Natural Gas Pipeline Company of America v. Federal Energy Regulatory Commission

765 F.2d 1155, 247 U.S. App. D.C. 1, 1985 U.S. App. LEXIS 30780

• Court: Court of Appeals for the D.C. Circuit
• Decided: July 5, 1985
• Docket: 84-1351
• Status: Published

Opinion

WALD, Circuit Judge:

Natural Gas Pipeline Company of America (Natural) challenges an order of the Federal Energy Regulatory Commission that rejected Natural’s efforts to recover from its ratepayers, through its cost of service, about 13 million dollars Natural spent in pursuit of three unsuccessful gas supply projects. See Natural Gas Pipeline Co. of Am., 27 F.E.R.C. ¶ 61,201 (1984). Although Natural never achieved any natural gas production from these projects and ultimately abandoned its investments in them, Natural claims that it acted prudently in attempting to develop these new sources of supply in a time of natural gas shortages. According to Natural, it should therefore be allowed to recover certain costs from these projects, amortized over five years, from its ratepayers. Natural does not seek to include the project in its rate base and has thus forgone any return on its investment or recovery of debt. It seeks only its out-of-pocket costs.

The Commission replies that a utility may ordinarily recover the costs of natural gas production projects only if the projects are “used and useful” in serving the public and the project costs consequently qualify for inclusion in rate base. See, e.g., Tennessee Gas Pipeline Co. v. FERC, 606 F.2d 1094, 1109 & n. 53 (D.C.Cir.1979), cert. denied, 445 U.S. 920, 100 S.Ct. 1284, 63 L.Ed.2d 605 and 447 U.S. 922, 100 S.Ct. 3012, 65 L.Ed.2d 1113 (1980). Production projects that never produce any natural gas are not, in the Commission’s view, “used and useful” in this sense. Similarly, the Commission has refused to consider non-recurring capital expenditures for unconventional gas production projects that fail in early stages as operating expenses. It therefore will not allow recovery from ratepayers of those expenditures through a utility’s cost of service. Money lost on such projects thus generally comes out of a utility's approved rate of return. The Commission treats the costs of failed electrical generation projects differently, but it argues that the rationale for this policy does not apply to the natural gas industry. We find the Commission’s order to be a reasoned exercise of its discretion under section 4 of the Natural Gas Act, 15 U.S.C. § 717c. We therefore deny the petition for review.

I. Background

A. The Used and Useful Standard

The Natural Gas Act permits the Commission 1 to approve charges for natural gas subject to the Commission’s jurisdiction only if those charges are “just and reasonable.” Natural Gas Act, § 4(a), 15 U.S.C. § 717c(a). In reviewing rates to de cide whether they are just and reasonable, the Commission decides what the utility’s cost of service should be, assuming that the utility is prudently managed.- In calculating the utility’s cost of service, the Commission includes its operating expenses, depreciation expenses, taxes, and a reasonable return on the net valuation of the property devoted to the public service. See P. Garfield & W. Lovejoy, Public Utility Economics 56 (1964). The Commission decides what property is devoted to the public service by asking whether the property is “used and useful” in serving the public.

As this court has frequently noted, the “used and useful” standard derives from the Supreme Court’s opinion in Smyth v. Ames, 169 U.S. 466, 18 S.Ct. 418, 42 L.Ed. 819 (1898). 2 In Smyth,

the Supreme Court articulated the guiding principle that “the basis of all calculations as to the reasonableness of rates to be charged by a [public utility] must be the fair value of the property being used by it for the convenience of the public." [Smyth, 169 U.S. at 546, 18 S.Ct. at 434 (emphasis added).] Although methods for determining values of rate base items have evolved since Smyth v. Ames, the precept endures that an item may be included in a rate base only when it is “used and useful” in providing service. In other words, current rate payers should bear only legitimate costs of providing service to them. The [Commission] early adopted the “used and useful” standard and has not departed from it without careful consideration of the wisdom of requiring current rate payers to bear costs of providing future service.

Tennessee Gas Pipeline Co. v. FERC, 606 F.2d 1094, 1109 (D.C.Cir.1979) (footnotes omitted), cert. denied, 445 U.S. 920, 100 S.Ct. 1284, 63 L.Ed.2d 605 and 447 U.S. 922, 100 S.Ct. 3012, 65 L.Ed.2d 1113 (1980). In this case, Natural does not seek to include the challenged expenses in its rate base, on which the utility’s rate of return is calculated. That step would have the effect of allowing Natural a return on its investment in failed projects, which Natural does not seek. Instead, it wishes to amortize its out-of-pocket costs, without debt or carrying charges, over five years, and then add those amortized charges to its cost of service. Thus, over five years Natural would recover the disputed costs dollar for dollar from ratepayers. 3 Of course, the exclusion of debt and carrying charges means that Natural would not completely recover its real costs. The difference between those real costs and the charges Natural proposed to include in its cost of service would be paid out of Natural’s rate of return, and consequently would be borne by Natural’s shareholders. 4 Natural correctly points out that for this reason, its proposed rate shared the risk of the failed projects between shareholders and ratepayers.

In essence, Natural argues that it should be allowed to recover, through its cost of service, prudently incurred expenses for failed gas supply projects. Because Natural acted blamelessly in incurring these expenditures, it believes the expenditures should be included in the utility’s routine cost of service. The Commission maintains that the expenditures were not used and useful to ratepayers, and are properly seen as nonrecurring capital expenditures that, under Commission precedents, may not ordinarily be included in a utility’s cost of service. In the Commission’s view, they are therefore a risk to be shouldered by the shareholders.

B. Natural’s Proposed Rate Filing

Natural is a pipeline company which transports natural gas through an elaborate interstate system. Natural generally obtains natural gas from producers in southwestern and gulf coast states and transports the gas through its Amarillo and Gulf Coast pipelines to utilities and municipalities in the Chicago area and elsewhere in the midwest. See generally Natural Gas Pipeline Co. of Am., 27 F.E.R.C. ¶ 61,201 (1984) [hereinafter cited as FERC Op.), affg in part and modifying in part 9 F.E.R.C. U63,059 (A.L.J.1979) [hereinafter cited as ALJ Op.], reh’g denied, 28 F.E.R.C. H 61,020 (1984).

