Louisiana Intrastate Gas Corp. v. Federal Energy Regulatory Commission

962 F.2d 37, 295 U.S. App. D.C. 228, 1992 U.S. App. LEXIS 7586

• Court: Court of Appeals for the D.C. Circuit
• Decided: April 24, 1992
• Docket: Nos. 89-1479, 90-1050, 90-1476
• Status: Published

Opinion

Opinion for the Court filed by Circuit Judge EDWARDS.

HARRY T. EDWARDS, Circuit Judge:

The Louisiana Intrastate Gas Corporation (“LIG”) petitions for review of rate-making orders that were issued by the Federal Energy Regulatory Commission (“FERC” or the “Commission”) pursuant to the Natural Gas Policy Act of 1978 (“NGPA”), 15 U.S.C. §§ 3301-3432 (1988). These orders fixed a rate for natural gas transportation through the Eloi Bay line, a stand-alone facility owned by LIG, and a separate rate for the rest of LIG’s pipeline system. The Commission calculated the Eloi Bay rate by dividing the facility’s costs into a “rate design volume.”

Petitioner advances two valid arguments concerning the Eloi Bay rate. First, the Commission has failed to explain why Eloi Bay is not exempt from the NGPA as a “gathering” facility. Second, the Commission has failed to justify the “rate design volume,” which was set at 90% of the line’s capacity. Thus, we vacate the Eloi Bay rate and remand for the Commission to reconsider these two issues. Petitioner also challenges FERC’s decision to award a full refund to non-Eloi Bay customers, but this challenge lacks merit.

I.Background

For many years, the Natural Gas Act ("NGA”), 15 U.S.C. §§ 717-717z (1988), has governed the interstate transportation of natural gas. FERC now administers this statute. Pursuant to the NGA, an interstate pipeline must obtain a “certificate of public convenience and necessity” from FERC, id. § 717f, and transportation rates must be “just and reasonable,” id. § 717c.

In promulgating the NGPA, Congress sought to facilitate the entry of intra state pipelines into the interstate market. Section 311(a)(2) of the NGPA permits the Commission to “authorize any intrastate pipeline to transport natural gas on behalf of — (i) any interstate pipeline; and (ii) any local distribution company served by any interstate pipeline.” 15 U.S.C. § 3371(a)(2)(A) (1988). An “intrastate pipeline” is defined as “any person engaged in natural gas transportation (not including gathering) which is not subject to the jurisdiction of the Commission under the Natural Gas Act.” Id. § 3301(16). Crucially, the intrastate pipeline need not obtain a NGA certificate for § 311(a)(2) transportation. Moreover, § 311(a)(2) rates must be “fair and equitable” instead of “just and reasonable”:

The rates and charges of any intrastate pipeline with respect to any transportation authorized under [§ 311(a)(2)] ... shall be fair and equitable and may not exceed an amount which is reasonably comparable to the rates and charges which interstate pipelines would be permitted to charge for providing similar transportation service.

Id. § 3371(a)(2)(B)(i).¹

The instant case concerns the Louisiana Intrastate Gas Corporation, a pipeline company accurately described by its name. All of LIG’s lines are inside Louisiana, and most are joined together to form an onshore grid. LIG also has a stand-alone facility that connects offshore gas fields to pipelines owned by other companies. The stand-alone, or so-called “Eloi Bay,” facility was built in 1984; it consists of a large-diameter line that is 22 miles long, as well as a short spur linked to this line.

LIG has been engaged in § 311(a)(2) transportation through its onshore grid since the early 1980s. In 1986, FERC approved a rate of 22.4 cents per MMBtu² for § 311(a)(2) transportation anywhere in the LIG system,³ and required the company to refile for rate approval no later than March 1988. LIG did so, and then, in December 1988, reached an agreement with its § 311(a)(2) customers (the “Settlement”), which fixed a new rate of 21 cents per MMBtu. The Settlement did not specify LIG’s refund obligation for the period between March and December 1988, during which time LIG had collected a higher rate.

Prior to these events, LIG had only provided intrastate transportation on its Eloi Bay facility, not § 311(a)(2) transportation. However, shortly after the Settlement was filed with FERC, the Prairie Producing Company (“Prairie”) and several other Eloi Bay customers requested § 311(a)(2) transportation. At the same time, Prairie protested to FERC that the Settlement rate of 21 cents per MMBtu should not apply to the Eloi Bay line, which was segregated from the rest of the LIG system. Meanwhile, LIG petitioned FERC to approve a § 311(a)(2) rate for Prairie and other Eloi Bay customers, and commenced § 311(a)(2) transportation for them.

