JOHN R. BROWN, Senior Circuit Judge.
Petitioner Algonquin Gas Transmission Company (Algonquin) brings this petition for review, challenging an order by respondent Federal Energy Regulatory Commission. The Commission denied Algonquin’s request for a rate increase to its customers to recover $900,000 in expenses it incurred in an unsuccessful development of the Eascogas Liquified Natural Gas import project (Eascogas). See Algonquin Gas Transmission Co., 31 FERC II 61,221 (1985). The Commission properly applied its long-standing policy of denying recovery of costs for unsuccessful gas supply projects. Accordingly, we deny the petition for review.
Algeria and the Energy Crisis
Algonquin is a pipeline company that sells natural gas for resale in interstate commerce. Therefore, the rates Algonquin charges for those services are subject to the Commission’s jurisdiction under Sections 4 and 5 of the Natural Gas Act, 15 U.S.C. §§ 717c and 717d (1982). The question here is whether Algonquin may properly charge its customers under those provisions for a gas supply project that was never completed.
Eascogas was a corporation created and jointly owned by Algonquin and other companies. Eascogas had proposed to import Liquified Natural Gas (LNG) from Algeria and deliver it to its own facilities in Staten Island, New York, and Providence, Rhode Island. From there, it would be stored, regasified, and sold to United States customers for subsequent resale in New Jersey and New England. Of the proposed import volume, twenty-eight percent was to be sold to Algonquin’s customers.
The feasibility of the Eascogas project depended on the purchase of Algerian gas under low price contracts. These contracts, however, were contingent on the sponsors getting Commission approval by January 1, 1974, for at least the importation and sale aspects of the project. Absent that approval, the project could be terminated and the gas purchase contracts renegotiated at a much higher price. Based on its perception of a crisis in the world’s natural gas supply, the Commission granted to Eascogas (i) a limited authorization under Section 3 of the Natural Gas Act, 15 U.S.C. § 717b (1982), to import the LNG from Algeria, and (ii) a limited certificate of public convenience and necessity for the sale for resale of LNG. Eascogas LNG, Inc., et al, 50 FPC 2075, 2093-94 (1973). It conditioned final certification, however, on “further comprehensive and conclusive evaluations of all issues,” and made clear that it did not “endorse the economic feasibility of the entire Eascogas project.” 50 FPC at 2091.
The Eascogas project was actually a series of projects: buying, importing and selling LNG; providing transport ships to bring the gas to terminal and storage facilities; building those facilities; and providing all the attendant distribution lines. When completed, Eascogas was to have imported, over a 22-year period, some 4.76 billion MMBtu’s of Algerian LNG. See Eascogas LNG, Inc. et al., 50 FPC 1921 (1973).
Unfortunately, the Algerian Connection was not to be. The contract between Algonquin and Algeria included price escalation provisions pegged to world oil prices. When the price of oil later skyrocketed, the LNG project became economically impossible. In 1977, Algonquin terminated the project. No Eascogas LNG was ever imported or sold. The only “facility” actually built for the LNG import project was the excess capacity that was included in the LNG storage facilities built for Providence Gas.
Providence in Providence
As one small part of the massive import project, Algonquin negotiated an agreement with Providence Gas Company (Providence), a local distribution company in Rhode Island. Originally, Providence had planned to construct a large 348,000 barrel storage tank as part of its distribution system. Algonquin persuaded Providence to change its plans and allow Algonquin to build its own 600,000 barrel storage tank on the site. Algonquin’s primary aim was to acquire a deep-water LNG terminal site in Rhode Island for its baseload LNG import project. In return, Algonquin guaranteed Providence 348,000 barrels of storage capacity in the 600,000 barrel tank, reserved for and subject to Providence’s use. Algonquin agreed to build the facilities and provide the services for thirty years.
Algonquin completed the storage tank facility in late 1973. Although Providence began storing its gas there, there was no Eascogas LNG to store. Algonquin prudently found alternative users for the excess capacity. Algonquin sought and received a temporary Commission authorization, valid for one year, allowing it to use that excess capacity for jurisdictional, i.e., interstate, storage services for other companies and to collect rates for such use. Algonquin LNG, Inc. & Algonquin Gas Transmission Co., 52 FPC 731 (1974). This was renewed on a yearly basis until 1982, when Algonquin received a ten-year authorization to use the excess capacity for jurisdictional storage services, Algonquin LNG, Inc. & Algonquin Gas Transmission Co., 19 FERC ¶ 61,265 (1982). It is this single storage operation that Algonquin claims has magically transformed the aborted Eascogas import project into a success, and thereby made Algonquin eligible for the recovery of its costs.