On June 30, 1978, Natural filed a proposal for a general rate increase with the Commission. On July 28, 1978 the Commission accepted the filing, suspended the rate increase, see 15 U.S.C. § 717c(e), and set the rate increase for hearing before an administrative law judge. See Natural Gas Pipeline Co. of Am., 4 F.E.R.C. H 61,089 (1978). The rate increase went into effect on December 1, 1978, subject to refunds the Commission might subsequently order.

Eighteen distributors of natural gas in the area served by Natural and one industrial user of natural gas intervened in the case. After numerous conferences, the parties agreed on all but three issues in the case, and the Commission approved a settlement reflecting that agreement. See 9 F.E.R.C. H 62,006 (1978). Two of the three remaining issues have since been independently settled; 5 the third issue is the one before us today.

That issue concerns Natural’s efforts to recover costs associated with three abandoned gas supply projects: a synthetic natural gas (“SNG”) facility in North Dakota (the Dunn County project), a liquified natural gas (“LNG”) project in Iran (the Kalin-gas project), and a pipeline to transport gas from Prudhoe Bay, Alaska, to the lower 48 states (the Gas Arctic project). Natural undertook these projects at a time when its supply of gas was steadily falling and serious natural gas shortages were believed to be imminent. See generally A. Tussing & C. Barlow, The Natural Gas Industry: Evolution, Structure, and Economics 62-91 (1984) ; Allison, Natural Gas Pricing: The Eternal Debate, 37 Baylor L.Rev. 1, 17-18 (1985) .

In 1973 and 1974, Natural acquired leases on coal-producing property in North Dakota and an option to purchase property on which a facility to produce SNG through a coal gasification process could be built. In 1976, however, the water commission in North Dakota voted to deny the proposed facility an essential water permit. Natural had prepared an environmental assessment to comply with various state and federal regulatory requirements, but passage of amendments to the Clean Air Act and the Surface Mining Control and Reclamation Act, as well as promulgation of new regulations, rendered much of the environmental assessment outdated. See FERC Op. at 61,376-77. Financing and design problems also surfaced. See ALJ Op. at 65,228. Confronted with these obstacles, Natural suspended work on the project. In this proceeding Natural seeks to recover approximately 1.474 million dollars it spent on environmental studies made obsolete by new legislation and regulations. See id. Natural reported to the Commission that it spent about 3 million dollars on “environmental and process-related” studies for the Dunn County project, id., and approximately 11.7 million dollars on the entire project, see FERC Op. at 61,377.

Natural’s involvement in the Kalingas project dates from 1975, when Natural joined a consortium of companies organized to produce natural gas from a field off the coast of Iran, liquefy the gas obtained, and export the LNG. Natural normally operates as a pipeline, not a producer, but Natural was apparently required to participate in production of the gas in order to obtain an option to purchase the liquefied natural gas produced. Natural initially paid 4.5 million dollars for an option to purchase a five percent interest in the project for an additional 3 million dollars. That additional 3 million dollars would also have purchased the right to a call of 400 million cubic feet per day of LNG from the project. See FERC Op. at 61,377; ALJ Op. at 65,225.

Within two years, the projected costs of the venture went up dramatically. Had Natural continued its participation in the project, it would probably have been required to triple its participation from five percent to fifteen percent, with corresponding increases in costs. At that time less costly sources of LNG began to appear on the horizon. In 1977 Natural decided to abandon the Kalingas project and forfeit its 4.5 million dollar deposit. Natural now seeks to recover that deposit and $244,824 in related administrative expenses. See FERC Op. at 61,377; ALJ Op. at 65,226; see also infra note 7.

From 1971 to 1977 Natural was involved in the Gas Arctic Northwest Project Study Group. That group, which included numerous energy companies, was principally formed to study various engineering, environmental, financial, and legal problems associated with construction of a pipeline from Prudhoe Bay, Alaska, to the lower 48 states. The Commission ultimately approved a pipeline along a route quite different from that initially proposed by the group. In approving that route, however, the Commission considered Arctic Gas studies explaining how various environmental problems raised by the pipeline could be overcome. 6 Natural requests reimbursement for about 6.7 million dollars spent on various studies submitted in support of the Gas Arctic proposed pipeline route.

C. The Administrative Decisions

The administrative law judge allowed Natural to recover the costs it claimed from the Dunn County project. He recognized that the Commission’s previous opinions had stressed an “established policy of disallowing the costs of unsuccessful alternate gas supply projects ... in jurisdictional rates,” AU Op. at 65,229 (quoting Northern Natural Gas Co., 4 F.E.R.C. ¶ 61,312 at 61,706 (1978) (further citations omitted)). He noted, however, that in Great Plains Gasification Associates, 9 F.E.R.C. ¶ 61,221 (1979), rev’d and remanded sub nom. Office of Consumers’ Counsel v. FERC, 655 F.2d 1132 (D.C.Cir. 1980), the Commission decided to permit recovery of costs on an SNG project, even before the project produced any gas. The administrative law judge concluded that the Commission’s Great Plains decision, read together with other Commission decisions, required him to allow the Dunn County project costs. See ALJ Op. at 65,-230. The administrative law judge also decided that Natural’s 4.5 million dollar deposit in the Kalingas project was, in effect, an advance payment for foreign gas. He interpreted Commission precedents to have “steadfastly denied [recovery of] any advance payments for foreign supplies,” AU Op. at 65,226, and therefore disallowed costs from the Kalingas project. 7 The administrative law judge further observed that many companies other than Natural had participated in the Gas Arctic project, and that costs resulting from the project should be treated in the same way for each participant. He accordingly concluded that recovery of these costs should be addressed in a future rulemaking, not an individual rate case, and therefore disallowed Natural’s Gas Arctic costs without prejudice to future recovery after such a rulemaking. See AU Op. at 65,227-28.

