El Paso Natural Gas Co., LLC v. Federal Energy Regulatory Commission, No. 15-1323 (D.C. Cir. 2020)

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Justia Opinion Summary

In three consolidated petitions for review, petitioners challenged five FERC orders on two intertwined El Paso rate cases under the Natural Gas Act, the 2008 Rate Case and the 2011 Rate Case.

The DC Circuit denied the petitions for review, holding that FERC's removal of both the undistributed subsidiary earnings and the loan to El Paso's parent from the equity component of El Paso's capital structure was reasoned and supported by substantial evidence. The court also held that FERC's conclusion that El Paso had not demonstrated that its proposed rates would comply with the 1996 settlement was reasonable; FERC reasonably excluded the two compressor stations from El Paso's rate base; and FERC's approval of a zone-of-delivery rate design measured by contract-paths and its rejection of equilibration for lack of quantitative support were neither arbitrary nor contrary to law.

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United States Court of Appeals FOR THE DISTRICT OF COLUMBIA CIRCUIT Argued March 13, 2020 Decided July 24, 2020 No. 15-1323 EL PASO NATURAL GAS COMPANY, L.L.C., PETITIONER v. FEDERAL ENERGY REGULATORY COMMISSION , RESPONDENT EL PASO MUNICIPAL CUSTOMER GROUP, ET AL., INTERVENORS Consolidated with 16-1122, 18-1183 On Petitions for Review of Orders of the Federal Energy Regulatory Commission Howard L. Nelson argued the cause for petitioner El Paso Natural Gas Company, L.L.C. With him on the briefs were Kenneth M. Minesinger, Francesca Ciliberti-Ayres, and J. Curtis Moffatt. Richard P. Bress argued the cause for petitioners Southern California Gas Company, et al. With him on the briefs were J. 2 Patrick Nevins, Charles S. Dameron, and Jonathan J. Newlander. Beth G. Pacella and Lona T. Perry, Deputy Solicitors, Federal Energy Regulatory Commission, argued the causes for respondent. With them on the briefs were James P. Danly, General Counsel, Robert H. Solomon, Solicitor, and Carol J. Banta, Senior Attorney. Anand Viswanathan, Attorney, entered an appearance. Howard L. Nelson, Kenneth M. Minesinger, and Francesca Ciliberti-Ayres were on the joint brief for intervenors El Paso Natural Gas Company, L.L.C., et al. in support of respondent. Betsy Carr, Katherine B. Edwards, John Paul Floom, Douglas M. Canter, Suzanne K. McBride, Keith A. Layton, John P. Gregg, and Barbara S. Jost were on the brief for intervenors BP Energy Company, et al. in support of respondent. John P. Gregg, Barbara S. Jost, Christopher J. Barr, and Keith A. Layton were on the brief for intervenors El Paso Municipal Customer Group, et al. in support of respondent. Before: SRINIVASAN, Chief Judge, and GARLAND and WILKINS, Circuit Judges. Opinion for the Court filed PER CURIAM. PER CURIAM: El Paso Natural Gas Company operates pipelines that transport natural gas to customers across the southwestern United States. The consolidated petitions for review challenge a number of orders of the Federal Energy 3 Regulatory Commission (“FERC”) on two intertwined El Paso rate cases. The proceedings at issue began in June 2008 when El Paso filed to increase its rates under Section 4 of the Natural Gas Act (“the 2008 Rate Case”). In March 2010, El Paso and its customers settled that case, but reserved certain issues for hearing, including the appropriateness of El Paso’s capital structure. The settlement provided that resolution of that issue would not affect the rates for the term of the settlement but would govern future rate cases. While the 2008 Rate Case’s reserved issues were pending before FERC, El Paso filed another Section 4 rate case in September 2010 (“the 2011 Rate Case”). FERC proceeded in both cases in parallel. In May 2012, FERC resolved the capital structure issue in El Paso Natural Gas Co., 139 F.E.R.C. ¶ 61,095 (2012) (“Op. 517”). In October 2013, FERC incorporated the 2008 Rate Case’s pending resolution of the capital structure issue and largely resolved the 2011 Rate Case’s issues, remanding one compliance question to an administrative law judge. El Paso Nat. Gas Co., 145 F.E.R.C. ¶ 61,040 (2013) (“Op. 528”). In July 2015, FERC granted partial rehearing on El Paso’s capital structure in El Paso Natural Gas Co., 152 F.E.R.C. ¶ 61,039 (2015) (“Op. 517-A”). El Paso then petitioned for review of Opinions 517 and 517-A. While that petition was pending, in February 2016, FERC denied rehearing in relevant part and addressed the compliance issue in the 2011 Rate Case in El Paso Natural Gas Co., 154 F.E.R.C. ¶ 61,120 (2016) (“Op. 528-A”). Three California-based utilities that either ship gas or purchase gas shipped on El Paso’s pipelines (“California Petitioners”) then petitioned for review of Opinions 528 and 528-A. This Court held both petitions for review in abeyance pending FERC’s disposition of requests for rehearing of 4 Opinion 528-A. FERC resolved those requests in El Paso Natural Gas Co., 163 F.E.R.C. ¶ 61,079 (2018) (“Op. 528-B”). El Paso then petitioned for review of Opinions 528, 528-A and 528-B. This Court consolidated the petitions. The result is that we now consider three petitions for review of five Commission orders. In the first petition, El Paso seeks review of Opinions 517 and 517-A. Specifically, El Paso challenges FERC’s removal of two assets -- certain undistributed subsidiary earnings and a loan to El Paso’s parent -- from the equity component of El Paso’s capital structure in the 2008 Rate Case. In the second petition, El Paso seeks review of Opinions 528, 528-A, and 528-B. Specifically, El Paso challenges FERC’s determination that El Paso’s rate proposal would violate a provision of a 1996 settlement agreement, FERC’s exclusion of two compressor stations from El Paso’s rate base, and FERC’s disposition of the capital structure issue as incorporated from the 2008 Rate Case. In the third petition, California Petitioners seek review of Opinions 528 and 528-A. Specifically, California Petitioners challenge FERC’s approval of a method of allocating costs across delivery zones based on contract-paths, and FERC’s rejection of El Paso’s proposal to merge the three western-most delivery zones. We deny the petitions for review. We hold that FERC’s removal of both the undistributed subsidiary earnings and the loan to El Paso’s parent from the equity component of El Paso’s capital structure was reasoned and supported by substantial evidence. We also hold that FERC’s conclusion that El Paso had not demonstrated that its proposed rates would comply with the 1996 settlement was reasonable. Further, we 5 hold that FERC reasonably excluded the two compressor stations from El Paso’s rate base. Finally, we hold that FERC’s approval of a zone-of-delivery rate design measured by contract-paths and its rejection of equilibration for lack of quantitative support were neither arbitrary nor contrary to law. I. The first issue we consider in these petitions is whether FERC arbitrarily removed two assets -- specifically, $145 million in undistributed subsidiary earnings and $615 million in loans from El Paso to its parent -- from the equity component of El Paso’s capital structure. Those adjustments substantially changed El Paso’s debt-equity ratio and thus its rate of return. El Paso challenges those adjustments. Primarily, El Paso contends that FERC arbitrarily departed from its supposed practice of declining to remove an asset from equity absent tracing the asset to an equity issuance. Because we cannot conclude that FERC departed from its precedent, we deny the petitions for review on this issue. A. The Natural Gas Act (“NGA”) requires a pipeline’s rates for the transportation or sale of natural gas to be “just and reasonable.” 