FERC agreed with Prairie that an incremental rate was appropriate for the Eloi Bay facility. The Commission approved the Settlement for purposes of non-Eloi Bay transportation; directed LIG to refund its non-Eloi Bay customers the full difference between the collected rate and the Settlement rate; and instituted a ratemaking proceeding for Eloi Bay. See Louisiana Intrastate Gas Corp., 47 FERC ¶ 61,-042 (Apr. 10, 1989) (“First Order”). In justifying a full refund, FERC stated that “LIG’s prior settlement [in 1986] required LIG to refile for a general system-wide rate on or before March 1,1988 and specifically stated that all rates collected on or after the date of such application and pending final Commission approval shall be subject to refund (emphasis added).” Id. at 61,119.

LIG requested rehearing on various grounds, inter alia that Eloi Bay might be a “gathering” line exempt from FERC’s jurisdiction under the NGPA. The request for rehearing was denied. See Louisiana Intrastate Gas Corp., 47 FERC ¶ 61,336 (June 7, 1989) (“First Rehearing Denial”). FERC responded to the “gathering” claim, but in a brief and cryptic fashion: “The issue of whether a pipeline is a gathering system is not relevant to this section 311 proceeding since the service is being performed by LIG as an intrastate pipeline under NGPA section 311.” Id. at 62,157.⁴ LIG raised the “gathering” claim again in a further rehearing request, and the Commission gave a different reply. See Louisiana Intrastate Gas Corp., 50 FERC ¶ 61,011 (Jan. 10,1990) (“Second Order”). FERC no longer asserted that “gathering” was an irrelevant issue, but, rather, that Eloi Bay was not in fact a “gathering” line, because “LIG has consistently treated [the Eloi Bay] facility as a transmission facility.” Id. at 61,026.

We note that an order of the Louisiana Office of Conservation granted LIG the authority to construct and operate the Eloi Pipeline as requested in its application for “the transportation of natural gas.” Additionally, the 1985 transportation agreement between LIG and Prairie under which LIG initiated service for Prairie on the Eloi Pipeline states that the rate for the intrastate transportation service shall be the rate charged by LIG for transportation service under section 311. Finally, the fact that LIG filed petitions for rate approval in the referenced dockets to perform section 311 transportation for Prairie indicates that LIG itself has acknowledged that the Eloi system is used to perform transportation services.

Id. (footnotes omitted).

The Second Order set a rate of 2.85 cents per MMBtu for § 311(a)(2) transportation on the Eloi Bay line. This rate, which putatively reflected LIG’s “cost of service,” was much lower than what the company proposed. FERC had calculated the yearly Eloi Bay costs, including operating expenses, depreciation, debt service and return on equity, and had then divided this figure by a “rate design volume.” The rate design volume was set at 90% of the line’s capacity, even though the actual throughput was almost five times lower.⁵ The Commission’s justification for this figure was as follows:

[Transportation rates for facilities built after 1978 should place the risk of underutilization on the intrastate pipeline, rather than the interstate customers____ Our concern is that an intrastate pipeline might unwisely expand its facilities based on overly optimistic expectations of future throughput, since it knows that even if the facility is not fully utilized it can pass on all the costs to interstate customers.

Id. at 61,025 (internal quotation omitted).

LIG requested rehearing. The company contended that the rate design volume should use actual throughput instead of capacity, and, in the alternative, cited Commission precedent for a capacity percentage lower than 90%. However, FERC refused to change the rate design volume. See Louisiana Intrastate Gas Corp., 52 FERC ¶ 61,297 (Sept. 19, 1990) (“Second Rehearing Denial”). The Commission again articulated at length its justification for a capacity-based rate design volume, see id. at 62,190-94, and purported to rely on Lear Petroleum Corporation, 42 FERC 1161,015 (1988), as authority for the 90% figure. The final Eloi Bay rate was set at 3.37 cents per MMBtu.⁶

II. Analysis

In these petitions for review of the rate-making orders,⁷ LIG presents numerous challenges to the Eloi Bay rate. Only two of the claims presented by LIG raise genuine issues: (1) that Eloi Bay is exempt from § 311(a)(2) as a “gathering” facility, and (2) that FERC should not have used 90% of capacity as the rate design volume.⁸