The Commission disallowed costs from all three projects. It rejected the administrative law judge’s allowance of the Dunn County project costs based on Great Plains for two reasons. First, Great Plains had permitted recovery of costs from a coal gasification plant only because that plant, unlike Natural’s proposed facility in Dunn County, had been formally approved by the Commission as a research, development, and demonstration plant. See 18 C.F.R. § 154.38(d)(5) (1984). Second, this court ultimately overturned the Commission’s allowance of costs in Great Plains, on the ground that the Commission lacked statutory authority to regulate and arrange financing for commercial SNG facilities before such faciliti-.s went into service. 8 See FERC Op. at 61,379. The Commission found that enforcement of its general policy prohibiting recovery of costs for natural gas plants that are not used and useful was particularly appropriate in cases involving SNG, since the Commission lacks jurisdiction to regulate the price at which pipelines sell such gas unless the gas is mixed with natural gas extracted from mineral deposits. See id. at 61,379-80. “The Commission’s concern is that if a project is successful, the pipeline will stand beyond the reach of Commission authority and reap the benefits, while if it is unsuccessful, ratepayers will be saddled with the loss.” Id. at 61,380 (citation omitted).

The Commission commented that it would also have lacked authority to regulate the price of any LNG produced from the Kalingas project sold outside the United States. 9 Similarly, the price charged for shipping LNG from the project to the United States would have been outside the Commission’s jurisdiction. The same considerations that led to disallowance of the Dunn County costs thus applied to the Ka-lingas plant. More fundamentally, the Commission concluded that the Dunn County and Kalingas projects were “highly speculative and any potential benefit to consumers was remote and uncertain.” FERC Op. at 61,381; see also id. at 61,379. The Commission declared that the risk of failure in such ventures was properly borne by shareholders rather than ratepayers. See id. at 61,381.

The Commission also noted that in two decisions issued after the administrative law judge’s decision in this case, the Commission had refused Gas Arctic participants permission to amortize costs associated with the projects. See id. at 61,381-82 (citing Michigan Wisconsin Pipeline Co., 13 F.E.R.C. ¶ 61,254 (1980); Columbia Gas Transmission Corp., 13 F.E.R.C. ¶ 61,102 at 61,222 (1980)). Thus, the concern the administrative law judge had expressed that project participants be treated similarly now supported outright denial of the costs, rather than postponement of the question to a general rulemaking. In Columbia Gas, a natural gas pipeline sought to amortize and include in cost of service some of its expenditures on the Gas Arctic project, and to include its remaining expenditures on the project in rate base. 13 F.E.R.C. at 61,222. The Commission decided that expenditures on the Gas Arctic project were not “used and useful” to ratepayers and were therefore not recoverable in either cost of service or rate base. Id. The Commission explained that:

Expenses incurred subsequent to [a filing with the Commission seeking a certificate approving a proposed pipeline] in pursuit of a certificate ultimately not granted are entrepreneurial in character and are not recoverable in rate base____ If a project fails and produces no new supply of gas, permitting the pipeline to include its expenditures in its rate base and amortize them through the cost of service would shift the risk from the stockholder to the ratepayer, although the pipeline receives a rate of return to compensate it for business risks. The used and useful principle does not permit the pipeline to shift the risk of loss by imposing the expense of the unsuccessful project upon its current ratepayers who have received no benefit from the project.

Id. The Commission found that the reasoning in Columbia Gas supporting denial of costs applied equally to Natural. See FERC Op. at 61,382.

This petition for review followed.

II. The Legality of the Commission’s Decision

A. The Commission’s Refusal to Apply the Prudence Standard

As the Commission noted in its opinion, it has long refused to include in regulated rates the costs of failed projects to develop new supplies of natural gas. In Texas Eastern Transmission Corp., 58 F.P.C. 2412 (1977), for example, the Commission commented that:

We have recently reaffirmed our established policy of disallowing the costs of unsuccessful alternate gas supply projects to be included in jurisdictional rates. In those cases we have held that, while we endorse such efforts as potentially beneficial to the interstate market, we view the risks associated with such efforts as properly borne by the shareholders and not the jurisdictional ratepayer.

Id. at 2422-23 (footnote omitted); see also Northern Natural Gas Co., 4 F.E.R.C. ¶ 61,312 at 61,705-06 (1978).

Transcontinental Gas Pipe Line Corp., 58 F.P.C. 2038 (1977), affd in relevant part and remanded on other grounds sub nom. Tennessee Gas Pipeline Co. v. FERC, 606 F.2d 1094 (D.C.Cir.1979), cert. denied, 445 U.S. 920, 100 S.Ct. 1284, 63 L.Ed.2d 605 and 447 U.S. 922, 100 S.Ct. 3012, 65 L.Ed.2d 1113 (1980), was among the cases in which the Commission disallowed expenses from unsuccessful alternate gas supply projects. In Transcontinental Gas, the pipeline sought to include expenses associated with four failed SNG plants in its rate base, or alternatively to amortize those expenses over five years and include the amortized expenses in the utility’s cost of service. The Commission rejected both proposals for essentially three reasons. First, the Commission had not approved the plants at issue as research, development, and demonstration projects. Thus, Commission decisions allowing inclusion in rate base of costs from such projects were inapposite. See id. at 2042-43. Second, “the obvious fact that these projects were unsuccessful removes them from that general precept that the costs of exotic supplies, whether SNG or LNG, are recouped along with a fair rate of return through the pipeline sales of such supplies." Id. at 2043 (emphasis added). Third, the Commission noted that it lacked authority to regulate the price of SNG. See supra note 8. Although in the Commission’s view, “that fact alone is not dispositive,” 58 F.P.C. at 2043, its lack of regulatory power was relevant because;

In that SNG projects are nonjurisdictional, the pipeline has the option to either sell the production in intrastate commerce so as to totally avoid Commission regulation or to obtain Commission certification of the transportation and/or sale of the SNG in interstate commerce. The potential for abuse by the pipeline is apparent ...: If the project is a success, it can choose to sell the SNG in intrastate commerce, but, if the project fails and produces no SNG, the pipeline merely includes the expenditures in rate base and amortizes them through the cost of service. No protection has been afforded the jurisdictional ratepayer under this scenario.