Algonquin Goes to Washington
In January 1980, Algonquin filed with the Commission, under Section 4 of the NGA, a request for $17.1 million per year rate increase for service to customers in New England, New York and New Jersey. Algonquin sought to recover approximately $1.5 million in Eascogas costs as “normal regulatory expenses” through an amortization allowance in its cost of service rate increase. Subsequently, this amount has been scaled down to $900,000. Algonquin gave only a general description of the expenses; it did not differentiate as to costs for the excess capacity for the Providence tank. Significantly, facility construction costs for the Providence storage tank were not included.
In December 1981, the AU issued her decision on Algonquin’s rate case. 17 FERC 1163,063 (1981). Relying on the prevailing Commission policy, the AU disallowed Algonquin’s Eascogas claim on the grounds that (i) the costs incurred for an unsuccessful gas supply project could not be recovered from ratepayers, but must instead be borne by stockholders, and (ii) Algonquin had not, in any event, borne its burden of showing that it had spent the money on otherwise lawful expenses. 17 FERC at 65,300.
In early 1983, the Commission announced its review of the AU’s decisions. 22 FERC H 61,279 (1983). Although it decided the other issues, it expressly postponed consideration of the Eascogas cost recovery question because it was at that time reviewing the same policy of cost recovery in the Natural Gas Pipeline Company case. Accordingly, it reserved judgment on the recovery issue. 22 FERC at 61,502.
The Natural decision, issued in May 1984, reaffirmed existing policy: the company could not recover costs for gas supply projects that were abandoned before completion.
Algonquin, however, ignored the plain meaning of Natural. In July 1984, Algonquin requested a remand to the AU. Seizing on what it contended were “new” standards announced in Natural, Algonquin demanded additional evidentiary proceedings to demonstrate how Eascogas met the new test.
In May 1985, the Commission denied Algonquin’s motion for remand of the reserved cost recovery issue and instead affirmed the AU’s initial decision denying those costs. Algonquin Gas Transmission Co., 31 FERC ¶ 61,221 (1985). The Commission found that Algonquin’s import project did not progress sufficiently beyond the stage of preliminary survey to warrant application of any standard different from the long-established policy reiterated and applied in Natural. In addition, the Commission found that the status of the Providence storage facility was distinct from that of the Eascogas import project. Accordingly, Algonquin could not “bootstrap” the unsuccessful import project onto the much smaller successful storage facility to cast the entire effort as a successful one.
On Algonquin’s petition for rehearing, the Commission found no dispute of the material facts and denied the request. Algonquin Gas Transmission Co., 33 FERC 1f 61,181 (1985). Thus, it comes to us.
Discussion: Au Natural
Algonquin appeals one issue in this case, and its name is Natural. In essence, Algonquin views the Natural decision as the evil spectre that has done in its case. It attacks Natural on three primary fronts. First, it contends that the Natural “test”— promulgated after Algonquin filed its case — is unacceptable revisionism of prior Commission precedent. For the Commission to apply the Natural test to Algonquin's case now, after the record has closed, violates due process. Second, if Natural can apply here, then Algonquin should certainly have the chance to show how, through its Providence storage tank, it now meets the new prudence test. And third, Algonquin contends that Natural’s disingenuous explanation of the disparate treatment of cost recovery for the electric and natural gas industries is hypocritical and unfair. Unfortunately for Algonquin, Natural is neither ground-breaking nor earth shaking. It is, however, an elegant restatement of the Commission’s traditional policy regarding cost recovery for abandoned natural gas projects.
The rationale underlying the Natural decision can be neatly stated. As the District of Columbia Circuit aptly observed:
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 this case, the Commission in effect decided that the public interest in seeing that ratepayers do not pay for services not received was dispositive.
Natural, 765 F.2d at 1163-64. We find this reasoning persuasive and applicable to Algonquin’s case.
Algonquin’s Inartful Dodging
Algonquin first attacks Natural as being revisionist. It contends the Commission has ignored or recast the inconsistencies in the Commission’s prior treatment of the cost recovery issue.
It is true that the Commission, in rare cases, has given advanced guarantees to a gas pipeline, assuring it that it may recover some of its project costs even if the project later proves unsuccessful. See, e.g., Trailblazer Pipeline Co., 18 FERC ¶ 61,099 at 61,500-04 (1982); Ozark Gas Transmission System, 16 FERC H 61,099 at 61,-194-96 (1981), reh’g denied, 17 FERC ¶ 61,024 (1981). These cases, however, are inapposite to Algonquin’s situation. The Commission has granted prior guarantees only when a party has raised public policy considerations and then only when the Commission had considered beforehand whether the project would be in the public interest.
