Association of Public Agency Customers, Inc. v. Bonneville Power Administration

126 F.3d 1158

Opinion

THOMAS, Circuit Judge:

Confronted by unprecedented market pressures, the Bonneville Power Administration (“BPA”) undertook a searching re-examination of its business strategy. As a result, BPA proposed profound alterations in its relationships with certain large industrial customers. At issue in this consolidated appeal are the administrative decisions effecting the transition, which are challenged by a number of widely divergent interest groups. After careful consideration, we deny all the petitions for review.

BACKGROUND

In order to assess whether BPA’s actions were arbitrary and capricious, or outside its statutory authority, we must place. BPA’s decision in proper context. Thus, an understanding of the statutory framework guiding BPA and the origins of the market forces which informed the BPA’s Administrator (“Administrator”) in reaching his conclusions is necessary.

BPA is a federal agency within the Department of Energy created by Congress in 1937 originally to market low-cost hydroelectric power generated by the Federal Columbia River Power System, a series of dams along the Columbia River in, Oregon and Washington. 16 U.S.C. §§ 832-832m. Congress has since expanded BPA’s mandate to include marketing authority over nearly all the electric power generated by federal facilities in the Pacific Northwest. 16 U.S.C. § 838f. As part of its marketing responsibilities, BPA is charged with oversight of the massive federal high-voltage transmission system, comprising approximately 80% of the bulk transmission capacity in the Pacific Northwest, used to deliver power generated at a federally owned and operated facility, termed “federal power,” and non-federal power to its customers. 16 U.S.C. § 838b.

Hydroelectric power producers, such as BPA, store the generation capacity of hydroelectric energy as water held behind dams. Department of Water & Power of the City of Los Angeles v. Bonneville Power Admin., 759 F.2d 684, 686 (9th Cir.1985). The amount of power that'BPA has available to sell at any given time depends upon the height of water held behind the dam. This in turn depends upon the streamflows in the Columbia River basin.' Portland Gen. Elec. Co. v. Johnson, 754 F.2d 1475, 1477 (9th Cir.1985). Because streamflows are somewhat unpredictable, BPA can never be certain precisely how much power it will have for sale in the future. To cope with this uncertainty, BPA has evolved a marketing plan dependent upon sales of “firm” and “nonfirm” power. From BPA’s perspective, “firm” power is that amount of power BPA will be able to produce when the streamflows are at their lowest possible level as determined by historical data. Southern Cal. Edison Co. v. Jura, 909 F.2d 339, 341 n. 1 (9th Cir.1990). Put another way, firm power is the minimum amount of power that BPA can expect to have available for sale during & given time period or the amount of power which “BPA expects to have available under even the most adverse streamflow conditions.” Portland Gen. Elec. Co., 754 F.2d at 1477. In contractual terms, “firm power” means power on demand at any time. A firm power customer expects unlimited power access, and pays a commensurate rate.

“Nonfirm” or “interruptible” power is any amount of power in excess of firm power. Because BPA can count on having power to meet its firm power commitments, BPA sells firm power in long-term contracts. Id. BPA sells nonfirm power on a short-term basis whenever it is available. Id.

BPA power purchasers essentially fall into three groups. The first and primary group is composed of public utilities and other public entities who purchase power for resale to the ultimate consumer. These purchasers are known as “preference” customers because BPA is required to give priority to this group’s applications for power over the competing applications of non-preference customers. 16 U.S.C. § 832c(a). The second group contains private, investor-owned utilities who also purchase BPA power for resale. The third group are the direct service industries (“DSIs”) — industrial companies engaging in power intensive operations who purchase power directly from BPA for their own use. These customers are a closed group: BPA is forbidden from selling power directly to any entity other than those who are currently DSIs. See 16 U.S.C. § 839c(d)(2). The DSIs represent approximately one-third of BPA’s total power sales and contributed 25% of BPA’s total revenues annually from 1992 to 1995.

The DSIs are unique among BPA’s direct customers in that they have the ability to withstand unexpected interruptions of their power without damage to their industrial processes. They are able to do this because they are typically large industrial customers who may be able to adjust their operations or provide their own backup power to accommodate occasional interruptions in service, particularly if they are given advance notice of the interruptions. The needs of DSIs are in contrast to BPA’s utility customers that serve residential consumers who need an uninterrupted source of power. BPA takes advantage of this capability by specifying in its DSI power sale contracts that a portion of the DSIs’ power or transmission capacity may be “interrupted” or held back for use elsewhere. This allows BPA to treat the interruptible portion as “reserves” from which it may draw in the event of an emergency threatening its ability to serve its other firm customers. See 16 U.S.C. §§ 839c(d)(l)(A), 839a(17)(B).

There are two types of reserves: “operating” reserves, which are called on to replace generation failures, and “stability” reserves, used to respond to transmission system failures. Both BPA and the DSIs gain from this arrangement. Having these reserves saves BPA the expense of building additional generating or transmission facilities to meet its firm power commitments, and the DSIs purchase the interruptible portion of their power at a discount. See 16 U.S.C. § 839e(c)(3).

BPA’s operations are governed largely by four statutes: the Pacific Northwest Electric Power Planning and Conservation Act of 1980, 16 U.S.C. §§ 839-839h (“Northwest Power Act”); the Pacific Northwest Federal Transmission System Act of 1974, 16 U.S.C. §§ 838-838k (“Transmission Act”); the Pacific Northwest Consumer Power Preference Act of 1964, 16 U.S.C. §§ 837-837h (“Preference Act”); and the Bonneville Project Act of 1937, 16 U.S.C. §§ 832-832m (“Project Act”). These statutes subject BPA to a variety of detailed and potentially conflicting statutory directives. For instance, the Northwest Power Act requires BPA to set its rates for electric power at a level sufficient to meet its costs and to repay the federal debt incurred in building the projects included in the Federal Columbia River Power System. 16 U.S.C. §§ 838g, 839(4), 839e(a)(l). While this would tend to encourage higher rates, the Transmission System Act requires that BPA market federal power “with a view to encouraging the widest possible diversified use of electric power at the lowest possible rates to consumers consistent with sound business principles____” 16 U.S.C. § 838g. At the same time, BPA must also be environmentally conscious, support energy conservation, and act to protect the fish and wildlife of the Columbia River basin.¹ 16 U.S.C. §§ 839, 839b.