15 U.S.C. § 717c(a). “Under cost-of-service ratemaking principles,” just and reasonable rates must “yield[] sufficient revenue to cover all proper costs.” City of Charlottesville v. FERC, 774 F.2d 1205, 1207 (D.C. Cir. 1985). Those costs include not only operating expenses but also the capital costs of the business, such as “service on the debt and dividends on the stock.” Fed. Power Comm’n v. Hope Nat. Gas Co., 320 U.S. 591, 603 (1944). 6 The classic cost-of-service ratemaking formula accounts for capital costs via a return on capital invested in rate base (i.e., in assets used to provide transportation or sale of natural gas subject to FERC’s jurisdiction). See City of Charlottesville, 774 F.2d at 1217; Pub. Serv. Co. of N.M. v. FERC, 653 F.2d 681, 683 (D.C. Cir. 1981). Because different sources of capital have different costs, a pipeline’s total cost of capital depends both on the cost of each source and the portion of each source in the pipeline’s total capitalization (i.e., the pipeline’s capital structure). See Pub. Serv. Co., 653 F.2d at 683. For example, in the 2008 Rate Case, El Paso’s proposed total capitalization ($2.9 billion) was roughly 60% equity ($1.8 billion) and 40% debt ($1.2 billion). Op. 517, 139 F.E.R.C. at 61,580. El Paso requested a 13% rate of return on its equity and a roughly 8% return on its debt, so its proposed rate of return would be about 11% (60% equity * 13% rate of return + 40% debt * 8% rate of return). Id. In principle, a pipeline’s rate of return should be based only on the capitalization, and the corresponding capital structure, that a pipeline devotes to rate base. See El Paso Nat. Gas Co. v. Fed. Power Comm’n, 449 F.2d 1245, 1251 (5th Cir. 1971). But that is often infeasible. A pipeline’s rate base is often less than the pipeline’s total capitalization because the pipeline invests in more than just rate-base assets. For instance, in the 2008 Rate Case, El Paso’s proposed total capitalization was $2.9 billion, but El Paso invested only $1.9 billion in the rate base and the remaining $1 billion in non-rate-base assets. Op. 517, 139 F.E.R.C. at 61,580. In that situation, a pipeline’s balance sheet, which reflects its total capitalization, does not reflect its rate-base capitalization. And in general pipelines do not otherwise track the source of capital used for specific investments beyond total capitalization. Rather, fungible funds from both debt and equity comingle in corporate accounts, and the pipeline draws upon that undifferentiated pool of total 7 capitalization to make both rate-base and non-rate-base investments. In light of that reality, FERC generally assumes that a pipeline invests in rate base in the same debt-equity ratio as it invests in everything else. See Kern River Gas Transmission Co., 123 F.E.R.C. ¶ 61,056, at 61,459 (2008); Ark.-La. Gas Co., 19 F.E.R.C. ¶ 63,008, at 65,057 (1982). But FERC adjusts that assumption when circumstances allow FERC to more accurately estimate the debt-equity ratio of capital invested in rate base. For instance, for project-financed pipelines in which loan agreements require that all debt be invested in rate base, FERC assumes that the pipeline invests all of its debt in rate base and makes up any shortfall with equity. See, e.g., Kern River, 123 F.E.R.C. at 61,459; Wyo. Interstate Co. Ltd., 69 F.E.R.C. ¶ 61,259, at 61,987 (1994). These cases involve a similarly motivated capital structure adjustment. Specifically, if FERC can attribute a specific non-rate-base asset solely to equity, FERC removes that asset from the equity component of the pipeline’s total capitalization. That adjusted capitalization and corresponding debt-equity ratio then more accurately estimates the debt-equity ratio of capital invested in rate base. For example, in a prior case, FERC removed from the equity component of El Paso’s total capitalization two non-rate-base subsidiaries that El Paso had acquired in exchange for El Paso common stock. El Paso Nat. Gas Co., 44 F.P.C. 73, 77 (1970), aff’d, El Paso Nat. Gas, 449 F.2d at 1251. Analogously, if FERC can attribute a non-rate-base asset to debt financing, FERC removes that asset from the debt component of total capitalization. See Ark.-La. Gas, 19 F.E.R.C. at 65,057. To remove a non-rate-base asset solely from equity in that manner, FERC must have a basis to attribute the asset solely to 8 equity. Absent such a basis, FERC adheres to its general assumption that a pipeline invests in rate base assets in the same debt-equity ratio as it invests in other assets. See, e.g., SFPP, L.P., 134 F.E.R.C. ¶ 61,121, at 61,583-84 (2011); Mountain Fuel Res., Inc., 27 F.E.R.C. ¶ 61,171, at 61,315 (1984); S. Cal. Edison Co., 3 F.E.R.C. ¶ 63,033, at 65,203 (1978). B. El Paso contends that FERC’s removal of certain undistributed subsidiary earnings and a pipeline-parent loan from the equity component of El Paso’s capitalization departed from this line of cases. FERC did not depart from those cases. In its decisions here, FERC reaffirmed that, “[i]n order to remove an asset not devoted to jurisdictional service from the equity portion of a pipeline’s capitalization, there must be a basis to attribute that asset to equity.” Op. 517, 139 F.E.R.C. at 61,588. FERC then went on to find sufficient bases to attribute both the undistributed subsidiary earnings and the pipeline-parent loan to equity before removing them. As for the undistributed subsidiary earnings, FERC reasoned that the funds “represent unrealized equity in the subsidiary, generated from pipeline operations,” which “will be recognized . . . as retained earnings, or equity” when El Paso appropriates them. Id. at 61,589. The undistributed earnings “reside in a proprietary capital account, meaning they are owing to the residual shareholder.” Op. 528-B, 163 F.E.R.C. at 61,386. Accordingly, FERC deemed it “appropriate to reflect the exclusion from the equity component of El Paso’s capitalization, rather than apply the exclusion proportionately to debt and equity.” Op. 517, 139 F.E.R.C. at 61,589. 9 As for the pipeline-parent loan, FERC reasoned that El Paso had loaned “funds generated from general revenue and operations,” which “no debt issuance ha[d] any claim on” and which “represent[ed] additional equity available to the pipeline to dispose of at its discretion.” Id. at 61,590. Further, FERC found it “more important than simple accounting,” Op. 517-A, 152 F.E.R.C. at 61,194, that the loan “represent[s] an asset that offsets the liability that [El Paso] owes its shareholder parent by way of common stock,” Op. 517, 139 F.E.R.C. at 61,590. While typically a parent’s stock represents the extent of its investment in the pipeline, El Paso’s continuous maintenance of a large, low-interest, long-term loan to its parent changed the “underlying financial realities.” Op. 517-A, 152 F.E.R.C. at 61,194; see also id. at 61,192. Such a loan rendered “El Paso’s stated equity figure not representative of the amount that its parent corporation has at stake in El Paso” or of “the risks that the parent has undertaken through its investment.” Id. at 61,194. El Paso contends that Commission precedent precludes that kind of attribution, and that only tracing the source of funds for an asset to a specific equity issuance could suffice. We disagree. FERC reasonably interpreted its precedent as requiring attribution of an asset to equity but not necessarily tracing the asset to a specific equity issuance. To be sure, FERC refuses to remove investments in subsidiaries from equity absent a basis to assume that the funds for such investments came from equity. See, e.g., Ark.