Moreover, Algonquin relies on language from these two cases that questions whether the traditional policy — one of non-recovery — might be subject for a change in the future. Not surprisingly, Algonquin neglects to mention that these decisions were issued while the Commission was reexamining the very same policy of non-recovery which was reaffirmed by the later Natural decision. In context, both Ozark and Trailblazer recognize that the usual policy was one of non-recovery.
Algonquin has relied on these cases for its claims that, before Natural, the Commission’s policy was different. Such reasoning fails for historical inaccuracy. These two cases were decided in the very different context of providing advanced guarantees that ratepayers would bear some risk of project failure. On appeal, Algonquin cannot complain that it was prejudiced by the Commission’s individualized treatment in Ozark or Trailblazer. After all, Algonquin never even received final certification or unconditional approval, much less an advanced guarantee.
Algonquin’s contention that Natural announced a new test is equally unavailing. The Commission explicitly rejected the notion that it was adopting or implementing a new standard of cost recovery for early abandoned projects. 27 FERC at 61,380. Algonquin nevertheless maintains that the following language announces the elements of a new test: “[Whether] the projects were found to be speculative and uncertain, [and] remote in time____”27 FERC at 61,-379. This “test” is nothing of the sort. It is merely one description — an alternative characterization — of the historical traits of projects in which cost recovery was disallowed. Indeed, the remainder of that same sentence, which merely continues this description, concludes, “[and were] without benefit to ratepayers.” Id. The “new” test of “speculativeness” and “remoteness” is merely an amplification of the same old policy. The test remains that a policy must, in the eyes of the Commission, be “of benefit to ratepayers.” The more speculative or remote a project, the less likely it will, in the Commission’s view, benefit ratepayers. Algonquin’s analysis is rejected.
Although the test for preliminarily abandoned projects remains unchanged, Natural did prospectively announce a prudence standard to be applied to projects that progressed beyond the preliminary stage before abandonment. The Commission stated, “[W]e do not foreclose reconsideration of the abandoned projects issue in future cases where projects have been carried beyond the stage of preliminary survey and investigation and where the pipeline’s investments are proportionately greater.” 27 FERC at 61,381 (emphasis added). The crucial criteria for this prospective “prudence standard” center on more advanced degrees of investigation and investment. Thus, projects that terminate at a “preliminary” stage will not likely merit Commission eligibility for consideration under the new prudence test. For early abandoned operations, therefore, Natural changes nothing: if the ratepayers never benefited, the costs cannot be recovered.
The Little Tank That Could
The engine in Algonquin’s drive to distinguish its case from Natural has been the storage tank in Providence. Algonquin so fervently urges the storage tank aspect of the Eascogas project for a very good reason: if it can “bootstrap” the abandoned Eascogas project onto the success of the storage facility, it may no longer be a “preliminary” project, and may be eligible for analysis under the more generous test of the recently expressed prudence standard.
Algonquin’s argument runs along this line: The storage tank is successful. (It is commercially profitable, and even has a ten-year jurisdictional certificate from the Commission.) If the storage tank’s success can be attributed to the entire Eascogas project (for which the tank was originally built), then Eascogas can be treated as having progressed beyond the preliminary stage. If Eascogas went beyond the preliminary stage, it (i) can be distinguished from the strictures of Natural, and (ii) more importantly, can claim the benefit of the “prudence test” announced prospectively in Natural. The hoped-for-conclusion to this, of course, is that Algonquin — which has no chance to recover under the Natural preliminary abandonment test — has some chance to recover under a prudence test.
However flawless may the logic be, the second premise, alas, is faulty. The Commission was entitled to determine that the storage tank’s success cannot be attributed to the entire Eascogas project. In the words of Commissioner Plumb, The Commission stated,
The record demonstrates that Algonquin participated in what are, in effect, two distinct but related LNG projects, i.e., an LNG storage project and an LNG import project. In constructing the facilities needed to serve Providence Gas, Algonquin included excess tank capacity for eventual use in the LNG import project. But independent of the status of the LNG import project, Algonquin made a 30-year commitment to provide delivery and storage capacity for Providence Gas’ own LNG. Algonquin would have continued to provide capacity for Providence Gas even if the LNG import project had been constructed and put into operation. Further, termination of the import project did not affect this service, which Algonquin has provided to Providence Gas since May 1974.