From its creation in 1937 until very recently, BPA enjoyed a considerable price advantage over its competitors in the sale of power. BPA’s inexpensive power and control over most of the transmission facilities in the Pacific Northwest made it the region’s dominant power supplier. Steadily increasing demand for low-cost federal power in the 1970s led BPA to conclude that it would not have sufficient resources to meet the demand by the end of the decade. Aluminum Co. of Am. v. Central Lincoln Peoples’ Utility Dist., 467 U.S. 380, 385, 104 S.Ct. 2472, 2477, 81 L.Ed.2d 301 (1984) {“ALCOA ”).

Accordingly, BPA announced in 1973 that new contracts for firm power sales would not be offered to the investor-owned utilities. Id. Two years later BPA advised the DSIs that their power sale contracts scheduled to expire during the 1981-1991 period would not be renewed. Id. By 1976, further increases in demand forced BPA to warn its preference customers that it would not have sufficient resources to fulfill their power needs past mid-July 1983. Id. BPA began considering how to allocate the available federal power among its preference customers, but in the absence of any guidance on the issue from the Project Act, it feared litigation would be inevitable. Id. Meanwhile, faced with the high cost of alternative sources of power, nonpreference customers hastened to find ways to regain access to cheap federal power. Id.

This uncertain and unstable situation spurred Congress to enact the Northwest Power Act in 1980. The Act transformed BPA from an agency that merely sold whatever power was available from generating facilities in the Federal Columbia River Power System to one charged with the responsibility of meeting the region’s future power needs, promoting energy conservation, and enhancing fish and wildlife affected by the power system in the Columbia River basin. 16 U.S.C. § 839. The Act also sought to avert disputes over power allocation by requiring BPA to enter into an initial set of power sale contracts with its different groups of customers, including the DSIs. ALCOA, 467 U.S. at 386, 104 S.Ct. at 2477-78, 16 U.S.C. §§ 839c, 839e(d)(l)(B), 839c(g)(l).

Pursuant to this statutory directive, BPA entered into new, 20-year contracts with the DSIs in 1981 which allowed them to vary their power load depending upon market conditions and to terminate the contract with one year’s notice to BPA (the “1981 Contracts”). The contracts also contain a “stranded costs” provision allowing BPA to recover from the DSIs any otherwise unrecoverable costs incurred by BPA as a result of a D SI terminating its contract and ceasing BPA power purchases.

BPA’s price advantage enabled it to discharge its new responsibilities to promote energy conservation and fish and wildlife welfare without significant incident throughout the 1980s. Technological advances in gas-fired combustion turbine design and low natural gas prices began lowering the price of alternative energy sources and putting some competitive pressure on BPA. Additionally, the Federal Energy Regulatory Commission (“FERC”) commenced efforts to encourage competition and transmission access. With the amendments to the Federal Power Act, 16 U.S.C. §§ 791a-828c, contained in the Energy Policy Act of 1992, Pub.L. No. 102-486, 106 Stat. 2776 (1992) (“Energy Policy Act”), competition in the wholesale power market increased markedly. The Energy Policy Act was intended, among other things, to promote greater competition in bulk power markets by encouraging new generation entrants and by expanding FERC’s jurisdiction to compel transmission access.

Under the Energy Policy Act, power producers who lack their own transmission capability may request FERC to order transmission line owners, including BPA, to transmit, or “wheel”, power for them even if the line owners had not generated the power. 16 U.S.C. §§ 824j(a), 824k(i). “Wheeling is the procedure by which the owner of transmission lines transmits electricity produced by another party for a specified charge.” Department of Water & Power, 759 F.2d at 688 n. 6. In this manner, Congress sought to encourage wholesale power marketing competition between utilities and independent power producers and thereby to reduce the cost of electricity to consumers. See, e.g., H.R. Rep. No. 474(1), 102d Cong., 2d Sess. 138-40 (1992), reprinted in 1992 U.S.C.C.A.N. 1953, 1961-63. As a result of this and other forces, the price of wholesale power in the Pacific Northwest dropped, and for the first time in its history, BPA faced considerable price competition. At the same time, increases in the cost of BPA’s fish and wildlife programs caused the price of its own power to rise.

The DSIs’ 1981 Contracts with BPA required any DSI wanting to continue purchasing BPA power after the 20-year term to request a replacement contract by June 30, 1993. In anticipation of this deadline, and at the behest of BPA customers considering diversification of their power supply to take advantage of the competitive developments in the wholesale power market, BPA initiated a long-term power sale contract renegotiation process in early 1992. At the same time, BPA began a parallel environmental review process in order to ensure compliance with the National Environmental Policy Act of 1969, 42 U.S.C. § 4332 (“NEPA”). BPA’s customers, state governments, environmental groups, and public interest groups all participated in these early contract renegotiation and environmental review processes.

On April 30,1992, BPA published a Notice of Intent to prepare an environmental impact statement (“EIS”) called the “Replacement of Long-Term Firm Power Sales Contracts EIS.” The anticipated scope of the EIS environmental analysis was “to address broad policy issues which affect the impacts of contract provisions on the environment.” The participants in the renegotiations established a “Working Group” composed of utility customers, DSIs, and constituents — including petitioners Public Power Council² and Northwest Conservation Act Coalition (“NCAC”)³ — to develop contract renegotiation principles. Recognizing that the NEPA process depended upon an analysis of the issues raised in the contract renegotiation process, the Working Group was tasked also with reviewing and coordinating the development of the analyses in the EIS.

By October of 1992, the Working Group had developed a list of primary issues for the new long-term power sales contract renegotiations. The participants had by this time formed smaller, self-selected groups, appropriately called subgroups, to address particular issues in more detail and present their conclusions to the full Working Group for consideration. Products from the Working Group were then shared with the broader public through mailings, Issue Alerts, and Fact Sheets. One subgroup, the “Process Subgroup,” which included petitioners Public Power Council and NCAC, was formed to develop alternatives for resolving each of the primary contract renegotiation issues. The Process Subgroup examined many questions, including whether “the power sales contracts [should] address transmission access for customers and ultimate consumers,” and whether the new contracts should allocate the unrecoverable costs that a single customer may impose on the system, called “stranded costs.” Another subgroup, the NEPA Adjunct Working Group, which also included petitioners NCAC and Public Power Council, met on a regular basis throughout the renegotiation process to discuss the relationships between the primary issues, alternative business decisions, and possible environmental impacts, and to review and comment on the proposed alternatives for the EIS.

