, 968 F.2d at 1293–94, none of the three responses provides a rational justification for the rate disparity in this case. First, FERC concluded in its rehearing order that a departure from cost-causation principles is appropriate to “reflect[ ] the fact that [existing] shippers are paying for the underlying facilities under which the pipeline is providing 12
service, such as Gulf South’s existing Index 198-3.” Rehearing Order at ¶ 19. Similarly, FERC notes that Entergy will be able to ship gas to other delivery points in the Lake Charles Zone without paying an added fee. Id. at ¶ 22. Neither fact justifies a departure from cost-causation principles. While it is true that existing shippers are already paying for the existing facilities, those facilities cost a fraction of the price of the expansion. The expansion facilities will cost $56.2 million to build, while the net cost of the existing Lake Charles Zone facilities was only $6.3 million. Id. at ¶ 13. To say that existing shippers should enjoy access to the more expensive expansion facilities because they are already paying for the less expensive existing facilities is not a justification for departing from cost causation. Instead, it is a simple admission that FERC’s order is a departure from cost causation. FERC’s assurance that Entergy will be able to ship gas to other delivery points in the Lake Charles Zone without paying an added reservation rate is unavailing for the same reason: Those facilities were a fraction of the cost of the Westlake Expansion, so Entergy’s open access to the rest of the Lake Charles Zone does not cure the disparity in rates charged for use of the expansion facilities.
Second, FERC noted that it has a “longstanding policy … that shippers should have access to secondary receipt and delivery points in the zone for which they pay a reservation charge.” Id. at ¶ 22. This policy gives shippers more “flexibility in receipt and delivery points.” Id. Yet Gulf South does not challenge FERC’s policy of allowing secondary-firm shippers to access expansion facilities. The question is how much those shippers should pay if they do so. FERC failed to explain why shippers who take advantage of FERC’s open-access policy should pay a rate that bears no relation to the cost of the facilities they use. 13
Third, FERC concluded that incremental-plus rates are inappropriate because expansion shippers like Entergy “must pay for the cost of the new capacity constructed for their needs.” Id. at ¶ 19. “To the extent that the pipeline has unsubscribed capacity …, then it must make a business decision as to whether to move forward with the project. However, an existing shipper’s ability to access the incremental capacity at a lower rate on a secondary basis in no way hinders the pipeline’s ability to recover its costs.” Id. Again, this explanation does not explain the departure from cost-causation principles. This is not a case where, in FERC’s words, “the pipeline has unsubscribed capacity,” id., thus creating a risk that existing customers will be saddled with the costs of construction. In those circumstances, it may be rational for FERC to hold that only expansion shippers should pay higher rates, forcing the company to “make a business decision as to whether to move forward” despite the risk. Id. Here, Gulf South has already entered into a precedent agreement accounting for all of the facilities’ capacity for 20 years, cf. Myersville Citizens for a Rural Cmty., Inc. v. FERC, 783 F.3d 1301, 1311 (D.C. Cir. 2015) (noting that FERC’s policy is “to not look behind precedent or service agreements” to evaluate market need), and FERC has emphasized that as a practical matter secondary-firm shippers will have only “limited” access to the facilities, Rehearing Order ¶ at 24. For our purposes, the question is not whether existing shippers ought to be burdened with the costs of construction if Entergy fails to support the project. Rather, the question is how much secondary-firm shippers should pay if they voluntarily access the new facilities. Again, FERC has not adequately explained why existing shippers should pay rates that do not reflect the price of the facilities they choose to use. 14
FERC’s justifications are further belied by the fact that the Commission consistently allows incremental-plus rates whenever it is possible to readily discern which shippers are using expansion facilities. Indeed, FERC has not identified a single case where it has denied incremental-plus rates in those circumstances. Most notably, whenever a company builds a lateral pipeline, FERC will allow incremental-plus rates because it can track which facilities shippers are using. Rehearing Order at ¶ 8 (“The Commission allows incremental plus pricing for service utilizing non-integrated facilities because for such facilities, the Commission can distinguish which customers are using the new facilities and which customers are using the existing facilities.”). When it comes to laterals, it does not matter to FERC that existing shippers already pay for the zone’s existing facilities, nor that FERC has an open-access policy, nor that pipeline companies must make business decisions about whether to build a facility without shifting costs to secondary-firm shippers. Despite those considerations, FERC allows incremental-plus rates because it is possible to track the facilities’ use. FERC has not identified any reason to treat laterals differently from Gulf South’s proposed expansion.