Under these circumstances, the existing LNG storage facilities used to serve Providence Gas are distinct from the Eascogas project. The only facility actually constructed for the Eascogas project was the excess capacity included in the Rhode Island site for future use for Algonquin’s own imported LNG.
31 FERC at 61,443. In other words, the bootstrap does not lift.
Further, the Commission found that most of Algonquin’s expenditures on the Eascogas project were for preliminary types of activities such as preliminary studies, permits, applications, and the like.
Factoring together these aspects, the Commission, concluding that the Eascogas project was terminated at a preliminary stage, found that Natural was controlling and the prudence standard unavailable. The Commission’s finding of two independent projects is supported by voluminous, substantial evidence. The level and type of activity involved in Eascogas by Algonquin has been, from all reasonable perspectives, purely preliminary. The fact that one element — 10% of the total estimated storage capacity — was taken to completion, and is now successfully operating in a manner utterly unrelated to Eascogas, is not decisive. Algonquin, cannot cantilever this “benefit to ratepayers” of the Providence storage tank onto all of the Eascogas project.
Thus, as we review this proposed rate increase by Algonquin, we are mindful that, “the [circuit] court’s responsibility is not to supplant the Commission’s balance of [risk and benefit factors involved in rate setting] 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, 350 (1968). We agree with the Commission’s characterization of the Eascogas project as preliminary, and concur in its application of the Natural “of benefit to ratepayers” test.
Apples, Oranges and FERC
Algonquin’s third argument is that because the Commission permits electric utilities to recover costs under the Federal Power Act for cancelled electric power projects, the Commission must therefore also permit such cost recovery for failed/discontinued projects under the Natural Gas Act. This contention, that two different industries regulated under two different statutes must be treated exactly alike, is utterly unpersuasive.
The Commission must preapprove jurisdictional (interstate) pipeline projects under § 7(c) of the NGA. Accordingly, it has the opportunity — if it chooses — to divide cancellation risks between project sponsors and ratepayers beforehand. See, e.g., Trailblazer Pipeline Co., 18 FERC ¶ 61,099 at 61,500-04 (1982). Under the FPA, however, the Commission has no analogous pri- or approval authority. Thus an electric utility cannot obtain an advance determination, as a pipeline can, of whether the risk of its failure can be shared with ratepayers. Given this lack of preliminary review power under the FPA, it is quite reasonable that the Commission has adopted separate policies of cost recovery for electric and natural gas projects.
The disparate approaches to regulation are well-established. As the Commission declared in Natural,
While Natural is correct in arguing that there is a lack of complete consistency between the Commission’s amortization policies under the Natural Gas and Federal Power Acts, that fact is not decisive. To approve amortization here would result in a direct transfer of risk and related cost from Natural’s shareholders to its ratepayers____ The Commission’s policy applicable to failed gas supply projects is of long standing and has been consistently applied in numerous cases. The Commission’s policy in this area is therefore well established. We have reviewed that policy in the course of deciding this case and have concluded that no charges are warranted.
Natural, 27 FERC 1161,201 at 61,380. We cannot say it any better.
Just One More Chance
Following the announcement of the Natural opinion, Algonquin has steadfastly maintained that it is entitled to a new evidentiary hearing so that it may supplement the record by new facts or data that will show that Algonquin’s Eascogas project has met the asserted new prudence standard. Algonquin’s arguments are unpersuasive.
Algonquin couched its arguments in terms of “unfairness” or failure of due process. These claims are unwarranted. First, Algonquin was clearly heard by the Commission. The Commission, in its order denying the cost recovery, fully responded to Algonquin’s claims of the interrelationship of the import and storage projects and the relation of Algonquin’s case to the Natural decision, and did so again on rehearing. That is sufficient. See, e.g., Pennsylvania Gas & Water Co. v. FPC, 463 F.2d 1242, 1251 (D.C.Cir.1972) (no hearing required when no material facts in dispute).
Algonquin also complains about the Commission’s use of data from its earlier certification proceedings involving Eascogas. It contends that such facts are stale or have been taken under questionably broad “judicial notice.” For example, Algonquin claims that the Commission relied on inaccurate figures in finding the storage tank to be independent from the import project. While it may be true that Algonquin spent more money on the Providence gas storage project than originally planned, this, as the Commission found, cannot change the result that the Providence gas storage tank was a very small part of the massive Eascogas project. Thus, determining the precise amount that Algonquin actually spent in constructing the tank was not significant to the Commission’s conclusion. As discussed above, the success of the storage tank cannot, retroactively or otherwise, transform the status of the Eascogas import project.