The Working Group early on identified overarching issues of major concern to the participants that were not addressed by the existing power sales contracts, including wholesale power rate design and access to BPA’s transmission facilities for purchases of non-federal power. Working Group discussions revealed that customers were reluctant to execute contracts with BPA without knowing its position on these issues. BPA therefore proposed to expand the scope of the EIS in August of 1993 to include rate design and transmission access, renaming it the “Pacific Northwest Commercial Services and Rates EIS.” In response to public comments on the scope of this new EIS, and in recognition of its need to become more competitive to retain customers while continuing to fulfill its public service missions, BPA further expanded the EIS in December of 1993 to encompass all aspects of its proposed Business Plan for 1994, renaming it the “Business Plan EIS.”

BPA circulated a Draft Business Plan EIS to the public for comment in June of 1994, along with a draft of BPA’s Business Plan. Meanwhile, in September of 1994, BPA and the renegotiation participants began negotiations, called “Omnibus Negotiations,” to reach non-binding agreements on the principles to govern the new long-term contracts.

In December of 1994, BPA announced that it would prepare a Supplemental Draft EIS to incorporate the extensive comments received on the Draft Business Plan EIS and updated information and analysis. This Supplemental Draft EIS was distributed for public comment in March of 1995.

By January of 1995, several issues remained unresolved in the Omnibus Negotiations after nearly four months of talks, including the marketing and crediting of unused power, the transition to new contracts, and stranded costs. The marketing and crediting issue involved a proposed “take-or-pay” contract provision, under which a purchaser must pay for power sold to it even if it does not take delivery. The parties proposed that, under certain circumstances, BPA be able to resell a portion of the undelivered power sold to the purchaser to mitigate the purchaser’s fixed obligations. BPA would credit revenue generated from the resale to the purchaser’s bill. In February of 1995, BPA and the participants discussed converting the non-binding agreements on principles into draft contracts. BPA proposed to develop and distribute for public comment contract “templates” to be used as a framework for bilateral negotiations with customers.

In April of 1995, soon after the conclusion of the Omnibus Negotiations in March, two DSIs reduced their power purchases under their 1981 Contracts, choosing to purchase less expensive power provided by BPA’s competitors.

Also in April, BPA and the DSIs began entering into five-year contracts in which BPA would sell to the DSIs “unbundled” transmission service, so called because BPA had previously transmitted only power it had produced itself, selling its power “bundled” with its transmission service. These agreements, called the Initial Transmission Agreements, established a mechanism by which the DSIs can obtain BPA transmission service for delivery of power purchased from sources other than BPA. In accordance with NEPA, BPA conducted an environmental review of the Initial Transmission Agreements, subsequently issuing a Categorical Exclusion Determination (“CX Determination”) under NEPA regulation 10 C.F.R. § 1021.410. BPA concluded that no further environmental analysis was necessary to comply with NEPA because the transmission contracts were of a class of actions qualified to be exempt from NEPA analysis: they were of short duration, would not cause changes in the normal operating limits of generating projects, and transmission was to occur over existing transmission lines.

In early June of 1995, BPA circulated preliminary drafts of contract templates for public review. In comments submitted on these draft templates, the DSIs indicated that BPA would not be able to compete successfully unless it offered contracts comparable to the five-year, fixed-rate contracts then being offered by its competitors. BPA held a public meeting on June 22, 1995 to discuss the contract renegotiations and stranded costs, among other topics. BPA stated that its plan for dealing with the stranded costs issue was never to incur them-it would attempt to secure a load commitment through a certain period sufficient to ensure enough revenue to meet all its costs, and after that period, compete successfully so that system investments never become stranded. BPA began discussions with the DSIs in mid-June to design a competitive BPA offer.

After examining comments on the Supplemental Draft EIS, BPA published the final Business Plan EIS in June of 1995. The Business Plan EIS contains extensive discussion of six alternative policy directions BPA considered adopting to guide its efforts to the changing conditions in the electric utility industry and in the Pacific Northwest. These alternatives were:

(1) the “Status Quo (No Action)” alternative, in which BPA would continue to raise rates to cover mounting costs;

(2) the “BPA Influence” alternative, requiring BPA to use its position in the regional power market to promote compliance by its customers with the goals established by the Northwest Power Act and its other organic statutes;

(3) the “Market-Driven” alternative, in which BPA would participate fully as a competitor in the market for power, transmission, and energy services, using success in the market to ensure the financial strength necessary to fulfill its mandates;

(4) the “Maximize BPA’s Financial Returns” alternative, in which BPA would seek to obtain the highest net revenue for marketable products and minimize costs for activities that do not produce revenue, while continuing to fulfill the requirements of the Northwest Power Act and other statutes;

(5) the “Minimal BPA Marketing” alternative, in which BPA would not acquire new power resources of plan to serve customers’ load growth, instead meeting revenue requirements through the long-term allocation of current Federal System capability; and

(6) the “Short-Term Marketing” alternative, in which BPA would emphasize short-term marketing of power and transmission products and services to be responsive to the market.

In a Record of Decision (“ROD”) published on August 15,1995, called the “Business Plan Final Environmental Impact Statement Record of Decision” (“Business Plan ROD”), BPA decided to adopt the Market-Driven alternative, believing it to be most accommodating to all BPA’s responsibilities and to strike the best balance between marketing and environmental concerns. While it was not one of the environmentally preferred alternatives, in BPA’s opinion the differences between it and the environmentally preferred alternatives were small. BPA felt its ability to achieve all its goals would be diminished under any other alternative. The Business Plan ROD indicates that while the Market-Driven alternative provides the basic policy direction for BPA to decide a number of major issues related to products and services, rate designs, energy resources, and transmission, BPA would review the Business Plan EIS to ensure that the impacts of any subsequent actions taken on these issues are adequately analyzed within the range of alternatives. Decisions on specific issues would be the subject of subsequent RODs tiered to the Business Plan ROD.