Petitioner also argues that FERC should not have ordered a full refund for the nonEloi Bay customers, but this argument is unworthy of a protracted response. The Commission rested its refund decision on several grounds, inter alia that LIG had previously agreed to a full refund. Petitioner’s briefs do not contest this factual finding or its legal sufficiency. See Syracuse Peace Council v. FCC, 867 F.2d 654, 657 (D.C.Cir.1989) (“if an agency relies on two grounds for a decision, a court may sustain it if one is valid and if the agency would clearly have acted on that ground even if the other were unavailable”), cert. denied, 493 U.S. 1019, 110 S.Ct. 717, 107 L.Ed.2d 737 (1990). Accordingly, we reject LIG’s claim contesting the full refund for the non-Eloi Bay customers.

We turn now to the “gathering” issue and the question concerning the rate design volume.

A. The “Gathering” Issue

At the outset, we reject respondent’s claim that LIG failed to preserve the “gathering” issue. The NGPA stipulates that “[n]o objection to [an] order of the Commission shall be considered by the [reviewing] court if such objection was not urged before the Commission in the application for rehearing unless there was reasonable ground for the failure to do so.” 15 U.S.C. § 3416(a)(4) (1988); see id. § 717r(b) (substantially identical language under NGA). An “objection” must be “specifically urge[d],” Office of the Consumers’ Counsel v. FERC, 914 F.2d 290, 295 (D.C.Cir.1990) (NGPA); see 15 U.S.C. § 3416(a)(2) (1988), and LIG did just that in its rehearing request. LIG argued to the Commission:

If the Eloi Bay segment is found to be a discrete and separate part of the LIG system, then two further issues should then be addressed. First, is the 21.9 mile segment in reality a gathering line exempt from both NGA and NGPA rate regulation?

Request for Rehearing [of First Order] at 12, reprinted in Deferred Appendix 137, 148. This statement was adequately specific to “put the Commission on notice of the ground on which rehearing was being sought”⁹ — as evidenced by the fact that FERC responded on the merits.¹⁰ See Public Serv. Comm’n of New York v. FERC, 866 F.2d 487, 493 (D.C.Cir.1989) (finding even brief assertion sufficient for NGA exhaustion); Consolidated Gas Supply Corp. v. FERC, 606 F.2d 323, 327 (D.C.Cir.1979) (same), cert. denied, 444 U.S. 1073, 100 S.Ct. 1018, 62 L.Ed.2d 755 (1980).

The First Rehearing Denial stated that the “gathering” issue was irrelevant. See 47 FERC ¶ 61,336, at 62,157. Apparently, the Commission was interpreting the NGPA to cover a “gathering” facility if that facility belonged to an intrastate pipeline company that also owned covered “transportation” facilities. However, Commission counsel made clear at oral argument that FERC no longer advances this interpretation as a basis for § 311(a)(2) jurisdiction over Eloi Bay. Thus, we need not decide whether the interpretation is valid.

Rather, respondent relies solely on the Second Order, which stated that the Eloi Bay line was not a “gathering” facility because LIG had characterized Eloi Bay as a “transportation” line. See 50 FERC 1161,011, at 61,026. But we fail to understand why this characterization shows the facility’s status. In short, we can find no “substantial evidence” to justify FERC’s conclusion on the “gathering” issue. See 15 U.S.C. § 3416(a)(4) (1988) (“substantial evidence” standard for judicial review of factual findings under NGPA).

In determining whether a facility falls within the “gathering” exemption to the NGA,¹¹ the Commission generally focuses on the “primary function” of the facility. See Farmland Indus., Inc., 23 FERC 1161,-063 (1983). Thus, it is said that:

the ultimate test is whether the primary function of the facility can be classified as transportation or gathering. Several indicia of this test include: 1) the diameter and length of the facility, 2) the location of compressors and processing plants, 3) the extension of the facility beyond the central point in the field, 4) the location of wells along all or part of the facility, and 5) the geographical configuration of the system.

Id. at 61,143; see also Amerada Hess Corp., 52 FERC 1161,268, at 61,987-88 (1990) (modifying Farmland by considering “changing technical and geographic nature of exploration and production,” and noting relevance of “nonphysical criteria such as the purpose, location and operation of the facility”). It appears that FERC also applies the Farmland/Amerada test to cases arising under the NGPA. See, e.g., Sandy Hook Pipeline, Inc., 58 FERC 1161,179 (1992); Tekas Corp., 54 FERC 11 61,045 (1991).