End of the (Pipeline
We end as we began, approving the Commission’s decision:
Algonquin’s Eascogas project falls squarely within the Commission’s longstanding precedent concerning disallowance of the costs of gas supply projects terminated at a preliminary stage. Our primary concern is the proper allocation of the risk of loss of such projects between the ratepayers and the shareholders. The Eascogas project was speculative and the potential benefit to ratepayers from LNG importation was remote, uncertain, and in the end, non-existent. Except for the costs associated with the converted storage facility, ratepayers should not bear, consistent with Natural, the costs of the Eascogas project. Because the costs of the converted facility are recoverable through Algonquin’s storage rate, they cannot be amortized in this proceeding.
31 FERC at 61,445.
Accordingly, we deny Algonquin’s petition for review.
DENIED.
. In reviewing a pipeline’s application for a rate increase, the Commission must determine what the pipeline’s appropriate cost of service should be, assuming prudent management, for the rate must be sufficient to recover that cost. The cost of service, in turn, is the sum of the utility's operating expenses, depreciation expense, taxes and a reasonable return on the net value of the property devoted to public service. See generally, Garfield & Lovejoy, Public Utility Economics 56 (1964).
. "MMBtu” is an abbreviation for one million Btu, and equals approximately one thousand cubic feet of gas.
. Indeed, Algonquin has estimated that $47.6 million additional investment would have been required to bring the project up to speed for the original baseload LNG import project. Algonquin Application for Certificate of Public Convenience and Necessity, Exhibit K (filed Nov. 22, 1972, Dkt. No. CP73-139L
. Algonquin did not seek rate base treatment of or a return on the expenses. See supra note 1.
. There was testimony at the hearing on the rate increase that these costs included "legal fees, consultant fees, Algonquin's own costs, the airplane rides to Washington, hotel bills,” but Algonquin did not categorize or classify the expenditures in its presentation to the Commissioner: "It is not clear on this record what costs are included in the $1.5 million total, or what dockets were involved.” Algonquin Gas Transmission Co., 17 FERC ¶ 63,063 at 65,298 (1981).
. See Natural Gas Pipeline Co., 27 FERC ¶ 61,201 (1984), reh’g denied, 28 FERC ¶ 61,020 (1984), aff'd, Natural Gas Pipeline Co. v. FERC, 765 F.2d 1155 (D.C.Cir.1985), cert. denied, — U.S.-, 106 S.Ct. 794, 88 L.Ed.2d 771 (1986).
. The Commission formulated the test as follows:
A pipeline claiming amortization of costs based on a standard of prudence should be prepared to demonstrate that it (rather than the corporate parent or corporate affiliates) was (i) the source of funds expended, and (ii) that the project, if successful, would have benefited its customers and consumers. The pipeline should also be prepared to present detailed evidence concerning (iii) the degree of planning which went into the project as well as any assumptions which were made prior to commitment of funds. In addition, the pipeline should present evidence concerning (iv) the factors which led to abandonment or failure of any project and (v) actions taken to avoid or mitigate resulting losses. In summary, the record must contain evidence which would be sufficient to enable the Commission to determine the reasonableness and prudence of the projects and the pipeline’s actions concerning them.
27 FERC at 61,381.
. See supra note 7.
. Storage itself, recall, was but a small element in the grand scheme of import, processing and distribution. See text accompanying supra note 2.
. The Natural decision is not unique. The Commission treats the two industries differently in other rate-setting matters as well. See, e.g., Cities of Aitken, et al. v. FERC, 704 F.2d 1254, 1257 n. 4 (D.C.Cir.1982); Arkansas Louisiana Gas Co. v. FERC, 654 F.2d 435, 439 n. 8 (5th Cir.1981).
. Stated more graphically, the total construction cost of the one completed Providence tank is estimated to be $17,600,000. Algonquin has disputed this figure, saying that it eventually was "higher.” Regardless of how much "higher” it may be, the Eascogas gas project would have required an estimated (by Algonquin) $47.6 million just to bring the Providence facility up to speed as a baseload LNG import facility. The constructed tank was to be one of three. And the Providence facility was only to store 35% of the imported LNG. Sixty-five percent of the project’s gas was to be stored at the terminal facilities in Staten Island, New York. These facilities, of course, were never constructed. Thus, this lone, bare storage tank, outfitted with inadequate or non-existent dock facilities, unloading lines, send-out facilities, and transmission lines, cannot by any stretch of the imagination be regarded as having progressed "beyond a preliminary stage.” See text accompanying supra note 2.