Meanwhile, the discussions with the DSIs to fashion a competitive BPA power sales contract came to a head. On August 22, 1995, the Administrator sent the DSIs unsigned contracts, requesting written offers of load placement at a target rate to be established later by BPA. On September 20, ten DSIs returned signed contract offers with a total load commitment of 1606 average megawatts (“aMW”), representing a little more than half of BPA’s loads at that time. BPA held a public meeting on September 22 to receive comments on whether it should accept the DSIs’ offers. The Administrator decided to execute the contract offers with each DSI committing 80% or more of their firm load to BPA, provided that the total DSI load commitment equaled at least 1200 aMW. True to his promise in the Business Plan ROD to issue subsequent RODs tiered to the Business Plan ROD for decisions on specific issues, the Administrator issued a ROD on September 28, 1995 announcing this decision (called the “Direct Service Industrial Customer Requirements Power Sales Contract Record of Decision,” or “Block Sale ROD”) and ensuring its consistency with the analysis contained in the Business Plan EIS. Presumably because they require the DSIs to purchase power on a take-or-pay basis, these contracts have come to be known as the “Block Sale Contracts.”

As the contract renegotiations progressed, BPA and the DSIs agreed to extend the term of the Initial Transmission Agreements. In a ROD issued on August 31, 1995 (the “Long-Term Extension ROD”), the Administrator announced his decision to execute contracts-ealled the Long-Term Extension Agreements-to extend the term of the Initial Transmission Agreements fifteen years, for a total of twenty years. These decisions resulted in the filing of three petitions for review.

The Association of Public Agency Customers (“APAC”) filed a petition for review of the Business Plan ROD on November 27, 1995 and an amended petition two days later on November 29,1995. APAC is a non-profit industrial trade association located in Portland, Oregon that represents companies that purchase large quantities of electric power at retail from public agency customers of BPA.

APAC, the Utility Reform Project and the Public Power Council filed petitions for review of the Long-Term Extension ROD on November 29, 1995. The Utility Reform Project is a non-profit Oregon environmental and energy policy advocacy organization that represents Oregon and Washington residents who receive power from BPA. A group of DSIs were later allowed to intervene, as were NCAC and the State of Oregon.

APAC, the Utility Reform Project and Kevin Bell (an individual member of the Utility Reform Project) filed petitions seeking review of the Block Sale ROD on December 27, 1995. Some DSIs were again allowed to intervene, as well as NCAC and Public Utility District No. 1 of Clark County, Washington (“Clark County”).

The Petitioners raise numerous arguments in the petitions, including: (1) whether BPA has the statutory authority to wheel non-federal power to the DSIs; (2) whether BPA failed sufficiently to comply with the NEPA; (3) whether BPA acted arbitrarily and capriciously in granting the DSIs stranded cost protection in the Block Sale Contracts; (4) whether BPA acted arbitrarily and capriciously in executing the Long-Term Extension Agreements; (5) whether BPA violated its statutorily mandated ratemaking procedures; and (6) whether the Long-Term Extension Agreements impermissibly interfere in states’ regulation of retail power sales.

ANALYSIS

I. CHALLENGES TO THE LONG-TERM EXTENSION AGREEMENTS

A. BPA’S STATUTORY AUTHORITY TO TRANSMIT NON-FEDERAL POWER

Petitioners challenge the Long-Term Extension Agreements, claiming BPA does not have the statutory authority to transmit non-federal power. Our inquiry must begin, as always, by examining the statutory language. If Congress has spoken directly to the issue, the agency and the courts must give full effect to that clearly expressed intent. Chevron, U.S.A., Inc. v. Natural Resources Defense Council, Inc., 467 U.S. 837, 842-43, 104 S.Ct. 2778, 2781-82, 81 L.Ed.2d 694 (1984). Unfortunately, none of BPA’s four organic statutes explicitly grants BPA authority to transmit non-federal power. The Petitioners and the DSIs proffer conflicting theories of statutory construction supporting their own views, but a careful reading of the statutes can only yield one result: Congress did not directly communicate its desire.

When relevant statutes are silent on the salient question, we assume that Congress has implicitly left a void for an agency to fill. We must therefore defer to the agency’s construction of its governing statutes, unless that construction is unreasonable. Chevron, 467 U.S. at 843-44, 104 S.Ct. at 2781-83.

BPA contends its interpretation of its authority to transmit non-federal power is reasonable because: (1) the Project Act, the Preference Act, the Transmission Act, and the Northwest Power Act together grant the Administrator broad discretion over the federal transmission system in the Pacific Northwest; (2) these statutes do not limit BPA’s authority to provide transmission services to the DSIs; and (3) the organic statutes confer upon the Administrator broad authority to contract in BPA’s best business interests.

Certainly, Congress endowed the Administrator with broad-based powers to act in accordance with BPA’s best business interests — powers not normally afforded government agencies. Section 2(b) of the Project Act authorizes the Administrator to “construct, operate, maintain, and improve” transmission facilities “he finds necessary, desirable, or appropriate for the purpose of transmitting electric energy, available for sale, from the Bonneville project to existing and potential markets.” 16 U.S.C. § 832a(b). In California Energy Comm’n v. Bonneville Power Admin., 909 F.2d 1298, 1314 n. 17 (9th Cir.1990), we found that “[tjhis delegation of authority is broad, allowing the Administrator substantial discretion. This discretion is tempered only by the implied limitation that the Administrator’s action not be inconsistent with other congressional decrees.”

Section 2(f) of the Project Act provides: Subject only to the provisions of this Act, the Administrator is authorized to enter into such contracts, agreements, and arrangements, including the amendment, modification, adjustment, or cancellation thereof, and the compromise or final settlement of any claim arising thereunder, and to make such expenditures, upon such terms and conditions and in such manner as he may deem necessary.