-La. Gas, 19 F.E.R.C. at 65,057. But FERC does not require that the funds come from a stock issuance in order to attribute them to equity. For example, in Southern Natural Gas Co., FERC attributed a loan to a subsidiary to equity because the pipeline had recently received a roughly equivalent amount in dividends and sales proceeds from another subsidiary. 44 F.P.C. 567, 572-73 (1970). FERC traced the loan to those funds, which the 10 pipeline recorded as gains in equity accounts, not to a stock issuance. Id. FERC proceeded similarly below, attributing both assets at issue to equity derived from operations. FERC noted that the undistributed subsidiary earnings “reside in a proprietary capital account, meaning they are owing to the residual shareholder.” Op. 528-B, 163 F.E.R.C. at 61,386. When El Paso’s parent appropriates them, they “will be recognized . . . as retained earnings, or equity.” Op. 517, 139 F.E.R.C. at 61,589. Likewise, FERC traced the pipeline-parent loan to “general revenue and operations,” which “no debt issuance ha[d] any claim on” and which “represent[ed] additional equity available to the pipeline to dispose of at its discretion.” Id. at 61,590. Moreover, the loan offset El Paso’s parent’s outlay of common stock. Op. 517-A, 152 F.E.R.C. at 61,195. FERC’s disposition is also consistent with numerous FERC precedents that have removed similar assets from the equity component of capital structure. See, e.g., Holyoke Water Power Co. & Holyoke Power & Elec. Co., 28 F.E.R.C. ¶ 61,361, at 61,651 (1984) (undistributed subsidiary earnings); Ark.-La. Gas, 19 F.E.R.C. at 65,057 (same); United Gas Pipe Line Co., 13 F.E.R.C. ¶ 61,044, at 61,096 (1980) (same); S. Cal. Edison Co., 3 F.E.R.C. at 65,203 (same); Distrigas of Mass. Corp., 18 F.E.R.C. ¶ 63,036, at 65,121 (1982) (a pipeline-parent loan). Especially in light of the “deference . . . due to the Commission’s interpretation of its own precedent,” Mo. Pub. Serv. Comm’n v. FERC, 783 F.3d 310, 316 (D.C. Cir. 2015), we cannot conclude that the Commission departed from its context-sensitive approach to capital structure adjustments. In addition, FERC’s disposition was reasonable. At bottom, FERC seeks to estimate the debt-equity ratio invested in rate base to the extent feasible. See El Paso Nat. Gas, 11 449 F.2d at 1251. Retained earnings represent equity just like the proceeds of an equity issuance. It would make little sense for FERC to remove from equity assets traced to proceeds of an equity issuance (one form of equity), but not assets attributed to retained earnings (another form of equity). Moreover, FERC’s consideration of the underlying financial realities, and specifically the pipeline-parent loan’s impact on them, was reasoned and entitled to the “great deference” we afford FERC’s enforcement of the just and reasonable standard. Morgan Stanley Capital Grp. Inc. v. Pub. Util. Dist. No. 1, 554 U.S. 527, 532 (2008). FERC’s attribution of internally generated funds to equity in this case did not exceed the bounds of the just and reasonable standard. As discussed, while the rate of return should be based only on the capitalization that a pipeline devotes to public service, that may be infeasible when “non-public segments of such capital” cannot be “distinctly identified and surely isolated.” El Paso Nat. Gas, 449 F.2d at 1251. In such situations, “a potential shareholder or lender-investor” may be unable to “determine the value of the regulated versus the nonregulated operations and calculate the sureness of his regulated return on the one and the commercial risk he assumes on the other.” Id. at 1250. Here, however, FERC found that “El Paso’s debtors are able to independently weigh the risks” of El Paso’s rate base assets and the outstanding pipeline-parent loan balance. Op. 517, 139 F.E.R.C. at 61,590-91. El Paso provides no reason to disturb that finding. That the funds loaned were internally generated does not mean that investors cannot distinctly identify the loan itself as non-public and evaluate it independently from El Paso’s public capitalization. The same is true for undistributed subsidiary earnings. Accordingly, we cannot conclude that FERC’s 12 removal of either asset exceeded the bounds of the just and reasonable standard. For these reasons, we deny the petitions for review on this issue. II. Next, El Paso challenges FERC’s determination that it charged for costs prohibited by a 1996 settlement agreement. That year, California customers returned their rights to about 35% of El Paso’s total capacity in response to state efforts to deregulate the electricity industry. Freeport-McMoRan Corp. v. FERC, 669 F.3d 302, 306 (D.C. Cir. 2012). For pipeline customers, unsubscribed capacity poses a problem. Pipeline rates are based on costs, so fewer customers means fewer people to split those costs. El Paso’s remaining customers therefore faced the potential for major rate hikes if El Paso could not resell this unsubscribed capacity, and El Paso risked a further drop in demand brought on by higher prices. In order to spread the risk, El Paso and its customers (now called “rate-protected shippers”) struck a deal: current customers would shoulder some costs in the short term (until 2004) in exchange for, as relevant here, a long-term promise that they would not thereafter pay for costs related to El Paso’s 1995 capacity if that capacity became unsubscribed or was discounted. Specifically, Article 11.2(b) of the settlement provides: El Paso agrees that the firm rates applicable to service to any [rate-protected shipper] will exclude any cost, charge, surcharge, component, or add-on in any way related to the capacity of its system on December 31, 1995 . . . that becomes unsubscribed or is subscribed 13 at less than the maximum applicable tariff rate as [adjusted for inflation]. Op. 528, 145 F.E.R.C. at 61,183 n.5. In essence, Article 11.2(b) modifies El Paso’s ability to charge “discount adjustments” to rate-protected shippers. Normally, when a pipeline gives some customers a discount due to competitive conditions, it can require other customers to help bear the cost. See Ala. Mun. Distributors Grp. v. FERC, 312 F.3d 470, 472-73 (D.C. Cir. 2002). Similarly, when a pipeline has unsubscribed capacity, each customer’s share of fixed costs will increase. Article 11.2(b) prevents El Paso from charging rate-protected shippers for those costs insofar as they are “in any way related” to unsubscribed or discounted 1995 capacity. El Paso has spent the intervening years trying to get out of this bargain.1 Today though, El Paso accepts that Article 11.2(b) applies. It simply argues that it has complied. FERC has developed a two-step process, unchallenged here, for testing El Paso’s compliance with Article 11.2(b): First, it calculates “whether El Paso’s firm contracts at or above the rate cap exceed 4,000 MMcf/d.” And second, it determines “whether El Paso proposes to shift the costs of unsubscribed or discounted capacity to the rates of Article 11.2(b) shippers.” 1 See, e.g., Freeport-McMoRan Corp., 669 F.3d at 308; Op. 528-A, 154 F.E.R.C. at 61,705; Op. 517-A, 152 F.E.R.C. at 61,223; Op. 528, 145 F.E.R.C. at 61,253; Op. 517, 139 F.E.R.C. at 61,60607; El Paso Nat. Gas Co., 133 F.E.R.C. ¶ 61,129, at 61,622 (2010); El Paso Nat. Gas Co., 132 F.E.R.C. ¶ 61,155, at 61,785 (2010); El Paso Nat. Gas Co., 124 F.E.R.C. ¶ 61,227, at 62,168 (2008); El Paso Nat. Gas Co., 124 F.E.R.C. ¶ 61,124, at 61,662 (2008); El Paso Nat. Gas Co., 114 F.E.R.C. ¶ 61,290, at 61,014 (2006). 