Indeed, even in integrated systems, FERC has been willing to allow incremental-plus rates when it is possible to track which shippers are using which facilities—particularly if doing so would prevent different shippers from paying an unfair cost differential. In Texas Eastern Transmission, LP, a pipeline company proposed to build various new facilities, including several new pipeline segments. 139 FERC ¶ 61,138, ¶ 7 (May 21, 2012). FERC concluded that the expansion would be integrated with existing facilities, id. at ¶ 32, but the Commission was nonetheless concerned that the zone’s existing rates would “not reflect the significant costs associated 15
with the construction of the project,” id. at ¶ 33. The expansion rate would have been “over 200 percent greater than the existing system” rate, which FERC concluded “would not be appropriate.” Id. The Commission therefore allowed Texas Eastern to “accomplish its rate objectives in an acceptable manner by creating a new rate zone with separate maximum recourse rates” for one of the expansion’s components. Id.
While Gulf South’s primary argument is that FERC should allow incremental-plus rates within the Lake Charles Zone, the company has argued in the alternative that FERC should allow the company to charge the same rates by creating a new rate zone including only the expansion facilities, as FERC did in Texas Eastern. FERC claims that Texas Eastern is inapposite because the “extension was easily distinguishable from the rest of Texas Eastern’s mainline system. Thus, existing shippers would only pay the additional cost of the new rate zone if they elected to transport gas to the new delivery point.” Rehearing Order at ¶ 15. Yet that is equally true for Gulf South: The company can discern which shippers use the expansion facilities and which do not, so existing shippers will, as in Texas Eastern, “only pay the additional cost of the new rate zone if they elect[ ] to transport gas to the new delivery point.” Id.
In the rehearing order, FERC also briefly suggested that it has a policy of allowing new rate zones only “when th[e] extension is in a distinct operational and geographical area.” Id. at ¶ 16. Yet FERC concluded its discussion in the next sentence without any explanation of why geographic separation is dispositive. Nor do any of the administrative cases cited by the Commission explain why geographically distinct facilities should be treated differently. Rehearing Order at ¶ 16 n.42. We have no basis to review FERC’s policy because the 16
Commission has said nothing about what the policy means or why it is justified. See Columbia Gas Transmission Corp. v. FERC, 448 F.3d 382, 387 (D.C. Cir. 2006) (“It will not do for a court to be compelled to guess at the theory underlying the agency’s action; nor can a court be expected to chisel that which must be precise from what the agency has left vague and indecisive.”) (quoting SEC v. Chenery Corp., 332 U.S. 194, 196–97 (1947)). Similarly, FERC did not explain why Texas Eastern’s expansion was geographically distinct but Gulf South’s is not. Both expansions consist of a variety of new components attached to or built near existing facilities. The only apparent distinction is that Texas Eastern’s expansion included a 15.2 mile pipeline segment that was significantly longer than the pipeline connecting Entergy’s power plant and the Index 198-3 loop. See Texas Eastern, 139 FERC ¶ 61,138 at ¶ 7. Again, this court cannot evaluate FERC’s conclusion without further explanation from the agency.
If there is a rational explanation for why Texas Eastern and Gulf South should be treated differently, FERC has failed to articulate it. Both companies proposed to build expansions that (1) were integrated; (2) were operationally distinct in such a way that would allow the pipeline to avoid burdening existing shippers with the costs of construction; and (3) were dramatically more expensive than the pipeline’s existing facilities. Indeed, the rate disparity in this case (442 percent) is far higher than in Texas Eastern. Absent reasonable grounds to distinguish the two, FERC should have offered Gulf South the same opportunity to charge incremental-plus rates—whether through the creation of a new rate zone or as an additional rate within the existing Lake Charles Zone. See ANR Storage Co. v. FERC, 904 F.3d 1020, 1025 (D.C. Cir. 2018) (emphasizing “FERC’s statutory duty … to provide some reasonable justification for any adverse treatment relative to similarly 17
situated competitors”); W. Deptford Energy, LLC v. FERC, 766 F.3d 10, 20 (D.C. Cir. 2014) (“It is textbook administrative law that an agency must provide a reasoned explanation for departing from precedent or treating similar situations differently.”) (quotation marks and alterations omitted). 2
2 According to FERC, Gulf South failed to exhaust the argument that its desired rates could be achieved through a new rate zone. We disagree. The Natural Gas Act provides that “[n]o objection to the order of the Commission shall be considered by the court unless such objection shall have been urged before the Commission in the application for rehearing unless there is reasonable ground for failure so to do.” 15 U.S.C. § 717r(b). Here, Gulf South indisputably raised the question of a new rate zone in its rehearing application, thus satisfying the statute’s exhaustion requirement. See Rehearing Request at 18 (“[T]he Commission should allow Gulf South the opportunity to create a new rate zone for the expansion facilities, consistent with Texas Eastern.”).