16 U.S.C. § 832a(f). This revised version of the section was enacted to allow BPA to function more like a business than a governmental regulatory agency. See S. Rep. No. 469, 79th Cong., 1st Sess. 13 (1945) (“[BPA] operates a business enterprise.”) (letter from Interior Secretary Ickes). Subsequent legislation reaffirmed BPA’s broad authority to further its business mission:

[The] legislative history [of the statutes governing BPA’s operations] reflects a congressional recognition of the significant role played by BPA in the Pacific Northwest, and an effort to enable this organization to operate in a businesslike fashion and to free it from the requirements and restrictions ordinarily applicable to the conduct of Government business. The transfer of the functions of BPA from the Department of the Interior to the Department of Energy is not intended to dimmish in any way the authority or flexibility which is a requisite to the efficient management of a utility business.

S. Rep. No. 164, 95th Cong., 1st Sess. 30 (1977), reprinted in 1977 U.S.C.C.A.N. 854, 883.

Although the Project Act did not contain a provision allowing BPA to wheel non-federal power, wheeling had long been BPA practice by the time Congress granted BPA express authority to do so in the Preference Act. Department of Water & Power, 759 F.2d at 688 n. 6. The Preference Act grants BPA the authority to allocate its excess transmission capacity to carry non-federal power in between the Pacific Northwest and other regions. 16 U.S.C. § 837e. The Preference Act did not forbid allocating transmission capacity to the DSIs, even though the Project Act discussed the DSIs at length.

The Transmission Act granted BPA even broader transmission authority, allowing it to provide transmission services for power sales occurring entirely within the Pacific Northwest. 16 U.S.C. § 838b. The Act empowers the Administrator to construct improvements and additions to the federal transmission system in the Pacific Northwest “as he determines are appropriate and required to ... transmit the electric power from existing or additional Federal or non-Federal generating units [or] provide service to the Administrator’s customers.... ” Id.

The Northwest Power Act left these statutory directives intact. To be sure, the Northwest Power Act donned BPA with more of the usual trappings of a federal regulatory agency than it had previously worn, including responsibility for promoting various environmental objectives. See, e.g., 16 U.S.C. §§ 839, 839b, 839d. But the Northwest Power Act also reaffirmed the Administrator’s historic broad authority to contract in no uncertain terms: “Subject to the provisions of this chapter, the Administrator is authorized to contract in accordance with section 2(f) of the Bonneville Project Act of 1937 (16 U.S.C. 832a(f) [sic]).” 16 U.S.C. § 839f(a). BPA’s new, more typically governmental responsibilities suggest the propriety of even greater deference to the Administrator’s decisions. He must continue to run BPA like a business ón a sound financial basis, enabling it to repay its debt to the federal treasury in a timely fashion, while discharging costly new public duties assumed after the Northwest Power Act’s passage. Significantly, even though a substantial portion of the Northwest Power Act is devoted solely to BPA’s relationship and obligations to the DSIs, Congress did not indicate any intent to restrict the Administrator’s discretion to provide wheeling services to these companies.

So what void did Congress leave for the Administrator to construe? Not the decision of whether BPA had the authority to transmit non-federal power: because until very recently, and well after passage of the Northwest Power Act in 1980, BPA power had always been much less expensive than power sold by its competitors, only the most prescient futurist could have contemplated that issue when Congress was considering BPA’s organic statutes. Rather, the “gap” Congress left for the Administrator is how best to further BPA’s business interests consistent with its public mission. The statutes governing BPA’s operations are permeated with references to the “sound business principles” Congress desired the Administrator to use in discharging his duties. See 16 U.S.C. §§ 825s, 838g, 839e(a)(l). See also Department of Water & Power, 759 F.2d at 693 (“To the extent that [BPA’s challenged transmission allocation policy] is designed to mitigate projected deficits, [it] is not only statutorily authorized but statutorily mandated.”). Thus, although Congress did not prescribe the parameters of the Administrator’s authority, it granted BPA an unusually expansive mandate to operate with a business-oriented philosophy. Accordingly, it seems particularly wise to defer to the agency’s actions in furthering its business interests, especially when the agency is responding to unprecedented changes in the market resulting from deregulation.

That Congress never foresaw unbundled transmission service as a valuable commodity, and thus never considered whether BPA could sell transmission services to the DSIs separate from BPA power, does not change this conclusion. Congress gave the Administrator the authority to run BPA like a business. In that sense Congress addressed BPA’s authority to act in response to unforeseen eventualities, as businesses frequently must. In this context, BPA’s statutory construction of its organic statutes appears reasonable, requiring our deference to its judgment.

B. UNLAWFUL DISCRIMINATION

The Transmission Act prohibits discrimination among retail power consumers in providing transmission services. APAC and the Public Power Council contend that this provision precludes BPA from offering to wheel non-federal power to the DSIs without also offering the same to APAC’s members. We disagree. There is no antidiscrimination provision applicable to the DSIs, and even if there were, the DSIs and APAC’s members are not “similarly situated,” as required to actuate the Transmission Act’s protection.

Section 6 of the Transmission Act provides that “the Administrator shall make available to all utilities on a fair and nondiscriminatory basis, any capacity in the Federal transmission system which he determines to be in excess of the capacity required to transmit electric power generated or acquired by the United States.” 16 U.S.C. § 838d (emphasis added). This section was intended to ensure that public and private utilities would have equal access to BPA’s excess transmission capacity. See H.R.Rep. No. 1375, 93rd Cong., 2d Sess. 5 (1974), reprinted in 1974 U.S.C.C.A.N. 5810, 5814. It therefore applies only to discrimination among utilities.

At the time this provision was enacted, equal transmission access for the DSIs to wheel non-federal power was not contemplated. For this reason, APAC’s and the Public Power Council’s appeal to the legislative history of § 838d, which provides that “the Administrator of the Bonneville Power Administration shall not discriminate among classes of customers in making agreements to transmit electric power over Federal transmission lines,” S. Rep. No. 1030, 93rd Cong., 2d Sess. 10 (1974), U.S. Code Cong. & Admin. News at p. 5810 (emphasis added), is unavailing. “Classes of customers” refers to classes of utility customers, those who purchase power for resale, because those are the only BPA customers in 1974 that desired unbundled transmission services from BPA. Further, APAC’s members are not “customers” of BPA, so BPA is not discriminating between classes of “customers” when it offers wheeling services to the DSIs but not to APAC’s members.