Given the applicability of the “primary function” test, which is not in dispute here, the facts cited by FERC — that “the 1985 transportation agreement between LIG and Prairie ... states that the rate for the intrastate transportation service shall be the [§ 311(a)(2)] rate,” Second Order, 50 FERC 1161,011, at 61,026, and that “LIG filed petitions for rate approval in the referenced dockets to perform section 311 transportation for Prairie,” id. — have little or no relevance to the issue at hand.¹² The labels that a party uses to commence a rate proceeding can hardly furnish the factual predicate for a judgment as to whether the primary function of a facility is “transportation” or “gathering.” See Sandy Hook, 58 FERC ¶ 61,179 (“gathering” facility exempted from § 311(a)(2) jurisdiction after petition for rate approval was filed); TEX/ CON Gas Pipeline Co., 53 FERC 1161,316 (1990) (same); South Tex. Gathering Co., 27 FERC If 61,440 (1984) (anticipating that “gathering” facility might be thus exempted); J-W Gathering Co., 21 FERC II 61,088 (1982) (same). “It is the responsibility of the reviewing court, in determining if the Commission’s factual conclusions are supported by substantial evidence, to assure itself that the Commission has given reasoned consideration to each of the pertinent factors.” Office of Consumers’ Counsel v. FERC, 783 F.2d 206, 227 (D.C.Cir.1986) (internal quotation omitted) (emphasis in original). FERC’s decision on the “gathering” issue is totally devoid of “reasoned consideration”; we therefore remand for reconsideration.

B. Rate Design Volume

The rates set by FERC under § 311(a)(2) must be “fair and equitable.” We need not decide in this case whether “fair and equitable” rates are substantively different from “just and reasonable” rates. Rather, we hold that the Eloi Bay rate is invalid because FERC failed to engage in the “reasoned consideration [that] is the ultimate issue in judicial review of agency determinations.” Offcie of Consumers’ Counsel v. FERC, 783 F.2d 206, 227 (D.C.Cir.1986) (internal quotation and bracket omitted).

In setting the rate design volume for Eloi Bay, the Commission made two implicit choices. The first was to use pipeline capacity rather than actual throughput, either historical or projected. The second was to use 90% as the capacity percentage. Only the first choice was fully reasoned.

As FERC explained in the Second Order, see 50 FERC 1161,011, at 61,025, and again at greater length in the Second Rehearing Denial, see 52 FERC 1161,297, at 62,190-94, a § 311(a)(2) rate design volume based solely on actual throughput might encourage overbuilding by intrastate pipeline companies, because the company might reason that its § 311(a)(2) customers would bear the cost of extra capacity. And the Commission could rationally respond to this phenomenon by refusing to lower the rate design volume beneath some threshold that represents the normal undercapacity of a well-designed pipeline. We have previously acknowledged that capacity-based rates are rational, and we do so again here. See Moraine Pipeline Co. v. FERC, 906 F.2d 5 (D.C.Cir.1990) (certificate for NGA facility can include capacity condition); Tennessee Gas Pipeline Co. v. FERC, 689 F.2d 212 (D.C.Cir.1982) (same).

LIG contended that a capacity-based rate design volume was inconsistent with normal NGA practice, but FERC fully answered this contention:

Because the Commission has no statutory authority to issue certificates approving the construction of intrastate pipelines (as opposed to the construction of interstate pipelines pursuant to NGA ... certificates), the Commission must be doubly careful in its ratemaking decisions to protect the interstate ratepayer from paying excessive section 311 transportation costs.