Id. The Commission concluded that:

Although we support further SNG development, the jurisdictional ratepaper should not bear the full risk____ Production of SNG by the pipeline is analogous to the production of natural gas by independent producers ... and the same shareholder risk should apply.

Id. at 2044. Finally, the Commission rejected Transcontinental’s offer of a settlement under which some of the disputed expenses would be included in the utility’s cost of service, but not in its rate base. “Although the cost to the consumer would obviously be less [under the cost of service proposal than under the rate base proposal, the cost to the consumer under the cost of service proposal] would nevertheless be more than what we have already determined to be the proper treatment, which is no recovery.” Id. at 2045.

This court found no difficulty in upholding this aspect of the Commission’s order. We explained that:

The Commission found that the expenditures were not “used and useful” in providing service and should not be charged to the rate payers. Since the projects did not produce any jurisdictional gas, this ruling clearly was a proper exercise of discretion____ These expenditures were prudent investments, argues [the pipe line]; however, for rate base inclusion expenditures must satisfy not only the necessary condition of prudent investment but must also be “used and useful” in providing service.

Tennessee Gas, 606 F.2d at 1123 (footnotes omitted). We therefore approved the Commission's rejection of both rate base treatment, id., and inclusion in cost of service, id. at 1124, for the expenses at issue. Cf. Tennessee Gas Pipeline Co. v. Federal Power Comm’n, 487 F.2d 1189, 1196-97 (D.C.Cir.1973) (upholding FPC’s interpretation of certificate for LNG plant to deny rate base treatment of unrecovered expenses when LNG plant failed to produce any gas).

In this case, Natural claims that it is entitled to amortization of the expenses of the abandoned projects if those expenses were prudently incurred. We think that our 1979 decision in Tennessee Gas forecloses so broad an argument. There, as here, a pipeline company sought to include expenses for failed gas supply projects in its cost of service on the ground that those expenses were prudently incurred. The Commission invoked the same general policy at issue in this case to refuse the pipeline’s request, and this court explicitly approved that policy. Admittedly, in the decision under review in Tennessee Gas, the Commission noted that if the pipeline had sold any SNG actually produced in intrastate commerce, the Commission would have lacked authority to regulate the price of that SNG. See Transcontinental Gas, 58 F.P.C. at 2043. In this case, one of the projects, the Kalingas project, was outside the United States and consequently beyond the Commission’s regulatory jurisdiction. Another, the Dunn County project, was an SNG facility and thus also beyond the Commission’s jurisdiction. The third project involved in this case, the Gas Arctic project, would if successful apparently have produced gas subject to at least some of the Commission’s regulatory powers. 10 Thus, if Tennessee Gas turned on the Commission’s lack of authority to regulate SNG not commingled with other natural gas, the case might not control our disposition of the Gas Arctic expenses here.

As we have already noted, the Commission’s order we reviewed in Tennessee Gas explicitly stated that the nonjurisdictional character of SNG was “not dispositive.” Transcontinental Gas, 58 F.P.C. at 2043. More importantly, this court’s discussion of the Commission’s ruling attached no importance at all to this subsidiary aspect of the Commission’s ruling: instead, we approved the Commission’s general policy that “current rate payers should bear only legitimate costs of providing service to them.” Tennessee Gas, 606 F.2d at 1109. The Commission, we found, could reasonably apply that policy to deny a natural gas pipeline any recovery of costs from supply projects that entirely failed to benefit ratepayers. See id. at 1123-24. That rationale applies equally to the case at hand.

In any event, we think the approach taken in Tennessee Gas yields a sensible result in this case. At bottom, Natural’s claim is that because it acted prudently, it cannot fairly be punished by nonreeovery of its expenses. But the problem of risk allocation in this case is not a problem of fault. The Commission did not find that the disputed expenditures were imprudent, and we therefore assume that the natural gas pipeline and its ratepayers were equally blameless for the losses at issue. That assumption, however, need not lead to the conclusion that Natural’s ratepayers must, through the utility’s cost of service, make good on all or any part of the money Natural lost. The Natural Gas Act simply does not guarantee the shareholders of even a prudently managed utility that ratepayers can always be stuck with the bill for supply projects that turn out to be total failures, however praiseworthy the utility’s motives for undertaking those projects may have been. In reviewing rates, we ask whether the Commission reasonably found that the rates may “be expected to maintain financial integrity, attract necessary capital, and fairly compensate investors for the risks they have assumed, and yet provide appropriate protection to the relevant public interests, both existing and foreseeable. The court’s responsibility is not to supplant the Commission’s balance of these interests with one more nearly to its liking, but instead to assure itself that the Commission has given reasoned consideration to each of the pertinent factors.” Permian Basin Area Rate Cases, 390 U.S. 747, 792, 88 S.Ct. 1344,1373, 20 L.Ed.2d 312 (1968). 11 In this case, the Commission in effect decided that the public interest in seeing that ratepayers do not pay for services not received was dispositive. While the Commission might have struck the balance otherwise, 12 we are unable to say that its judgment was arbitrary. Moreover, Natural does not even argue that the resulting rates are outside the “zone of reasonableness,” Federal Power Comm’n v. Natural Gas Pipeline Co., 315 U.S. 575, 585, 62 S.Ct. 736, 742, 86 L.Ed. 1037 (1982), within which the Commission may fix rates. We accordingly reject Natural’s suggestion that the questioned rates were unlawful merely because the Commission refused to include the expenses at issue in calculating Natural’s cost of service.