14 Op. 528, 145 F.E.R.C. at 61,267 (quoting Op. 517, 139 F.E.R.C. at 61,624). The first step is used to determine whether El Paso has any unsubscribed or discounted 1995 capacity. Because El Paso operates as an integrated whole, it is difficult to assign a unit of capacity to a particular year. Instead, FERC treats the first 4,000 million cubic feet per day (MMcf/d) -- El Paso’s approximate 1995 capacity -- as the 1995 capacity. See Freeport-McMoRan, 669 F.3d at 312-13 (upholding this presumption). If El Paso subscribes 4,000 MMcf/d of capacity at its maximum rate, FERC will presume that there is no unsubscribed or discounted 1995 capacity and thus, there is no “cost, charge, surcharge, component, or add-on in any way related to” that capacity that El Paso can pass on. But if El Paso has not subscribed 4,000 MMcf/d at the maximum rate, FERC will proceed to the second step and examine El Paso’s rates more closely to see whether El Paso is charging those costs to rate-protected shippers. El Paso accepts that it has not met the 4,000 MMcf/d threshold, but disagrees with FERC regarding how to determine whether the costs of discounted or unsubscribed capacity are being charged to rate-protected shippers. Because El Paso does not dispute that it bears the burden of proving Article 11.2(b) compliance, see Op. 528-A, 154 F.E.R.C. at 61,742, we ask only whether FERC reasonably rejected El Paso’s approach, not whether FERC’s approach is right. We review FERC’s decision under the familiar arbitrary-andcapricious standard. 5 U.S.C. § 706(2)(A); see FERC v. Elec. Power Supply Ass’n, 136 S. Ct. 760, 782 (2016). El Paso contends that FERC must look at the facilities (e.g., the physical pipeline) that existed in 1995 and see what costs those add to El Paso’s current rates. Since any facilities 15 that existed in 1995 have significantly depreciated in value, the revenues attributable to those facilities now exceed their costs, which, in El Paso’s view, means that there are no costs “in any way related to” discounted or unsubscribed 1995 capacity. Hence, there is no impermissible cost-shifting. FERC, by contrast, points out that Article 11.2(b) does not mention “facilities,” but only refers to “the capacity of [El Paso’s] system on December 31, 1995.” Op. 528-B, 163 F.E.R.C. at 61,377 (emphasis omitted). In FERC’s view, El Paso takes a wrong turn at the outset by looking at facility costs. Instead, to simplify slightly, FERC compares the rates El Paso wants to charge rate-protected shippers with the rates it would have charged them had it managed to subscribe 4,000 MMcf/d at the maximum rate. Op. 528-A, 154 F.E.R.C. at 61,742. Since the proposed rates are higher, El Paso has not complied with Article 11.2(b). We agree with FERC. Its reading is consistent with the text and purpose of the 1996 settlement. The settlement refers to capacity, not facilities, and FERC reasonably concluded that these are distinct concepts. See Op. 528-A, 154 F.E.R.C. at 61,740-41. While El Paso maintains that the “cost of capacity can be measured only by reference to the cost of facilities that create that capacity,” El Paso Opening Br. 23 (emphasis added), FERC’s alternative methodology shows otherwise. And given the capacious language of the settlement -- covering costs “in any way related to” discounted capacity -- FERC’s approach also avoids unduly narrowing which costs are prohibited. Cf. Morales v. Trans World Airlines, Inc., 504 U.S. 374, 383 (1992) (noting that the “ordinary meaning” of “relating to” is a “broad one”). FERC’s reading also effectuates the settlement’s purpose by providing shippers with long-term protection. That promise 16 would mean little if the prohibited costs quickly depreciated away. Especially in light of the “high degree of deference” we give to FERC’s interpretation of settlement agreements, Freeport-McMoRan, 669 F.3d at 308, we conclude that FERC reasonably rejected El Paso’s facilities-based approach. From there, El Paso’s remaining arguments fall away. El Paso barely contests FERC’s bottom-line conclusion that it shifted costs, simply reiterating that FERC should have looked at depreciated facility costs -- the argument we just rejected. Instead, El Paso focuses on FERC’s rejection of two studies that purport to show El Paso’s compliance with Article 11.2(b). But both of those studies “erroneously identify the cost of 1995 capacity as the cost of the facilities comprising El Paso’s 1995 system.” Op. 528-A, 154 F.E.R.C. at 61,741; see Op. 528-B, 163 F.E.R.C. at 61,374. By putting all of its eggs in one basket, El Paso made FERC’s task -- and ours -- straightforward. Having reasonably rejected El Paso’s premise, FERC reasonably rejected studies that insist on that premise. El Paso makes one other argument, but it too is readily dispatched. El Paso claims that FERC improperly treated El Paso’s failure to subscribe 4,000 MMcf/d at the maximum rate as dispositive, ignoring whether El Paso charged rate-protected shippers for discounted capacity. But that is not what FERC did. Instead, FERC first noted that, because El Paso had not met the 4,000 MMcf/d threshold, discounted or unsubscribed 1995 capacity existed. At the second step, it then analyzed El Paso’s proposed rates and determined that they passed the cost of those discounts on to rate-protected shippers. Op. 528-A, 154 F.E.R.C. at 61,742; Op. 528-B, 163 F.E.R.C. at 61,378, 61,380. That two-step analysis is fully consistent with FERC’s long-standing approach to Article 11.2(b). 17 III. Finally, El Paso challenges FERC’s decision to exclude two compressor stations from its cost calculation. 2 As part of its mandate to ensure “just and reasonable” rates, FERC generally looks to a pipeline’s cost of service. N. Nat. Gas Co. v. FERC, 700 F.3d 11, 13 (D.C. Cir. 2012) (quoting 15 U.S.C. § 717c(a)). By regulation, FERC considers a pipeline’s costs during a test period, including a twelve-month base period and an up-to-nine-month adjustment period. 18 C.F.R. § 154.303(a). But FERC may permit “reasonable deviation” from the test period, id. § 154.303(d), which it does when testperiod estimates are “substantially in error or would yield unreasonable results,” Nat’l Fuel Gas Supply Corp., 51 F.E.R.C. ¶ 61,122, at 61,334 (1990). In September 2010, two days before it initiated its 2011 rate case and during the adjustment period for that same case, El Paso applied to abandon its Deming and Tucson compressor stations. See Abandonment Appl. 1 (Sept. 28, 2010) (2 J.A. 1161);3 El Paso Rate Filing 5 (Sept. 30, 2010) (2 J.A. 575) (initiating the 2011 rate case with an adjustment period running from July 1, 2010, to March 31, 2011). It noted that those compressors “have become functionally obsolete and are no longer required to provide natural gas transportation service.” 2 Natural gas is transported at high pressure. Pipelines use compressor stations at strategic locations to maintain that pressure and pump gas along the pipeline. See FERC, AN INTERSTATE NATURAL GAS FACILITY ON MY LAND? WHAT DO I NEED TO KNOW? 20 (Aug. 2015). 3 The parties filed two separately paginated appendices in these consolidated cases. For ease of reference, we cite the appendix in No. 15-1323 as Volume 1 and the appendix in Nos. 16-1122 and 181183 (including the supplement) as Volume 2. 