Second Rehearing Denial, 52 FERC 1161,297, at 62,193 (citing Lear Petroleum Corporation, 42 FERC ¶ 61,015 (1988), and-similar FERC cases). LIG also pointed to prior NGPA case law, but identified only one decision where FERC articulated a different rate-design methodology than here. In Mustang Fuel Corporation, 31 FERC 1161,265 (1985), reh’g granted in part, 36 FERC II 61,001 (1986), review granted in part sub nom. Mustang Energy Corp. v. FERC, 859 F.2d 1447 (10th Cir.1988), cert. denied, 490 U.S. 1019, 109 S.Ct. 1743, 104 L.Ed.2d 180 (1989), the Commission declined to base a § 311(a)(2) rate on originally-projected rather than currently-projected volumes, because the first approach “unnecessarily shifts most of the risk of underutilization ... to [the intrastate pipeline].” 31 FERC 1161,265, at 61,531. However, most of the Mustang facilities were built for intrastate service, not § 311(a)(2) service, and the Mustang decision is explicitly predicated on this fact. See id. at 61,530-31. As FERC stated in the Second Order, “transportation rates for facilities built after 1978 [the date of the NGPA] should place the risk of underutilization on the intrastate pipeline,” because companies could have anticipated § 311(a)(2) authorization for such facilities. 50 FERC 1161,-011, at 61,025 (emphasis added). Thus, the Commission adequately distinguished Mustang, whatever its obligation to do so.

In short, FERC’s choice of a capacity-based rate design volume was adequately reasoned. But its choice of the capacity percentage was not. On this issue, FERC merely cited Lear Petroleum Corporation, 42 FERC 1161,015 (1988). See Second Order, 50 FERC 1161,011, at 61,025. In Lear, the Commission had arrived at a 90% figure by reasoning that a particular facility should be fully utilized and then allowing 10% downtime for maintenance. See 42 FERC ¶ 61,015, at 61,053-57. However, as LIG rightly noted in its rehearing request, Lear was followed by Delhi Gas Pipeline Corp., 43 FERC If 61,024 (1988), which used an 87%-of-capacity rate design volume. The numerical difference between 87% and 90% is not terribly significant, but the methodological difference is.

The Commission based the rates in Lear Petroleum Co. on 90 percent of peak day design capacity, in order to reflect the company’s downtime for maintenance.

The record in the instant proceeding contains no evidence indicating the percentage of downtime. However, the Commission believes that there is a better measure of the appropriate use of the pipeline’s capacity. Because all the pipelines [here] act essentially as gathering systems, the percentage of capacity throughput to be used in setting Delhi’s Section 311 transportation rates logically should relate to the capacity output of the wells which the [pipelines were] built to service. Properly designed, these pipelines should be able to move all the production of the wells connected to them.

Delhi, 43 FERC 1161,024, at 61,070-71 (footnote omitted) (emphasis added).

FERC did not explain why Lear’s methodology was applicable rather than Delhi’s. The Commission also ignored 18 C.F.R. § 2.65, which was cited by LIG and specifies a 60% -of-capacity condition for NGA certificates granted to pipeline facilities in the southern Louisiana offshore area. Although “[t]here is no question that the Commission may attach precedential, and even controlling weight to principles developed in one proceeding and then apply them under appropriate circumstances in a stare decisis manner,” the Commission should only do so if “the factual composition of the case to which the principle is being applied bear[s] something more than a modicum of similarity to the case from which the principle derives.” Michigan Wis. Pipe Line Co. v. Federal Power Comm’n, 520 F.2d 84, 89 (D.C.Cir.1975). In the proceedings below, FERC should not have relied on Lear as authority without explaining why that precedent was on point. There is no obvious reason to justify FERC’s decision; indeed, it appears patently arbitrary and irrational in some critical respects.¹³ Accordingly, we direct the Commission to reconsider its decision to use 90% of capacity as the rate design volume for Eloi Bay.

III. Conclusion

The petitions are granted in part and denied in part. We uphold FERC’s decision to award a full refund to non-Eloi Bay customers. However, we vacate FERC’s rate for the Eloi Bay facility and remand the case for further proceedings concerning that rate. On remand, the Commission must reconsider whether Eloi Bay is a “gathering” facility exempt from the NGPA. Then, if the facility is not exempt, the Commission may set an incremental rate for the facility and may use a capacity-based rate design volume, but must reexamine whether the 90% figure used in Lear is truly appropriate here.

1 . The history and purpose of the NGPA are more fully described in Associated Gas Distributors v. FERC, 899 F.2d 1250, 1253-56 (D.C.Cir.1990).

2 . "MMBtu” stands for "million British thermal units.”

3 .There was also an incremental rate for transportation on the “East Moore Sams” portion of the LIG system.

4 . In a footnote, the Commission paraphrased the NGPA’s definition of "intrastate pipeline.”

5 . See id. at 61,027 (LIG’s calculation).

6 . In its rehearing request, LIG argued that the Commission was underestimating the costs associated with Eloi Bay, and FERC responded by raising the rate from 2.85 cents to 3.37 cents per MMBtu.