Thus, there is no antidiscrimination standard that applies to BPA’s provision of wheeling services to the DSIs but not to APAC’s members. APAC’s argument that the Federal Power Act, as amended by the Energy Policy Act, prohibits BPA’s rates for transmission services from being “unjust, unreasonable, or unduly discriminatory or preferential,” 16 U.S.C. § 824k(i)(l)(ii), does not require a different conclusion. See also 16 U.S.C. § 824k(a). The issue is not whether BPA may charge discriminatory rates for transmission services but whether, having offered transmission services to some of its retail customers, it must offer those services to all.

Even if section 6 did apply, we believe BPA’s actions would be fully justified. To make out a discrimination claim under the Federal Power Act, APAC must at a minimum show that: (1) its members are similarly situated to the DSIs; and (2) there is disparate treatment for the same service. City of Vernon v. F.E.R.C., 845 F.2d 1042, 1045-46 (D.C.Cir.1988).

APAC’s members and the DSIs are not similarly situated. The DSIs have the right to cancel their direct BPA power purchases with just one years’ notice to BPA, while APAC’s members do not contract directly with the DSIs at all. Rather, they contract with utilities who purchase power from BPA under contracts which require seven years’ notice for cancellation. The Administrator offered transmission services to the DSIs in order to make BPA a more attractive service provider to these important BPA customers. Not only do the DSIs account for a substantial portion of BPA’s total revenue, but they also provide BPA with the reserves it needs to ensure the smooth and efficient operation of service to its other customers. Both the revenue and the reserves would have been lost if the DSIs canceled their power sale contracts, as several were seriously considering.

The crucial fact which renders the DSIs and APAC’s members not “similarly situated” — that BPA was faced with the prospect of losing the DSIs as customers — is also the fact which impelled BPA to act as it did. Under these circumstances, there has been no unlawful discrimination.

Finally, Petitioners argue that if the DSIs cease purchasing power directly from BPA in 2001, when the Block Sale Contracts expire, and instead start to purchase power from a utility in the retail market, they will no longer be direct service industrial customers; rather, they will be retail customers just like APAC’s members. If that occurs, Petitioners argue, the DSIs will then lose any special legal status they may currently enjoy. This is speculative and contingent upon an eventuality that may never come to pass. Actions allegedly violative of the antidiscrimination provisions Transmission Act must be judged on the purchaser’s status when the Administrator acts. Accordingly, the DSIs’ potential status as future customers is not germane to a present antidiscrimination inquiry. At the time relevant to our consideration, APAC’s members and the DSIs were not similarly situated.

C. ANTI-COMPETITIVE EFFECTS

APAC argues that BPA did not consider the impact of its allocation decision on competition in the relevant markets, as required by 16 U.S.C. § 832a(b). BPA has an obligation to consider some federal antitrust policies when allocating its excess transmission capacity. California Energy Resources Conservation and Dev. Comm’n v. Bonneville Power Admin., 831 F.2d 1467, 1475 (9th Cir.1987) (“CERCDC I”). “Congress specifically articulated its intent that BPA operate its transmission lines in part ‘to prevent the monopolization thereof by limited groups.’ ” Id. (quoting 16 U.S.C. § 832a(b)). APAC argues this obligation requires BPA to consider the impact of its allocation decision on competition in the relevant markets. We disagree.

In CERCDC I, the petitioners challenged BPA’s then-applicable Intertie access policy, arguing in part that the policy failed to give regard to antitrust policies. We upheld the access policy after examining BPA’s justifications for its policy and the structure of the market for electric power and transmission services. CERCDC I, 831 F.2d at 1474-77.

APAC argues that the Long-Term Extension Agreements will give the DSIs a competitive edge over the APAC members with which they compete, and BPA failed to consider this anti-competitive impact when it executed the contracts. APAC’s argument carries the CERCDC I command to examine antitrust policies too far. CERCDC I does not require BPA to consider the competitive effects of these contracts in downstream markets. Thus, BPA need not attempt to examine whether or how much of a price advantage an aluminum producing DSI may have over its APAC counterpart as a result of these agreements, a task it is ill-equipped to undertake.⁴ Rather, BPA must consider the competitive effects of these contracts in the markets for power and transmission services. See California Energy Comm’n, 909 F.2d at 1309 (“BPA has given adequate consideration to the effect of the [transmission access policy] on competition in the interregional energy markets.”) (emphasis added).

That command has been fulfilled. The whole thrust of BPA’s business activities in the last few years, the entire text of the BP EIS, and the foundational principles in the Business Plan all focus on competition in the markets for electric power and transmission services. Because BPA entered into the Long-Term Extension Agreements to enable it to compete effectively in the newly competitive market for wholesale power, it had to consider the impact of those Agreements on competition in that market. Moreover, by permitting the DSIs access to excess BPA transmission capacity, the agreements promote, rather than restrict, competition in the electric power industry. Thus, the agreements further, rather than frustrate, the purposes of the antitrust laws.

D. INFRINGEMENT ON STATE REGULATORY AUTHORITY

Oregon argues that the Long-Term Extension Agreements impermissibly interfere with the regulatory scheme envisioned by Congress, in which authority over retail wheeling, or the transmission of power to end-users of electricity, is reserved to the states.

We disagree. While it is unquestionably generally the province of the states to regulate retail sales of power, see FERC Order No. 888, 61 Fed.Reg. 21,540, 21,726 (1996); Federal Power Comm’n v. Southern Cal. Edison Co., 376 U.S. 205, 214, 84 S.Ct. 644, 650-51, 11 L.Ed.2d 638 (1964), the states do not have the power, absent absolutely clear congressional direction to the contrary, to regulate transmission lines owned by BPA, a federal agency. See Hancock v. Train, 426 U.S. 167, 179, 96 S.Ct. 2006, 2012-13, 48 L.Ed.2d 555 (1976) (“[W]here ‘Congress does not affirmatively declare its instrumentalities or property subject to regulation,’ ‘the federal function must be left free’ of regulation.”) (footnote omitted). No such affirmative declaration is present here. See 16 U.S.C. § 824k(h) (“[Njothing in this subsection shall affect any authority of any State ... concerning the transmission of electric energy directly to an ultimate consumer.”).