18 Abandonment Appl. 1 (2 J.A. 1161). Both had been used only in reserve since at least 2004 and “recently” were only “intermittently run and tested to maintain compliance” with Department of Transportation and Environmental Protection Agency requirements. Id. at 6-7 (2 J.A. 1166-67). El Paso also noted the benefit to its customers: “Any appropriate rate impact to customers resulting from a timely approval of this abandonment application should be reflected in [El Paso’s 2011] rate case filing.” Id. at 12 (2 J.A. 1172). FERC approved the abandonment in September 2011, after the end of the test period. El Paso Nat. Gas Co., 136 F.E.R.C. ¶ 61,180 (2011). Despite those statements, El Paso sought to include the compressor costs in its rates. FERC’s Administrative Law Judge (“ALJ”) found this to be “entirely unjust and unreasonable,” noting that although FERC did not approve the abandonment until after the end of the test period, El Paso’s application represented that the stations were no longer useful during the test period. El Paso Nat. Gas Co., 139 F.E.R.C. ¶ 63,020, at 66,214 (2012) (“ALJ Op.”). FERC affirmed and reaffirmed the ALJ’s conclusion. Op. 528, 145 F.E.R.C. at 61,214-15; Op. 528-A, 154 F.E.R.C. at 61,677. In doing so, FERC noted that El Paso “does not dispute that these compressor stations have not served any real function related to the transportation of natural gas for a number of years.” Op. 528, 145 F.E.R.C. at 61,214. El Paso presses its case to us, arguing that excluding the compressor costs is inconsistent with two strands of FERC precedent. In Tennessee Gas Pipeline Co., 73 F.E.R.C. ¶ 61,368 (1995), and Panhandle Eastern Pipe Line Co., 71 F.E.R.C. ¶ 61,228 (1995), FERC permitted pipelines to charge for facilities in service during the test period but later abandoned. And in Wyoming Interstate Co., 76 F.E.R.C. ¶ 61,252 (1996), and Eastern Shore Natural Gas Co., 76 19 F.E.R.C. ¶ 61,358 (1996), FERC permitted pipelines to charge for new backup compressor stations. All of these cases simply reflect FERC’s longstanding practice of permitting charges for facilities that are “used and useful.” See La. Pub. Serv. Comm’n v. FERC, 174 F.3d 218, 228-29 (D.C. Cir. 1999). Although El Paso points to its own expert’s testimony that the stations were used and useful, see Prepared Rebuttal Testimony of Mark A. Westhoff 26-27 (2 J.A. 756-57), FERC’s factual finding to the contrary is “conclusive” if supported by “substantial evidence,” 15 U.S.C. § 717r(b). Our review on this score is “highly deferential.” PJM Power Providers Grp. v. FERC, 880 F.3d 559, 562 (D.C. Cir. 2018) (internal quotation marks omitted). Here, FERC reasonably found, based on El Paso’s own statements, that the Deming and Tucson compressor stations served no purpose for backup or otherwise during the test period. In light of that finding, FERC properly held El Paso to its promise not to charge customers for those costs. Taking a different tack, El Paso argues that, since FERC excluded the compressor costs, it should also have considered post-test-period changes that favored El Paso. But making one post-test-period adjustment does not obligate FERC to make all such adjustments. FERC considers subsequent developments when test-period estimates are “substantially in error or would yield unreasonable results.” Nat’l Fuel, 51 F.E.R.C. at 61,334. As El Paso makes no effort to show how the changes it favors meet that standard, this argument fails as well. IV. For their part, California Petitioners -- Southern California Gas Company, San Diego Gas & Electric Company, and Southern California Edison Company -- challenge two FERC 20 orders -- Opinion 528 and Opinion 528-A -- on several issues: (1) FERC’s approval of a “zone-of-delivery” rate methodology; (2) FERC’s approval of the measurement of those zones with reference to “contract paths”; and (3) FERC’s rejection of El Paso’s “equilibration” proposal and its determination that the proceeding was properly conducted under Section 4 of the NGA, 15 U.S.C. § 717c, rather than under Section 5, id. § 717d. For the reasons detailed herein, we deny the petition on all appealed issues. There is substantial evidence supporting FERC’s finding that El Paso’s continued use of a zone-of-delivery design now calculated by reference to contract paths is just and reasonable under Section 4; El Paso’s uncontested dekatherm-mileage study supports a rate design reflecting moderate, distance-based differences in rates increasing from east to west, and contract paths are a reasonable measurement tool in this case. FERC also reasonably affirmed the ALJ’s determination that El Paso failed to prove its equilibration proposal was just and reasonable, finding equilibration would significantly modify the results of the dekatherm-mileage study without sufficient empirical support. Finally, approving the zone-of-delivery design and rejecting equilibration did not result in a rate of FERC’s own making such that Section 5 of the NGA is triggered. FERC properly proceeded under Section 4 of the NGA and as such was not required to consider California Petitioners’ alternative rate proposal. In a rate-setting proceeding, a pipeline may seek to recover its mileage-based fixed costs, or costs associated with maintaining sufficient capacity to serve peak needs on the system. Because of the interconnected, multi-path nature of El Paso’s system, most gas being delivered has more than one flow option, and higher demand can require gas to flow through 21 more indirect routes. These fluctuations make the actual route gas will flow to each delivery point impossible to calculate, complicating the allocation of fixed costs. In El Paso’s last fully litigated rate case in 1959 (before the pipeline was as complex as it is today), FERC approved a zone-of-delivery rate methodology, under which shippers pay the same rate to deliver gas to any point within each of the five state zones -Texas, New Mexico, Arizona, Nevada, and California -increasing in modest increments from east to west. See El Paso Nat. Gas Co., 22 F.P.C. 260, 280-82 (1959). In El Paso’s two most recent rate settlements, it has continued to use these state-wide zones. In the 1990s as pipeline demand grew, El Paso had insufficient capacity to serve all customers, prompting FERC to order the creation and assignment of “contract paths.” See Op. 528-A, 154 F.E.R.C. at 61,682. These contract paths were not created to establish the path that gas would actually flow from receipt and delivery points, but rather the path on El Paso’s system that a shipper had rights to under its contract. Contract paths were then assigned as a mechanism to ensure that El Paso had capacity to meet the demands of all shippers’ contracts on peak days. See Op. 528, 145 F.E.R.C. at 61,223; Op. 528-A, 154 F.E.R.C. at 61,686. In this rate case, El Paso proposed to continue its 50-plusyear-old zone-of-delivery rate design. See ALJ Op., 139 F.E.R.C. at 66,217. To support its proposal, El Paso conducted a dekatherm-mileage study, which calculated the average distance gas is transported to each of the five rate zones based on assigned contract paths. The study determined the mileage associated with every firm shipper’s contract path in the state, then the mileages were added together and weighted by the total contract delivery volume for each zone. See id. at 66,222; see also El Paso Ex. No. 224, at 41 (2 J.A. 680) (El Paso 22 witness Richard Derryberry stating, “[b]ecause a shipper is able to rely on its contract paths when they are needed most, at the peak, I believe such paths provide a more accurate measure of the facilities need[ed] to serve the shipper, and the associated distance of haul, than the ‘typical’ flows” on El Paso’s system). After calculating the average miles of haul for each of the five state zones, El Paso further proposed to “equilibrate” the distances, or equalize the rates, for the three western states -Arizona, Nevada, and California -- into a single zone. See El Paso Ex. No. 107, at 29-30 (2 J.A. 729-30). After equilibration, the proposed California rates would have been slightly lower and the Arizona rates slightly higher than under a pure five-zone approach. Op. 528, 145 F.E.R.C. at 61,207.4 After a hearing, the ALJ found El Paso’s zone-of-delivery design as measured by contract paths just and reasonable but rejected the additional step of equilibration. See ALJ Op., 139 F.E.R.C. at 66,220-29. FERC affirmed these findings in Opinion 528, 145 F.E.R.C. at 61,222-23, 61,225-26, 61,227, and reaffirmed them in relevant part in Opinion 528-A, 154 F.E.R.C. at 61,679-86, 61,690-93. Below we address California Petitioners’ objections to the challenged portions of FERC’s orders in turn. A. The question of how to allocate costs among a pipeline’s customers is “a difficult issue of fact, and one on which [FERC] enjoys broad discretion.” Midcoast Interstate Transmission, Inc. v. FERC, 198 F.3d 960, 971 (D.C. Cir. 2000) (citation omitted). And since the question involves “both technical understanding and policy judgment,” this Court’s “important 4 The impact on Nevada was hypothetical given the lack of contracts there. See El Paso Ex. No. 177, at 37 (2 J.A. 625). 