B. Natural’s Claim of Inconsistent Treatment

Natural also argues that the Commission’s disallowance of costs in this case is inconsistent with Commission decisions allowing recovery of costs for unsuccessful pipeline storage projects, dry holes drilled by natural gas producers, and unsuccessful electrical generation projects. 13

In Southern Natural Gas Co., 29 F.P.C. 323 (1963), the Commission permitted a natural gas company to include the cost of failed gas storage projects in its cost of service. The Commission commented that “the search for storage is an activity properly related to Southern’s pipeline operations.” Id. at 331; see also Northern Natural Gas Co., 45 F.P.C. 1050 (1971) (permitting utility to recover costs of abandoned storage project over five years). The Commission has explained that it permitted amortization of losses on these storage projects because the projects “represented an effort on behalf of the companies to improve the quality and quantity of service systemwide. These were not individual projects of a short duration intended for the benefit of a small group of customers to meet a special service requirement.” Tennessee Gas Pipeline Co., 48 F.P.C. 149, 159 (1972), aff'd, 487 F.2d 1189 (D.C.Cir. 1973). Natural asserts that its failed gas supply projects were also efforts “to improve the quality and quantity of service system-wide.” The Commission replies that it treats expenses for storage projects as “recurring costs associated with a continuing search for storage,” rather than “non-recurring costs associated with an unsuccessful project.” FERC Br. at 16 (emphasis deleted); cf. Southern Natural Gas, 29 F.P.C. at 331-32 (suggesting that storage costs at issue were properly regarded as recurring).

In essence, the Commission treats the expenses of failed storage projects as a kind of recurring operating expense. Pipelines must have storage facilities, and efforts to find and secure those facilities are essential to maintaining the ordinary equipment of a pipeline company. Production activities are fundamentally different. It may be prudent and even necessary for pipelines to enter the production business, as Natural did in the three ventures at issue here, if the pipeline’s suppliers appear unable to meet future needs of the pipelines’ customers. But these production activities are not the normal activity of a pipeline seeking to maintain its physical plant and equipment; they are the normal activity of a producer, to which quite different rules apply. Natural has offered no reason why a pipeline should not be treated like other gas producers when the pipeline attempts to act as a gas producer.

Next, Natural points out that the Commission has allowed gas producers to recoup expenses incurred in unsuccessful exploration efforts through the producers’ cost of service. See, e.g., El Paso Natural Gas Co., 22 F.P.C. 659, 665-65 (1959). If the cost of drilling a dry well can be included in the producers’ cost of service and thus in rates for gas sold, Natural argues that it should be able to recover the cost of the three gas supply projects at issue here.

We believe, however, that the failed projects in this case are sufficiently unlike dry wells so that the Commission could reasonably treat the two situations differently. In the dry wells cases, the Commission has suggested that dry wells are a nearly inevitable result of efforts to find and develop new mineral deposits of natural gas. For that reason,

[t]he gas consumer must pay rates sufficient, among other things, not only to amortize the cost of unsuccessful past drilling which makes present service possible, but also [to support] the current losses and other expenditures incurred in an effort to replace the gas currently being produced and consumed and [to] continue service in the future.

Phillips Petroleum Co., 24 F.P.C. 537, 559 (1960), aff'd sub nom. Wisconsin v. Federal Power Comm’n, 303 F.2d 380 (D.C.Cir.1961), aff 'd, 373 U.S. 294, 83 S.Ct. 1266, 10 L.Ed.2d 357 (1963). The Commission has thus viewed conventional efforts to find new natural gas as a bundle: it has not required wholly different treatment of failed and successful wells, but instead views the cost of dry wells as an unavoidable operating expense if new productive wells are to be found. The costs of dry wells are then recovered from revenue for gas from productive wells, which the Commission views as revenue from the same general “project.”

The exotic technologies involved in SNG and LNG plants like the Dunn County and Kalingas projects are, the Commission believes, qualitatively different from , dry wells. Lost investment in such plants is not an inevitable result of closely related activities that do produce natural gas for consumers. The Gas Arctic pipeline, too, was an uncertain enterprise that ended at an early stage in denial of a Commission certificate and thus in no gas. The Commission plausibly viewed these three projects as unusually risky ventures that were really distinct programs to supplement conventional gas sources, rather than viewing them as unsuccessful aspects of a general exploration program that did produce some gas for consumers. The failure of the three projects involved in this case was total, and from the outset the potential benefit to consumers from them was, as the Commission commented, remote and uncertain. See FERC Op. at 61,379-81. In contrast, the Commission has suggested that expenses for dry wells are integrally bound up with expenses for successful wells. The Commission could reasonably find that money Natural lost on its three projects, unlike money lost on dry wells, was not closely enough tied to any successful exploration efforts to justify cost of service treatment.

Finally, Natural argues that the Commission has allowed electrical utilities to recover costs similar to those involved here, while irrationally denying Natural any recovery. Specifically, Natural notes that the Commission has permitted electrical utilities to amortize prudently incurred expenses from unsuccessful generation projects, and to recover those amortized expenses through the utility’s cost of service. The Commission has not, however, allowed inclusion of these expenses in rate base. See New England Power Co., 8 F.E.R.C. ¶ 61,054 (1979), aff'd sub nom. NEPCO Mun. Rate Comm. v. FERC, 668 F.2d 1327 (D.C.Cir.1981), cert. denied, 457 U.S. 1117, 102 S.Ct. 2928, 73 L.Ed.2d 1329 (1982). See generally Awerbuch & Freireich, Nuclear Cancellations: Economic and Legal Bases for Allocating Losses, in Award Papers in Public Utility Economics and Regulation 325, 340-44 (1982). According to Natural, the three failed gas supply projects in this case are comparable to the failed generation projects for which electrical utilities have recovered their costs. If electrical utilities may charge ratepayers for their failed efforts to develop new supplies of energy, Natural maintains that it must be allowed to do so as well.

The Commission offered two basic reasons for treating electrical utilities and natural gas companies differently. First, it pointed out that the statutory schemes governing electrical and natural gas utilities vary somewhat. Second, and more fundamentally, the Commission suggested that allocating the risk of failure for the projects involved in this case is a different policymaking problem than allocating the risk of failure for electrical plants.