Oregon’s economic concerns about load-shifting are not germane to our review. Interstate transmission is clearly a federal matter. FERC Order No. 888, 61 Fed.Reg. at 21,725. Additionally, because the DSIs have historically purchased their power requirements directly from BPA, allowing the DSIs to purchase out-of-state power will not remove any load from Oregon power producers. Further, the Long-Term Extension Agreements do not embrace retail wheeling to all end-users of power. They merely contemplate wheeling non-federal power for select end-user customers with whom BPA has had a special relationship for many years. While Congress may have “consistently left to the States the authority to regulate retail sales to the end-users of electricity,” the states have never had any authority to regulate BPA’s interactions with the DSIs. Nothing in the Long-Term Extension Agreements compromise Oregon’s regulatory efforts. Oregon’s utilities remain subject to Oregon’s governance.

E. TRANSMISSION AGREEMENTS’ COMPLIANCE WITH 42 U.S.C. § 4332(2) (E)

42 U.S.C. § 4332(2)(E) requires federal agencies to “study, develop, and describe appropriate alternatives to recommended courses of action in any proposal which involves unresolved conflicts concerning alternative uses of available resourees[.]” This requirement is independent of EIS requirements, and applies to a wider range of federal actions than do the EIS requirements. Bob Marshall Alliance v. Hodel, 852 F.2d 1223, 1229 (9th Cir.1988). Under this section, any proposed federal action involving unresolved conflicts as to the proper use of resources triggers NEPA’s consideration of alternatives requirement, whether or not an EIS is also required. Id.

Petitioners argue that section 4332(2)(E) “required BPA to evaluate the general goal of fair and efficient access to the transmission system and not merely review the preconceived plan of extending the ‘Trial ’ wheeling agreements for fifteen years.”

A fair review of the record demonstrates BPA compliance with section 4332(2)(E). The BP EIS considered many alternatives to long-term wheeling for the DSIs: (1) no long-term wheeling to DSI or retail loads; (2) long-term wheeling to DSI loads that comply with a Power Plan but no wheeling to retail loads; (3) long-term wheeling to DSI loads, but not retail loads; (4) long-term wheeling to serve DSI loads and service to other utilities’ major retail loads where legally feasible; and (5) short-term wheeling to all requesters that can arrange scheduling. Because BPA thoroughly considered alternatives, it did not violate 42 U.S.C. § 4332(2)(E).

F. WAS BPA’S DECISION ARBITRARY AND CAPRICIOUS?

APAC argues that BPA’s decision to execute a contract granting long-term transmission services to the DSIs was an arbitrary and capricious departure from established precedent unsupported by the record. Mindful of our obligation to give the Administrator broad discretion to contract to fulfill his varied statutory duties, we believe BPA’s business decision to execute the Long-Term Extension Agreements is more than amply supported by the record.

The Long-Term Extension ROD fully explains BPA’s reasons for extending the Initial Transmission Agreements. In that ROD, BPA express its belief that its long-term business relationships with the DSIs were best served by providing them with wheeling services. Clearly this is a reasonable belief, particularly in light of the fact that the DSIs, able to cancel their BPA power contract for any reason on one years’ notice, could likely access BPA’s transmission system indirectly. Through the mechanism provided in the Energy Policy Act, 16 U.S.C. §§ 824j(a), 824k(i), a power producer from whom a DSI had agreed to purchase power could obtain access to BPA’s transmission system to wheel power to the DSI. Rather than forcing the DSIs into the arms of another power producer, BPA chose to short-circuit what appeared to be the inevitable, do voluntarily what FERC could have ordered it to do, and thereby foster a better commercial relationship with the DSIs.

The fact that this voluntary agreement removes the transaction from FERC oversight does not derogate congressional intent. FERC procedures are primarily designed to regulate involuntary wheeling requests. After FERC receives a § 824j(a) request for transmission access it intends to grant, it will issue a proposed order which sets a time limit for the parties to agree to the terms and conditions of the order. 16 U.S.C. § 824k(c)(l). Any such agreement reached by the parties must be approved by FERC before it will be included in the final order. Id. If the parties do not agree, FERC will prescribe the terms and conditions governing the transmission access in the final order. Id. § 824k(c)(2)(B). The terms of any agreement should be subject to FERC review where one of the parties was forced into a relationship with the other. This requirement reflects Congress’s desire to provide “assurance to all persons that they will be treated fairly and compensated fully” if compelled to provide involuntary wheeling services. H.R.Rep. No. 496(IV), 95th Cong., 1st Sess. 152 (1977), reprinted in 1978 U.S.C.C.A.N. 7855, 8595. Where the relationship is wholly voluntary, however, there is no reason for FERC approval. Moreover, a theme of the Energy Policy Act was “to use the market rather than government regulation wherever possible both to advance energy security goals and to protect consumers!;.]” H.R.Rep. No. 474(1), 102d Cong., 2d Sess. 183 (1992), reprinted in 1992 U.S.C.C.A.N.1953,1956.

Further, by providing the DSIs with long-term transmission access, BPA secures on a long-term basis the right to use the DSI loads as stability reserves for its entire system, a benefit it would have lost had the DSIs decided to purchase bundled power and transmission services elsewhere.

Despite these positive attributes, several parties argue that the Long-Term Extension Agreements will result in BPA making less revenue, thereby having less to spend on its statutory environmental responsibilities. This challenge to the soundness of BPA’s business strategy is not persuasive. We are not to debate the wisdom of any BPA business decision unless that decision is so manifestly unreasonable as to rise to the level of being arbitrary and capricious. See, e.g., California Energy Comm’n, 909 F.2d at 1306. The decision to execute the Long-Term Extension Agreements was not.

While providing wheeling services to the DSIs is clearly a change in BPA policy, that modification was neither unanticipated nor unexplained. The BP EIS examined both the unbundling of BPA’s power and transmission services in general and DSI wheeling in particular. Of the sections of the BP EIS describing issues “represent[ing] the heart of decisions BPA will make on how to conduct business in the future” were: (1) “Bundling or Unbundling of BPA Power Products and Services,” (2) “Unbundling of Transmission and Wheeling Services,” (3) “Transmission and Wheeling Pricing,” and (4) “Retail or DSI Wheeling.” In this last section, BPA explained that “BPA has not traditionally provided long-term wheeling over its transmission system to serve DSIs and does not provide any wheeling to retail loads of other utilities. However, this policy could be revised to allow such wheeling, as consistent with BPA’s statutory framework and other Federal and state laws.”