23 but limited role is to ensure that [FERC] engaged in reasoned decisionmaking -- that it weighed competing views, selected [a result] with adequate support in the record, and intelligibly explained the reasons for making that choice.” Elec. Power Supply Ass’n, 136 S. Ct. at 784. In a Section 4 rate case, the pipeline bears the burden to prove the justness and reasonableness of any changes it proposes to its previously approved (and presumptively reasonable) rate design. See 15 U.S.C. § 717c(e); see also 5 U.S.C. § 556(d) (proponent of order bears the burden of proof); 18 C.F.R. § 154.301(c) (stating a “natural gas company filing for a change in rates or charges . . . [bears] the burden of proving that the proposed changes [in rates] are just and reasonable”). In order for distance-based rates to be just and reasonable in a Section 4 proceeding, FERC must reasonably conclude that the cost of transmission on the system varies materially with the distance from the nominated point of receipt to the point of delivery. See 18 C.F.R. § 284.10(c)(3)(ii). And FERC’s findings must be supported by substantial evidence in the record. Algonquin Gas Transmission Co. v. FERC, 948 F.2d 1305, 1311 (D.C. Cir. 1991). California Petitioners first argue that FERC’s approval of El Paso’s proposed zone-of-delivery method was not just and reasonable or supported by substantial evidence. Cal. Pet’rs Opening Br. 25. Because the modern-day El Paso pipeline is an integrated and reticulated system, it relies extensively on displacement, or the “substitution of gas at one point for gas received at another point.” Interstate Nat. Gas Ass’n of Am. v. FERC, 285 F.3d 18, 42 (D.C. Cir. 2002). Pointing to the ALJ’s concession that, due to displacement and other pipeline features, it is impossible to “accurately calculate distance [of product flows],” ALJ Op., 139 F.E.R.C. at 66,222 , California 24 Petitioners argue that distance-based rates are “untenable.” Cal. Pet’rs Opening Br. 26. That is, since “it is impossible to tell how far any particular shipment of gas will actually travel to reach a delivery point[,] . . . the impact of distance on the cost of transportation is unknowable.” Id. at 25-26. They point out that, as El Paso’s own expert acknowledged, “[t]he changes that have occurred on the [El Paso] system in recent years have almost all been in the direction of deemphasizing the importance of distance as a cost causation factor[.]” El Paso Ex. No. 224, at 4 (2 J.A. 643). For example, the predominant source of gas has shifted to the San Juan Basin, which now supplies two-thirds of all deliveries and “is more or less equidistant from all major delivery centers.” Id. at 16 (2 J.A. 655). As such, California Petitioners argue there is “no rational basis for saying that it costs El Paso more to make deliveries to California than to make deliveries to Texas.” Cal. Pet’rs Opening Br. 29. In Opinions 528 and 528-A, FERC affirmed and reaffirmed the ALJ’s approval of El Paso’s proposed zone-of-delivery design, mostly on the basis of El Paso’s “thorough and detailed” dekatherms-mileage study. Op. 528, 145 F.E.R.C. at 61,222. FERC found El Paso’s unchallenged dekathermmileage study “demonstrated somewhat shorter average transportation mileages, and thus less cost responsibility, for zones moving from east (Texas) to west (California).” FERC Br. 62-63 (citing ALJ Op., 139 F.E.R.C. at 66,218, 66,222, 66,228; Op. 528, 145 F.E.R.C. at 61,222-23; Op. 528-A, 154 F.E.R.C. at 61,679). Finding “El Paso’s mileage studies were meticulously prepared, and the assumptions underlying the studies [were] reasonable and the differences in mileages between the same receipt point/delivery point combinations reflect[ed] operational limitations on El Paso’s system,” Op. 528-A, 154 F.E.R.C. at 61,685, FERC held the studies provided “substantial evidence to support” El Paso’s proposed 25 rate design of “moderate, but reasonable, differences in rates due to distance sensitivity,” Op. 528, 145 F.E.R.C. at 61,22223. Although FERC agreed that some factors (i.e., contraflows, displacement, and the integrated nature of the pipeline) complicate a pure distance-based calculation, it found the study properly accounted for these realities. See Op. 528-A, 154 F.E.R.C. at 61,683. Given the level of deference we grant FERC’s ratemaking decisions and the comprehensive nature of El Paso’s dekatherm-mileage study, which illustrates that “distance still has at least a modest effect on system cost responsibility,” ALJ Op., 139 F.E.R.C. at 66,228, we find there is substantial evidence to support El Paso’s proposed zone-of-delivery methodology. A distance-sensitive rate -- reflecting modest increases moving east to west through the five state zones -has been in place on the El Paso pipeline for over fifty years. See id. at 66,217 (discussing the 1959 litigation and 1990 Settlement); El Paso Nat. Gas Co., 54 F.E.R.C. ¶ 61,316, at 61,934 (1991) (approving the continued use of historic zone rates because “[t]he zones do reflect differences in the distance of haul”), on reh’g, 56 F.E.R.C. ¶ 61,290, at 62,156 (1991). And although California Petitioners correctly point to the increasing complexity of the system over time, FERC reasonably found the unchallenged study provided a “reasonable method to account” for these realities. Op. 528-A, 154 F.E.R.C. at 61,683. The study proactively addressed contraflows, displacement, and other phenomena California Petitioners point to, and illustrated that these characteristics did not offset the finding that “distance remains a significant factor in determining the cost of transporting gas on El Paso’s system.” Op. 528, 145 F.E.R.C. at 61,223. El Paso’s statedefined rate zones, previously approved by FERC, remain presumptively just and reasonable, see Morgan Stanley Capital Grp., 554 U.S. at 530-31; see also ALJ Op., 139 F.E.R.C. at 26 66,221, and given the evidence in the record, FERC did not act arbitrarily and capriciously in reaffirming them here. B. Next, California Petitioners argue that even if there is a rational basis for distance-sensitive rates, that contract paths are not a rational tool for measuring costs associated with such distance. Cal. Pet’rs Opening Br. 31-39. As FERC conceded, El Paso’s contract paths “were never developed or approved for the purpose of cost allocation,” Op. 528-A, 154 F.E.R.C. at 61,686, but were created to help with capacity allocation problems. See Op. 528, 145 F.E.R.C. at 61,223 (noting that “contract paths reflect the level of service El