The Commission identified two differences between the Federal Power Act and the Natural Gas Act that, in its view, supported the result in this case. First, the Commission noted that a natural gas company must obtain a certificate of public convenience and necessity before the company begins a gas project subject to the Commission’s authority. 14 The Commission commented that “[t]his fact alone undoubtedly helps to explain the Commission’s historic reluctance to allow pipelines to recover from ratepayers amounts lost in projects which were either ineligible for a certificate or, if eligible, did not receive a certificate.” FERC Op. at 61,380. By contrast, the Commission has no authority to rule on electrical generation projects before they are constructed. This rationale supports the Commission’s different treatment of expenses from the Gas Arctic project and expenses from failed generation projects in a straightforward way. The pipeline planned by project participants could not be constructed without Commission review, and in fact all the money Natural lost was spent in unsuccessful pursuit of a certificate. Because the Commission has no certificate jurisdiction over electrical utilities, there is obviously no direct analogue in the electrical industry to money spent on a failed application for a certificate.

Next, the Commission noted that it lacked certificate jurisdiction over the Dunn County and Kalingas projects, and that if Dunn County SNG had been sold without commingling it with other natural gas and Kalingas LNG had been sold on foreign markets, the Commission would also have lacked authority to regulate rates for the gas produced. Ratepayers subject to the Commission’s jurisdiction should not, in the Commission’s view, ordinarily pay to develop supplies that might ultimately be delivered to ratepayers who purchase gas at unregulated prices. Electricity sold domestically by investor-owned utilities is always subject to rate regulation, either by the Commission or by the states. Ratepayers paying regulated prices thus always reap the benefits of successful generation projects. For that reason, the Commission is willing to impose a share of the risk of failure on federally regulated ratepayers by including in rates part of the cost of facilities intended to benefit them. But Natural could legally have sold SNG from the Dunn County project and LNG from the Kalingas projects at prices subject to no federal or state regulation. If price regulation might not contain the utility’s potential profits from the endeavors, so, in the Commission’s view, price regulation should not be used to protect the utility from the possibility of loss.

Natural replies that it always intended to sell any gas produced at the Dunn County and Kalingas projects to jurisdictional ratepayers. Even assuming that Natural’s account of its intentions is correct, we think the Commission’s argument retains some force. As the facts of this case demonstrate, market changes can easily disrupt the plans of natural gas companies. Ratepayers paying regulated electricity prices were virtually certain to receive any electricity produced by failed generation facilities, while the likelihood that jurisdictional ratepayers would receive gas from the Dunn County and Kalingas projects depended on plans that might conceivably have changed. 15

The Commission did not, however, rely principally on these statutory differences to distinguish failed electrical generation facilities from the Dunn County and Kalin-gas projects. Instead, the Commission suggested that those two projects were “highly speculative and any potential benefit to ratepayers was remote and uncertain.” FERC Op. at 61,381. That conclusion is enough to support the Commission’s refusal to follow the electricity cases in this very different context.

The real gist of Natural’s argument is that the Commission must logically adopt a single general policy for the natural gas and electrical industries governing recovery of money lost in abandoned supply projects. We think that suggestion fails to take account of the complex policy questions that are relevant in determining the appropriate treatment of these losses. As the Commission has recognized, money lost on abandoned projects, if not recovered through a utility’s cost of service or rate base, ultimately comes from the rate of return allowed the utility. Charging losses against the rate of return in this way results in at least a short-term loss to investors, because earned surplus is reduced. However, as investors become aware that they bear the risk of losses from abandoned projects, they are likely to demand compensation for the risk by increasing the cost of capital to the utility. The cost of capital — that is, the return demanded by investors — is in turn eventually paid by ratepayers as a higher rate of return. Thus, the long-term burden of these losses, according to the Commission, eventually falls on ratepayers. “[I]f rate of return is required to be sufficiently high ... to attract capital, the risk of [abandonment] losses must be borne by ratepayers either directly (through cost of service) or indirectly (through rate of return).” New England Power Co., 8 F.E.R.C. at 61,177.

Given this complicated economic picture, the question of how to treat abandonment losses is a most involved one. In this case, for example, the Commission determined that the losses involved were proportionately small. See FERC Op. at 61,381. That finding suggests that charging the losses to investors may not noticeably increase investor risk and thus may not significantly alter the return investors demand. 16 More fundamentally, the Commission evidently believed that the exotic SNG and LNG technologies involved in these projects were unproven and radically different from orthodox methods of obtaining and processing natural gas. Natural gas is conventionally obtained as a gas from mineral deposits, unlike SNG; and it is conventionally transported as a gas, without the elaborate cooling and liquefaction treatment required to product LNG. SNG and LNG facilities can be seen as generically different from ordinary industry operations and

thus as creating quite different risks for investors and ratepayers.

We think the Commission could reasonably find that SNG and LNG facilities have no analogues in the electrical industry. Failed generation facilities may, of course, involve highly advanced technology, such as nuclear reactors. But Natural has not shown that its Dunn County and Kalingas projects were, when undertaken, as likely to be completed successfully and to benefit ratepayers as the failed electrical plans for which the Commission has permitted amortization. Even if it had, we believe that in setting rates within a just and reasonable range, the Commission may consider what future activities it wishes to encourage. The Commission could, for example, believe that the public interest in developing SNG and LNG facilities is more remote and doubtful than the public interest in developing innovative sources of electricity. 17 If so, the Commission could shift some of the risk that a generation facility might fail from investors to ratepayers, while requiring shareholders to bear the initial risk that an SNG or LNG facility might fail. See generally Avery, The Cost of Nuclear Accidents and Abandonments in Ratemaking, Pub.Util.Fort., Nov. 8, 1979, at 17, 21-22 (discussing policy questions involved in allocation of risk when utility plant fails). In short, the Commission could have believed that failed SNG and LNG facilities are unlike the failed electrical facilities for which amortization has been allowed, and consequently could rationally have treated these different cases differently.