7 . The instant petitions cover four FERC orders: the First Order, First Rehearing Denial, Second Order and Second Rehearing Denial.

8 . In addition, petitioner contends that: (1) FERC should have held a hearing to decide whether the Eloi Bay facility merited an incremental rate; (2) Prairie should have had the burden of proving that the "existing” rate of 22.4 cents per MMBtu was inappropriate for the facility; (3) FERC should not have used a 15-company sample to calculate the facility’s cost of debt and return on equity; (4) the Eloi Bay rate is confiscatory; and (5) the Eloi Bay customers should not have received a full refund.

The first contention fails because petitioner does not identify disputed facts that were material to FERC’s decision. See, e.g., Kansas Power & Light Co. v. FERC, 851 F.2d 1479, 1483-84 (D.C.Cir.1988). Similarly, the burden-of-proof claim is a red herring, because petitioner does not argue that the undisputed facts were insufficient to sustain Prairie's burden: Eloi Bay is segregated from the rest of the LIG system. Finally, the Commission did not actually use the 15-company sample to calculate cost of debt, see Second Order, 50 FERC ¶ 61,011, at 61,023-24, while the return on equity was higher than LIG's proposal, see id. We need not address the fourth or fifth contentions, since we vacate the Eloi Bay rate and do so on nonconstitutional grounds.

9 . City of Farmington v. FERC, 820 F.2d 1308, 1311 n. 1 (D.C.Cir.1987).

10 . See First Rehearing Denial, 47 FERC ¶ 61,336, at 62,157; cf. Columbia Gas Transmission Corp. v. FERC, 750 F.2d 105, 110 n. 7 (D.C.Cir.1984) (nothing to indicate doubt by Commission or court that petitioner’s "succinct” objection was sufficient to raise issue in request for rehearing).

11 . "The provisions of [the NGA] ... shall not apply to ... the production or gathering of natural gas.” 15 U.S.C. § 717(b) (1988).

12 .FERC also noted that “an order of the Louisiana Office of Conservation granted LIG the authority to construct and operate the Eloi Pipeline as requested in its application for ‘the transportation of natural gas.’” Id. Assuming, arguendo, that FERC was here relying on Louisiana’s characterization of Eloi Bay rather than LIG’s, that was arbitrary. In discussing whether Eloi Bay merited an incremental rate, the Commission had specifically deprecated Louisiana’s finding that Eloi Bay was an extension of the LIG system. See First Rehearing Denial, 47 FERC ¶ 61,336, at 62,157.

13 . For example, we do not understand why Lear’s "full utilization” approach makes regulatory sense, at least in certain circumstances. That approach might well encourage the under-building of pipelines. Imagine that a company is choosing between a 12-inch and a 14-inch pipeline, and that the latter involves no additional cost if the increment is unutilized; in other words, the cost of a fully utilized 12-inch line is essentially the same as the cost of a 14-inch line with 2 inches of unutilized capacity. In this scenario, a 14-inch line should be built: the 2 inches of extra capacity are free, and may serve to transport volumes that a 12-inch line could not handle. However, the Lear methodology gives the company a strong incentive against the larger line. If the company builds a fully utilized 12-inch line, it will recover all of its costs; if it builds a 14-inch line with 2 inches of unutilized capacity, it will recover only 73% of its costs (assuming that 73% is the ratio of the capacity of a 12-inch line to a 14-inch line).

Even assuming that FERC could rationally decide to have intrastate pipelines bear the full economic risk of § 311(a)(2) facilities, see Moraine, 906 F.2d at 9 (NGA certificate legitimately places full economic risk on pipeline); Associated Gas Distribs. v. FERC, 824 F.2d 981, 1030-38 (D.C.Cir.1987) (same), cert. denied, 485 U.S. 1006, 108 S.Ct. 1468, 99 L.Ed.2d 698 (1988), that does not dispose of the question here, because there may be a crucial difference between full utilization and full economic risk. If incremental capacity is costless to build and to maintain unutilized, then the economic risk of building that capacity is also zero. In such a case, FERC can place the full economic risk on the pipeline without requiring full utilization. Moraine upheld a full-utilization condition, but the equivaIence between full economic risk and full utilization was not challenged there.

We do not decide at this point that the full-utilization approach is impermissible, but we do require that FERC more fully consider and explain that approach if it is here adopted.