Paso is obligated to provide on any day”); Tr. of Hearing 1472 (Nov. 4, 2011) (2 J.A. 613) (El Paso witness Derryberry conceding that on an average day there is “no relationship . . . between the contract path that a shipper holds in its contract and the [actual] flow [of gas] on that day”). California Petitioners do not contest the dekatherm-mileage study or its findings, see Cal. Pet’rs Opening Br. at 13, 39; see also ALJ Op., 139 F.E.R.C. at 66,221 n.156 (noting participants do not dispute the distances El Paso assigned to contract paths); they simply argue that contract paths are “fundamentally not a rational measure of cost incurrence,” so the study’s quality is “irrelevant,” Cal. Pet’rs Opening Br. 39. They argue that the length of a contract path bears “no such rational relationship” to the distance gas actually travels and thus to the costs actually incurred to provide that transportation, especially given aspects of the pipeline such as contraflows. Id. at 32. In support, California Petitioners provide a map of the complex pipeline, id., and point to statements by an El Paso expert conceding that gas often flows along shorter, more efficient routes than the assigned contract paths, Tr. of Hearing 2183, 2186 (Nov. 14, 2011) (2 J.A. 764, 767). They analogize using the contract path 27 methodology to mapping a drive from Bethesda to Baltimore via Alexandria, arguing it would not be rational to use this circuitous and rarely sensible detour to Virginia as a substantial factor in calculating the average drive time between two Maryland cities. Cal. Pet’rs Opening Br. 35. Despite California Petitioners’ claims, we find there is substantial evidence supporting FERC’s finding that El Paso’s proposed contract-path methodology is just and reasonable in this case. As California Petitioners point out, “[t]he relevant question is whether [contract paths] are a rational tool for the purpose of measuring cost incurrence, a purpose for which they concededly were not developed.” Id. at 32. However, we disagree that just because contract paths do not reflect the path gas actually flows on El Paso’s system (which California Petitioners admit is impossible to determine, id. at 2), they cannot be used to calculate the costs incurred by El Paso to provide that transportation. California Petitioners correctly point out the dekatherm-mileage study shows that, even under peak conditions, actual flows replicate contract paths only “60 to 70 percent” of the time and only in the northern parts of the system, Tr. of Hearing 2617 (Nov. 16, 2011) (2 J.A. 742-43), arguing this is a “far cry” from resembling actual flows, Cal. Pet’rs Opening Br. 37. However, FERC reasonably found that even though contract paths do not consistently reflect actual flows, they can still be appropriate measuring tools for ratemaking purposes. Even though a shipper’s gas may not actually travel along its assigned contract path, those paths still “reflect a shipper’s right to capacity along a specified path, not subject to [a] prior claim by any other shipper, on all days[.]” FERC Br. 53; see also Op. 528-A, 154 F.E.R.C. at 61,680, 61,685-86; Op. 528, 145 F.E.R.C. at 61,223. As the ALJ noted, allocating fixed costs based on capacity rights as established by contract paths 28 “acknowledges that installed capacity is the pipeline’s major fixed cost driver.” ALJ Op., 139 F.E.R.C. at 66,224 . And “[b]ecause a shipper is able to rely on its contract paths when they are needed most, at the peak, . . . such paths provide a more accurate measure of the facilities need[ed] to serve the shipper, and the associated distance of haul, than the ‘typical’ flows[.]” El Paso Ex. No. 224, at 41 (2 J.A. 680). Furthermore, FERC credited testimony that “reliance on typical or average, flows may well understate the capacity -- and therefore the related mileage -- needed to serve a particular shipper.” Id. El Paso’s dekatherm-mileage study clearly established (and California Petitioners do not challenge) the relative length of the average contract paths in each zone, which supported moderate, but reasonable, distance-based differences in rates. See Op. 528, 145 F.E.R.C. at 61,222. Although it’s clear why California Petitioners would desire that shorter routes be used to calculate their rates, it was reasonable for FERC to find that, in these circumstances, allocating fixed costs based on capacity rights reasonably reflects the costs required to provide services to customers on a complex and integrated pipeline. Although we might not drive from Bethesda to Baltimore via Alexandria every day, if the highway authority must maintain a dedicated lane for us to take that route on a high-traffic day, the associated expenses seem a reasonable measure of the fixed costs expended to serve our needs. C. California Petitioners’ next argue that even if the contract path and zone-of-delivery methodologies are reasonable, FERC’s decision to reject El Paso’s proposed “equilibration” of the western-zone rates was arbitrary and capricious. Cal. Pet’rs Opening Br. 23. In its ratemaking proposal, after calculating rates for each of the five state zones based on contract paths, El Paso proposed to “equilibrate” the California, 29 Arizona, and Nevada zones by averaging their rates into a single rate, maintaining separate zonal rates only for New Mexico and Texas. Op. 528-A, 154 F.E.R.C. at 61,680; see also ALJ Op., 139 F.E.R.C. at 66,187 n.27 (noting equilibration is not a previously approved practice). El Paso asserted equilibration was justified because any cost differences between the California and Arizona zones due to distance of haul were minimal and offset by other factors that made transportation to Arizona more expensive. Op. 528, 145 F.E.R.C. at 61,226. The ALJ found El Paso had not shown its equilibration proposal would result in just and reasonable rates since the concept was inconsistent with the distance-sensitive nature of El Paso’s contract path methodology and its dekatherm-mileage study. ALJ Op., 139 F.E.R.C. at 66,22829. FERC affirmed this finding, stating equilibration would “significant[ly] modif[y]” the results of the detailed dekatherm-mileage study -- which did reflect differences in average mileages between the California and Arizona zones -without offering any comparable empirical support. Op. 528, 145 F.E.R.C. at 61,227-28. California Petitioners disagree, pointing to El Paso’s assertion below that without equilibration, “the resulting zone of delivery rates would overstate the importance of distance in allocating costs.” El Paso Br. Opp. Exceptions 47 (Sept. 19, 2012) (2 J.A. 866). They argue the rejection of equilibration places undue importance on state boundaries, which are themselves inherently arbitrary, and that “there is no more ‘empirical support’ for treating Arizona as its own zone than there is for . . . dividing Arizona into two (or more) zones or [] combining Arizona with California . . . especially [] given that the only California delivery points on the El Paso system are literally on the Arizona border.” Cal. Pet’rs Opening Br. 4041. They argue El Paso presented sufficient evidence showing that higher system costs in Arizona -- including the use of 30 smaller diameter delivery laterals which have a higher per-unit cost -- offset the slightly higher distance to California, justifying western-zone equilibration. See Op. 528, 145 F.E.R.C. at 61,227. El Paso argued below and California Petitioners argue now that FERC’s 1962 decision in Tennessee Gas Transmission Company also supports its equilibration proposal. 