C. The Commission’s Suggestion of a Future Prudence Standard

In its opinion, the Commission suggested that it might in the future apply a prudence test to failed natural gas supply projects, and it explained what the elements of such a test would be. The Commission also, however, noted that it would not apply the test to the projects at issue in this case and concluded that those projects would not have met the test in any event. Natural requested rehearing before the Commission, claiming among other things that the Commission had failed to give Natural an opportunity to show that its projects satisfied the proposed prudence test formulated by the Commission. In its opinion denying rehearing, the Commission stated that it “did not adopt a new prudence standard [in its previous opinion]; it merely held that the issue would be reconsidered in future cases and outlined basic ground rules which would apply in formulating any future prudence standard.” Natural Gas Pipeline Co. of Am., 28 F.E.R.C. ¶ 61,020 at 61,038-39 (1984). The Commission’s characterization of its earlier opinion is entirely accurate. Natural cannot claim it was unfairly surprised by announcement of a proposed new standard when the Commission would not in any event have applied that standard to the projects at issue here.

Conclusion

The Commission has long held that a natural gas company may not include expenditures for gas supply projects that never produce any gas in its cost of service. We find that the Commission’s enforcement of that policy in this case was reasonable. The petition for review is accordingly

Denied.

1 . Throughout this opinion we use "the Commission" to refer to both the Federal Energy Regulatory Commission and its predecessor, the Federal Power Commission.

2 . Smyth remains an important early statement of the used and useful standard. Cf. Denver Union Stock Yard Co. v. United States, 304 U.S. 470, 475, 58 S.Ct. 990, 994, 82 L.Ed. 1469 (1938) (under Constitution, stockyard "is not entitled to have included any property not used and useful” to render services in property on which return is calculated) (citation omitted). However, Smyth and some other early Supreme Court opinions may be read to emphasize judicial notions of "fair value” as a constitutional standard for ratemaking and to suggest that courts should closely scrutinize ratemaking methodology to be certain that rates reflect fair value. See Smyth, 169 U.S. at 546-47, 18 S.Ct. at 434. That reading of Smyth has not survived. See Federal Power Comm’n v. Natural Gas Co., 320 U.S. 591, 601-03, 64 S.Ct. 281, 287-88, 88 L.Ed. 333 (1944); Federal Power Comm’n v. Natural Gas Pipeline Co., 315 U.S. 575, 585-86, 62 S.Ct. 736, 742-43, 86 L.Ed. 1037 (1942); id. at 601-07, 62 S.Ct. at 750-53 (Black, Douglas, and Murphy, JX, concurring); Farmers Union Cent. Exch. v. FERC, 584 F.2d 408, 413-14 & n. 8 (D.C.Cir.), cert. denied, 439 U.S. 995, 99 S.Ct. 596, 58 L.Ed.2d 669 (1978).

3 . However, as we note below, Natural did not seek to include all its expenses from the three projects at issue in the disputed costs. See infra at 1158-1159.

4 . Charges initially borne by the shareholders of a utility may, as we discuss below, ultimately cause rates to increase. See infra at 1167-1168.

5 . One of the other disputed issues, which concerned tax normalization, was severed from this proceeding and consolidated with a separate case before the Commission. Natural Gas Pipeline Co. of Am., 13 F.E.R.C. ¶ 61,266 (1980), reh’g denied, 21 F.E.R.C. ¶ 61,119 (1982). A second issue, which concerned onshore separation of liquids, was ultimately resolved by settlements in related proceedings. See Natural Gas Pipeline Co. of Am., 28 F.E.R.C. fl 61,109 (1984); High Island Offshore Sys., 26 F.E.R.C. f 61,302 (1984).

6 . See ALJ Op. at 65,226. The initial decision in the Alaska pipeline case was Alaskan Natural Gas Transp. Project, 58 F.P.C. 1127 (A.L.J.1977); the Commission issued its recommendation to the President under § 5 of the Alaska Natural Gas Transportation Act of 1976, 15 U.S.C. § 719c, in Alaska Natural Gas Transp. Sys., 58 F.P.C. 810 (1977). The administrative law judge in the Alaskan pipeline case relied on Gas Arctic studies to analyze technical details of the competing projects, see, e.g., 58 F.P.C. at 1261, and the Commission in turn relied on the findings of the administrative law judge.

7 . The administrative law judge did, however, allow Natural to recover $244,824 in routine administrative expenses connected with the Ka-lingas project. See AU Op. at 65,226. The Commission held that administrative expenses connected with the project should not be treated differently from other project expenses, and therefore disallowed this item. See FERC Op. at 61,381. Natural does not challenge the Commission’s decision that all project expenses should be treated similarly.

8 . In overturning Great Plains, this court held that the Commission has no direct regulatory authority over sales of SNG unless the SNG is commingled with other natural gas. See Office of Consumers' Counsel v. FERC, 655 F.2d 1132, 1145-46 (D.C.Cir.1980); Henry v. Federal Power Comm’n, 513 F.2d 395, 401 (D.C.Cir.1975). In this case, the Commission suggested there may be some doubt whether it is statutorily permitted to impose on ratepayers losses sustained from failed SNG facilities. See FERC Op. at 61,383 n. 9; see also Office of Consumers' Counsel, 655 F.2d at 1148 ("Nothing in this holding denies FERC any authority it may have to consider the costs of production of synthetic gas in the course of considering jurisdictional sales rate filings and petitions under Section 4 of the Gas Act____”); cf. Public Utilities Comm'n v. FERC, 660 F.2d 821 (D.C.Cir.1981) (holding that FERC may permit natural gas companies to recover in regulated rates certain expenditures for research and development on projects not directly related to interstate commerce in natural gas), cert. denied, 456 U.S. 944, 102 S.Ct. 2009, 72 L.Ed.2d 466 (1982). Elsewhere in its opinion, however, the Commission speculated that in the future these expenditures, if prudently incurred, might be recoverable. See FERC Op. at 61,381. In any event, the Commission ultimately declined to decide whether it may authorize recovery of SNG losses in jurisdictional rates, id. at 61,383 n. 9, and we express no view on this issue.