Nonetheless, FERC argues that if a party raises an argument for the first time in its rehearing request (rather than in the initial application) and FERC rejects it, then the party must raise the argument again in a second rehearing application. Nothing in the Natural Gas Act nor our case law requires that a party file two duplicative rehearing applications. In arguing otherwise, FERC mistakenly relies on four cases addressing an unrelated issue. Those cases hold that if FERC modifies its order on rehearing, a party generally must raise any new complaints in a subsequent rehearing application, rather than raise them for the first time in court. See Columbia Gas Transmission Corp. v. FERC, 477 F.3d 739, 741–42 (D.C. Cir. 2007); Canadian Ass’n of Petroleum Producers v. FERC, 254 F.3d 289, 296–97 (D.C. Cir. 2001); Town of Norwood, Mass. v. FERC, 906 F.2d 772, 774–75 (D.C. Cir. 1990); Tenn. Gas Pipeline Co. v. FERC, 871 F.2d 1099, 1109–10 (D.C. Cir. 1989). FERC’s rehearing order did not raise a new source of complaint, and Gulf South raised its new-rate-zone argument for the first time before the 18
Because FERC did not adequately explain its action, we hold that the rejection of Gulf South’s proposed incremental- plus rates was arbitrary and capricious. See 5 U.S.C. § 706(2)(A). While Congress has conferred substantial discretion on FERC in the context of rate setting, our review under the APA requires the agency to offer reasonable explanations for the rates it sets. “If we are to hold that a given rate is reasonable just because the Commission has said it was reasonable, review becomes a costly, time-consuming pageant of no practical value to anyone.” Fed. Power Comm’n v. Hope, 320 U.S. 591, 645 (1944) (Jackson, J., dissenting). Here, FERC set rates that would require shippers to pay amounts vastly disproportionate to the value of the benefits they draw, and FERC failed to show why such rates were reasonable. We therefore vacate the part of FERC’s order rejecting Gulf South’s proposed incremental-plus rates and remand for further proceedings. On remand, FERC must also address the possibility of a new rate zone, as it did in Texas Eastern in materially similar circumstances. 3
Commission, not in court. FERC was “adequately apprised of” the objection, Tenn. Gas, 871 F.2d at 1110, and we may consider it on appeal. 3 In addition to the problems discussed above, Gulf South argues that FERC failed to respond to the possibility that shippers will game the system by reserving capacity in the Lake Charles Zone solely to take advantage of the pricing disparity. Yet FERC reasonably concluded that such gamesmanship would be an unlikely and risky endeavor given that Entergy has already contracted for 100 percent of the facilities’ capacity. Rehearing Order at ¶ 24. FERC’s conclusion was neither arbitrary nor capricious. Still, that does not absolve FERC of the problems discussed above. FERC has not explained why existing 19
B.
Next, Gulf South challenges FERC’s denial of its proposed initial rate of return—i.e., the amount the company is permitted to charge in addition to its rate base and operating costs “to ensure that pipeline investors are fairly compensated.” N.C. Utils. Comm’n v. FERC, 42 F.3d 659, 661 (D.C. Cir. 1994). FERC set an initial rate of return of 10.41 percent, which is equal to Gulf South’s last approved rate of return. Rehearing Order at ¶ 29. Gulf South claims that FERC should have adjusted that rate to reflect recent changes in the company’s capital structure.
When setting initial rates of return for integrated expansion facilities in Section 7 proceedings, FERC’s general policy is to use the pipeline’s last approved rate. Id. at ¶¶ 27– 28. The company is then free to seek a different rate of return in its next general rate filing under Section 4 of the Natural Gas Act. See 15 U.S.C. § 717c. The Supreme Court has consistently upheld FERC’s policy of deferring the consideration of fact- intensive rate questions to the company’s next general rate case, because initial Section 7 proceedings are meant only “to hold the line awaiting adjudication of a just and reasonable rate.” Atl. Ref. Co., 360 U.S. at 392; see also United Gas Imp. Co. v. Callery Properties, Inc., 382 U.S. 223, 227–28 (1965).