27 F.P.C. 202 (1962). There, as here, FERC found it impossible to identify the portion of the mainline facilities installed or operated for the benefit of any individual customer. Id. at 208. In Tennessee Gas, the New England zone of that system featured lateral pipelines not present elsewhere in the system requiring a special type of service, which FERC found justified a differentiated cost zone. Id. at 212-13. California Petitioners argue this precedent clearly supports El Paso’s equilibration proposal given the laterals and other distinct costs on the Arizona portion of the pipeline. See Op. 528, 145 F.E.R.C. at 61,228; see also Cal. Pet’rs Opening Br. 42-43. Given the level of deference we grant FERC, the “indisputabl[e]” differences between Arizona and California’s rates as illustrated by the dekatherm-mileage study, ALJ Op., 139 F.E.R.C. at 66,228 , El Paso’s failure to provide substantial evidence illustrating any uniqueness of Arizona’s laterals as compared to laterals all over the southern portion of the system, and the lack of other empirical evidence supporting equilibration, we find FERC did not act arbitrarily or capriciously in finding El Paso failed to meet its burden. In evaluating equilibration, FERC was faced with a new, unapproved practice for the pipeline. FERC pointed to clear findings by the ALJ that El Paso’s dekatherm-mileage study -which California Petitioners do not attempt to discredit -“indisputably generates different average mileages for the California and Arizona zones,” FERC Br. 65 (quoting ALJ Op., 31 139 F.E.R.C. at 66,228), and El Paso proffered no comparably detailed study, empirical cost comparison, or other analysis undermining that finding, see Op. 528, 145 F.E.R.C. at 61,227. FERC, limited to the record before it, reasonably found that “based on the evidence in this proceeding, El Paso did not show that its equilibration proposal would result in just and reasonable rates.” Id. at 61,228. FERC acknowledged the cost of Arizona’s laterals and other state-specific programs, but reasonably found these expenses were “offset by other factors including the integrated manner in which El Paso operates its system, the mechanisms El Paso has to address costs associated with the non-ratable deliveries of gas, and significantly discounted rates for deliveries to California.” Id. at 61,227. Perhaps, as FERC noted, id. at 61,227-28, a zone-of-delivery rate design with only two east-west zones could have been developed with the appropriate evidentiary support. However, it was reasonable to find that an equilibration of this nature was not supported by the dekatherm-mileage study or other equally substantive evidence in the record, and thus could not be deemed just and reasonable in this proceeding. Additionally, FERC reasonably found Tennessee Gas distinguishable because, unlike in that case where the laterals were limited to the New England zone, El Paso’s laterals run across at least three southern states, not just through Arizona, and El Paso provided no empirical cost comparison or analysis justifying recalibrating solely the Arizona rates in this way. See id. at 61,228. Next, California Petitioners argue that by approving a zone-of-delivery design but rejecting equilibration, FERC adopted a rate of its own making that was “substantially different from El Paso’s proposal and that overstates the effect of distance on rates.” Cal. Pet’rs Opening Br. 44. They assert that although the zone-of-delivery method has been in effect on the pipeline for over 50 years, FERC has never approved the 32 contract path methodology for measuring those zones, so its partial approval was not an approval of the status quo but a rate of its own design. Id. at 44. Such action, they argue, converted this from a proceeding under Section 4, 15 U.S.C. § 717c, to a proceeding under Section 5, id. § 717d, compelling FERC to consider alternative rate proposals, including California’s proposed “postage-stamp rate” methodology (i.e., a nondistance sensitive rate). Cal. Pet’rs Opening Br. 44-50. Section 4 of the NGA “limits [FERC] to two courses of action [in ruling on a ratemaking proposal], ‘acceptance (in whole or part) or rejection of the pipeline’s proposed rates.’” W. Res., Inc. v. FERC, 9 F.3d 1568, 1574 (D.C. Cir. 1993) (quoting Sea Robin Pipeline Co. v. FERC, 795 F.2d 182, 183 (D.C. Cir. 1986)) (emphasis added). If the rate imposed by FERC “differs significantly” from the rate proposed by the pipeline, it can no longer be attributed to the pipeline or qualify for Section 4 treatment, and the proceeding must be conducted pursuant to Section 5. Id. at 1579. Section 5 requires a showing that: (1) the pipeline failed to show its proposed rate was just and reasonable under Section 4; (2) the default position, the prior rate, is no longer just and reasonable; and (3) FERC’s substitute rate is itself just and reasonable. Id. Under this Court’s precedents, FERC can alter a proposed rate and remain in a Section 4 proceeding as long as its change represents “at least partial approval of the change” for which the pipeline itself petitioned. Pub. Serv. Comm’n of N.Y. v. FERC, 642 F.2d 1335, 1345 (D.C. Cir. 1980). But this Court has rejected FERC’s argument that Section 4 permits it to approve any rate, no matter how materially different from that proposed by the pipeline, so long as it can be viewed as a “part” of the original request. W. Res., Inc., 9 F.3d at 1579 (finding FERC proposed a rate that “differed substantially” from its old rates by “employ[ing] a completely different strategy in quantifying distinctions between the two kinds of service” and 33 adding a “50% backhaul rate”). Despite California Petitioners’ assertions, it seems clear FERC approved “part” of the proposed rate design without “differ[ing] substantially” from El Paso’s proposal. Id. Unlike in Western Reserve where a novel methodology and rate calculation schema were imposed by FERC, in approving the zone-of-delivery design but rejecting the additional step of equilibration, FERC simply left a version of El Paso’s preexisting methodology in place and rejected slight changes to rates in California and Arizona. See Op. 528-A, 154 F.E.R.C. at 61,682. Although this is the first time FERC has approved the use of contract paths as a measurement tool for the cost of transporting gas to the zones (El Paso proposed the contract path methodology in its prior two rate cases, but both resulted in settlements, see id.), this is merely a measurement tool further supporting the five zones that have long been part of El Paso’s rate design. The approved rate design simply does not differ so substantially from El Paso’s original proposal that the proceeding must now stand scrutiny under Section 5. Thus, FERC was correct in finding it unnecessary to consider alternative rate proposals, including California Petitioners’ preferred postage-stamp methodology. Under Section 4, if a pipeline’s proposal is just and reasonable, FERC must accept it (in whole or in part), regardless of whether other just and reasonable rates might exist. See W. Res., Inc., 9 F.3d at 1578. As discussed above, California Petitioners made no showing that El Paso’s proposed rates were unjust or unreasonable, and as such there was no basis to consider alternative rate designs under Section 5. See 15 U.S.C. § 717d; see also Elec. Power Supply Ass’n, 136 S. Ct. at 784 (stating it is “not [the court’s] job” to supplant FERC’s reasoned, explained choice of rate). 34 V. For the foregoing reasons, the petitions for review are Denied.
Primary Holding
Petitions for review challenging five FERC orders on two intertwined El Paso rate cases under the Natural Gas Act denied.

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