9 . Section 3 of the Natural Gas Act provides in part that "no person shall ... import any natural gas from a foreign country without first having secured an order of the Commission authorizing it to do so. The Commission shall issue such order upon application, unless, after opportunity for hearing, it finds that the proposed ... importation will not be consistent with the public interest." 15 U.S.C. § 717b. Sections 301(b) and 402(f) of the Department of Energy Organization Act, 42 U.S.C. §§ 7151(b), 7172(f), assigned the Secretary of Energy authority over applications to import natural gas. Under DOE Delegation Order No. 0204-111, 49 Fed.Reg. 6,684, 6,690 (1984), the Secretary’s authority over these applications is exercised by the Administrator of the Economic Regulatory Administration. See 10 C.F.R. Pt. 590 (1985) (regulations governing applications); cf. West Virginia Public Servs. Comm’n v. United States Dep’t of Energy, 681 F.2d 847, 853-59 (D.C.Cir.1982) (discussing scope of § 3); Distrigas Corp. v. Federal Power Comm’n, 495 F.2d 1057, 1064 (D.C.Cir.) (discussing § 3 authority formerly exercised by Federal Power Commission), cert. denied, 419 U.S. 834, 95 S.Ct. 59, 42 L.Ed.2d 60 (1974).

Importation of natural gas from the Kalingas project to the United States would thus have been subject to federal supervision under § 3. In addition, the Commission would have had independent authority to regulate the construction of facilities to receive or ship natural gas from the Kalingas project in interstate commerce or the sale of that gas in interstate commerce or for interstate resale. See Natural Gas Act §§ 1(b), 4, 7, 15 U.S.C. §§ 717(b), 717c, 717f; West Virginia Public Servs. Comm'n, 681 F.2d at 856 n. 38.

10 . When the Commission grants a certificate of public convenience and necessity, as the Gas Arctic group asked the Commission to do for its proposed pipeline, the Commission may attach conditions to the certificate. See Alaskan Natural Gas Transp. Project, 58 F.P.C. 1127, 1144-46 (A.L.J.1977); see also Alaska Natural Gas Transportation Act of 1976, § 12, 15 U.S.C. § 719j (exports of Alaska natural gas subject to Natural Gas Act); cf. supra note 6. As the Commission commented in this case, those conditions may include an apportionment of risk between shareholders and ratepayers if the project fails. See FERC Op. at 61,379-80, 61,383 n. 8.

11 . Permian Basin also directs attention to two other inquiries: whether the Commission has "abused or exceeded its authority," 390 U.S. at 791, 88 S.Ct. at 1373; and whether, considering “the manner in which the Commission has employed the methods of regulation which it has itself selected," “each of the order’s essential elements is supported by substantial evidence," id. at 792, 88 S.Ct. at 1373. For the reasons stated generally in this opinion, we conclude that the Commission’s order satisfies these standards.

12 . But cf. supra note 8.

13 . Natural raises no claim founded on § 4(b) of the Natural Gas Act, 15 U.S.C. § 717c(b), which prohibits certain discriminatory practices by natural gas companies. Natural’s claim is simply that the Commission acted irrationally by treating similar situations differently.

14 . Section 7(c) of the Natural Gas Act, 15 U.S.C. § 717f(c), provides that “natural-gas com-pan[ies]” and "person[s] which will be a natural-gas company upon completion of any proposed construction or extension” may not engage in the transportation or sale of natural gas subject to the Commission’s jurisdiction, undertake construction of facilities for those activities, or acquire or operate any such facilities, without a certificate of public convenience and necessity from the Commission. A "[n]atural-gas company” is "a person engaged in the transportation of natural gas in interstate commerce, or the sale in interstate commerce of such gas for resale.” Id. § 2(6), 15 U.S.C. § 717a(6). The Commission has jurisdiction over “the transportation of natural gas in interstate commerce, ... the sale in interstate commerce of natural gas for resale for ultimate public consumption for domestic, commercial, industrial, or any other use, and ... natural-gas companies engaged in such transportation or sale.” Id. § 1(b), 15 U.S.C. § 717(b). The Commission does not have jurisdiction over certain local and state-regulated transactions in natural gas and facilities used in those transactions. See id. § 1(b)— (c), 15 U.S.C. § 717(b)-(c).

15 . According to Natural, the Commission’s concern that jurisdictional ratepayers might not have benefited from the Dunn County and Ka-lingas projects, even if they were successful, is unsupported by substantial evidence. The Commission, however, did not conclude that jurisdictional ratepayers probably would not have benefited; it found only that they might conceivably not have benefited. The Commission’s concern that this outcome was possible, even if it may have been unlikely, is supported by substantial evidence.

Natural also criticizes the Commission’s suggestion that natural gas companies are compensated through their rate of return for entrepreneurial risks, such as the risk that gas supply projects will entirely fail. See FERC Op. at 61,379. Specifically, Natural argues that the Commission established its rate of return without considering this risk. However, the Commission never claimed that Natural’s rate of return included a particular allowance for the risk that these three projects would fail. The Commission merely pointed out that rates of return are set with the knowledge that the risk of losses generally similar to those at issue here falls on the investors. Natural has said nothing to blunt that argument. Moreover, Natural can hardly have assumed, in light of the Commission precedents we discuss, that it would be allowed to recoup the expenses of these three projects through its cost of service. Thus, if Natural believed that its approved rate of return was inadequate in light of its losses on the projects, it should have so stated to the Commission in the separate proceeding to set Natural’s rate of return.

16 . In the past, the Commission has not based its general policy of denying natural gas companies recovery of expenses for failed gas supply projects on the small amounts of the losses. In this case, however, we do not review that policy in all of its possible applications; we review the reasonableness of its application to the facts before us. The Commission argued that the relatively small losses involved here supported its refusal to depart from its established policy, and we believe that view is reasonable.

17 . See ALJ Op. at 65,229 ("the coal gasification process is seen as a new and unconventional source of gas, yet to be proved and found adaptable to the gas industry”).