Gulf South argues that this general policy is unreasonable as applied to this case because the pipeline’s last approved rate of return was set over 20 years ago and because it cannot set a new rate until 2023. Yet Gulf South had an opportunity to set a new rate of return in 2015 in its most recent rate case, but it
shippers should pay a lower rate when they secure capacity on the expansion facilities, even if it will be rare. 20
agreed to settle with FERC and other interested parties without doing so. Moreover, both Gulf South and FERC agree that the only reason Gulf South cannot set a new rate of return until 2023 is that the company agreed in its 2015 settlement to a moratorium on rate filings. FERC Br. 43; Gulf South Br. 15. Thus, the existing rate of return is the result of Gulf South’s contractual choices.
Gulf South asks the court to look past the 2015 settlement because it was a “black box” agreement, a settlement in which the parties agree to the overarching terms without “explain[ing] how the rates were derived. In other words, parties to black box settlements agree to rates without identification or attribution of costs or adjustments for any particular component of those rates.” El Paso Nat. Gas Co., 132 FERC ¶ 61,139, ¶ 82 (Aug. 17, 2010). Because prices are determined without specifying the component parts, no new rate of return is submitted to FERC for approval. Yet nothing compels parties to agree to black-box settlements. To the contrary, FERC has repeatedly encouraged parties to discuss rates of return when reaching settlements. See Rehearing Order at ¶ 28 (“Given this policy [of setting Section 7 rates based on the most recent approved rate of return], the commission encourages companies and parties in rate cases to address concerns relating to the rate of return that should be used in calculating initial rates in future certificate proceedings.”); Transcon. Gas Pipe Line Co., LLC, 156 FERC ¶ 61,022, ¶ 25 (July 7, 2016) (likewise advising parties to “use that opportunity to address issues of concern relating to the rate of return”). Other companies have heeded this advice. See, e.g., E. Shore Nat. Gas Co., 138 FERC ¶ 61,050, ¶ 2 (Jan. 24, 2012) (specifying a rate of return in what was otherwise a black-box settlement). Gulf South agreed to settle the 2015 rate case without adjusting its rate of return; it also agreed to enter an eight year moratorium on rate filings. 21
Gulf South’s freely made contractual choices are no reason to depart from a longstanding policy, repeatedly upheld by the Supreme Court, to use the last approved rate of return.
Gulf South also argues that FERC should have adjusted the rate of return because the formula is so simple it “can be calculated with a pencil on the back of an envelope.” Reply Br. 25. Specifically, Gulf South claims that its rate of return can be adjusted by changing a single variable: its capital structure. In support, Gulf South cites Missouri Public Service Commission v. FERC, where this court held that it was unreasonable for FERC to include a premium in a merged pipeline’s Section 7 rates without conducting the particularized inquiry that would normally be required to include a premium of that kind. 601 F.3d 581, 586–88 (D.C. Cir. 2010). Central to our decision was the fact that “FERC easily could have resolved the threshold issue on the basis of the uncontested paper record before it in the § 7 proceeding.” Id. at 587.
In this case, it was not arbitrary or capricious for FERC to conclude that a full Section 4 hearing was necessary before adjusting Gulf South’s rate of return. First, it was reasonable for FERC to conclude that a full evidentiary hearing would be necessary to account for variables other than capital structure— for instance, the company’s growth rates and its “position within the zone of reasonableness with regard to risk.” Rehearing Order at ¶ 28. As the Commission notes, rates of return are determined based on a discounted cash flow method, which is much more involved than simply adjusting capital structure figures. See Bos. Edison Co. v. FERC, 885 F.2d 962, 965 (1st Cir. 1989) (Breyer, J.) (explaining the discounted cash flow method in length). Moreover, FERC was understandably hesitant to accept Gulf South’s capital structure figures without a hearing. In the rehearing order, FERC noted that Gulf South 22
inexplicably amended its proposed rate in its rehearing request from 10.81 to 10.68 percent. Rehearing Order at ¶ 29. Gulf South explained in its opening brief that it “updated the rate of return to 10.68 percent, based on its most-recently reported capital structure” and “[i]n response to a FERC data request.” Gulf South Br. 15 n.4. The fact that Gulf South’s capital structure figures fluctuated with more data bolsters FERC’s position that it should not adjust the approved rate of return without a hearing to assess Gulf South’s data. This case is readily distinguishable from Missouri Public Service, where the relevant analysis could easily be done without a full hearing. See 601 F.3d at 586–88. We therefore reject Gulf South’s challenge to the initial rate of return of 10.41 percent, its last approved rate of return.
C.
Finally, Gulf South challenges the rejection of its proposed depreciation rate. In this context, “[d]epreciation is generally defined as ‘the loss, not restored by current maintenance, which is due to all the factors causing the ultimate retirement of the property.’” Memphis Light, Gas & Water Div. v. Fed. Power Comm’n, 504 F.2d 225, 228 (D.C. Cir. 1974) (quoting Lindheimer v. Ill. Bell Tel. Co., 292 U.S. 151, 167 (1934)). Pipeline companies may include depreciation charges as “a legitimate part of [their] operating expenses.” Id. To set depreciation rates, FERC must “forecast[ ] the probable useful life of the specific pipeline systems in question, based both on wear and tear and on the exhaustion of natural resources.” Petal Gas Storage, LLC v. FERC, 496 F.3d 695, 702 (D.C. Cir. 2007) (quotation marks omitted). A shorter useful life means a higher depreciation rate, which in turn “will necessarily increase gas prices to current consumers.” Memphis Light, Gas & Water Div., 504 F.2d at 231. As with initial rates of return, FERC’s 23
general policy in Section 7 proceedings involving integrated expansions is to use the pipeline’s last approved deprecation rate. See, e.g., Wyo. Interstate Co., Ltd., 119 FERC ¶ 61,251, ¶ 22 (June 7, 2007). Gulf South’s last approved depreciation rate was based on the 76 year useful life of the Lake Charles Zone facilities, which results in a depreciation rate of 1.32 percent. Rehearing Order at ¶ 30.
While Gulf South does not challenge FERC’s policy as a general matter, it argues that this case falls within an exception for laterals built for a single customer. In those cases, FERC has approved depreciation rates based on the length of the contract at issue. See, e.g., Millennium Pipeline Co., LLC, 157 FERC ¶ 61,096, ¶ 32 n.58 (Nov. 9, 2016); Gas Transmission Nw., LLC, 142 FERC ¶ 61,186, ¶ 17 (Mar. 14, 2013). Gulf South claims those cases should apply here because the length of the contract with Entergy is effectively the useful life of the expansion facilities. Nonetheless, rather than request a depreciation rate based on the 20 year length of the contract with Entergy, Gulf South requested a depreciation rate based on a useful life of 35 years (2.86 percent). Gulf South’s counsel was asked at oral argument why the company requested a depreciation rate based on a useful life that is 15 years longer than the length of the contract, when the company’s entire argument is premised on the notion that the length of the contract is the correct benchmark. Counsel responded that Gulf South “knew that 20 [years] probably wasn’t the right answer,” so it chose a more “practical and realistic” lifespan “somewhere between the 76 and the 20” reflecting the “typical power plant operational life.” Oral Argument at 8:20.
That concession is dispositive. Gulf South does not dispute that it is generally appropriate in Section 7 proceedings to use a pipeline’s last approved depreciation rate. Although FERC 24
has recognized an exception for cases in which the length of the contract is the more appropriate useful life, Gulf South has conceded that the length of the contract “wasn’t the right answer” here. Id. Gulf South has offered no rationale nor cited any precedent for an initial depreciation rate based instead on a useful life of 35 years. Nor did Gulf South argue in its briefs that the depreciation rate should be based on the typical power plant’s operational life. See U.S. ex rel. Davis v. D.C., 793 F.3d 120, 127 (D.C. Cir. 2015) (“[A]rguments raised for the first time at oral argument are forfeited.”). We therefore reject Gulf South’s challenge to the 1.32 percent depreciation rate.
***
We grant Gulf South’s petition for review in part and vacate the part of FERC’s order rejecting incremental-plus rates. We deny the petition for review in all other respects and remand for further proceedings. FERC must reconsider whether to grant incremental-plus rates—whether within the Lake Charles Zone or through the creation of a new rate zone— and provide an adequate explanation for its action consistent with this opinion.
So ordered.