In a section of the BP EIS devoted solely to this issue, BPA examined the issue of DSI wheeling in terms of each of the six policy alternatives BPA considered to guide its business direction for the indeterminate future. BPA described the contours of this issue under the Market-Driven alternative which BPA eventually chose:

BPA would provide wheeling to DSI loads, but not to other retail loads.... Providing wheeling to DSIs would increase the DSI customers’ power options, and therefore potentially could reduce the amount of load for which BPA would have to acquire resources in the future. Providing wheeling to DSI loads could mean the loss of some Federal power sales revenue, but it would also reduce the revenue uncertainty associated with the relatively volatile DSI loads....

These issues were not analyzed on a short-term basis. It is implicit in the BP EIS and the BP that any alteration, when made, was to be for the foreseeable future. The Initial Transmission Agreements and the Long-Term Extension Agreements represented a policy change, but not an unexplained one.

The Public Power Council argues that BPA has contractually diminished utilities’ statutory rights to BPA’s excess transmission capacity as guaranteed by section 6 of the Transmission Act, 16 U.S.C. § 838d. The Interim Transmission Agreements, and therefore also the Long-Term Extension Agreements, accord the DSIs the same priority to BPA’s available transmission capacity as public utilities and other producers of non-federal power in the Pacific Northwest. This concern is premature. The argument presumes that there will be insufficient capacity requiring allocation and that BPA will take action in violation of 16 U.S.C. § 838d. Without deciding whether those actions would violate 16 U.S.C. § 838d, we simply note that if and when that event occurs, the aggrieved utilities will have a remedy. The potential for future litigation on a disputed point is not sufficient for us to find that BPA acted arbitrarily or capriciously.

II. PETITIONS FOR REVIEW OF THE BLOCK SALE CONTRACTS

A. VIOLATION OF RATEMAKING PROCEDURES

1. Background

Petitioners challenge the terms of the Block Sale Contracts as disguised ratemaking in derogation of ratemaking procedures mandated by the Northwest Power Act.

Section 7(a) of the Northwest Power Act directs the Administrator to “establish, and periodically review and revise, rates for the sale and disposition of electric energy and capacity and for the transmission of non-Federal power.” 16 U.S.C. § 839e(a)(l). Section 7(i) prescribes specific procedures BPA must follow when establishing its rates. 16 U.S.C. § 839e(i). After notice of his initial proposed rate is published in the Federal Register, the Administrator is to conduct one or more hearings to receive public comment and develop a complete record upon which to base the final rate. Id. Any final rate the Administrator proposes must be approved by FERC before going into effect. Id. §§ 839e(a)(2), 839e(i)(6). These section 7(i) proceedings are also referred to as a “rate case.”

By the fall of 1995, competition for the DSIs’ business was fierce. Many were considering attractive offers from alternative suppliers to serve their loads at prices below BPA’s rates. BPA was engaged in section 7(i) proceedings but did not expect to complete the ratemaking process for several more months, by which time BPA feared it would be too late, the DSIs having already accepted the competing offers.

Recognizing the need to respond to these competing offers and the desirability of preserving the DSIs as BPA customers, and also of the prohibition on negotiating final rates outside the rate case, the Administrator included a rate target rather than an actual rate in the Block Sale Contracts. This provision created a “rate test”: if the section 7(i) proceedings resulted in a rate at or below the rate target, BPA would “pass” or “meet” the rate test, and the DSIs would remain bound to the Block Sale Contracts. If the proceedings produced a rate above the rate target, however, BPA would “fail” or “fail to meet” the rate test, in which case the DSIs would have three options: (1) terminate the Block Sale Contract on seven-days’ notice, terminate the 1981 Contract on seven-days’ notice,⁵ and use the rights to BPA’s transmission system it secured in the Long-Term Extension Agreement to wheel to it power purchased on the open market; (2) terminate the Block Sale Contract on seven-days’ notice and continue purchasing power under the 1981 Contract; or (3) purchase power under the Block Sale Contract at whatever rate BPA established in the rate case. BPA met the rate test. See 60 Fed.Reg. 36,464 (1996) (BPA’s final proposed rates from the 1996 rate case).

2. Contractual Terms Constituting “Rates”

Petitioners first argue that the Block Sale Contract rate test mechanism violated the ratemaking procedures of section 7(i) because the “rate” which must be established in a rate case includes the terms and conditions applicable to the rate which materially affect the bargain struck. The Northwest Power Act does not define “rate,” and BPA’s own regulatory definition expressly provides that contractual terms and conditions are not part of the “rate.” Absent a statutory imperative, we must defer to BPA’s definition if reasonable. Chevron, 467 U.S. at 842-43, 104 S.Ct. at 2781-82. Thus, in order for Petitioner’s argument to prevail, we must find BPA’s definition of “rate” to be unreasonable.

Since at least 1986, BPA has defined “rate” in the context of section 7(i) proceedings as follows:

“Rate” means the monetary charge, discount, credit, surcharge, pricing formula, or pricing algorithm for any electric power or transmission service provided by BPA, including charges for capacity and energy---- A rate may be set forth in a contract; however, other portions of a contract do not thereby become part of the rate for purposes of these rules.

Procedures Governing Bonneville Power Administration Rate Hearings § 1010.2(j), 51 Fed.Reg. 7611, 7615 (1986). BPA thus defines a “rate” as a monetary charge for the sale of electric power. Under this definition, contract terms and conditions that do not establish such monetary charges are not rates.

This is a reasonable interpretation, and the plain language of the Northwest Power Act supports it. Section 7(a) commands the Administrator to establish “rates for the sale and disposition of electric energy and capacity and for the transmission of non-Federal power.” 16 U.S.C. § 839e(a)(l). This implies that rates are charges for the sale of power and transmission services rather than any quid pro quo for particular contractual purchase terms.

Further, we have rejected a similar attempt to expand the meaning of rate. In CERCDC I, 831 F.2d at 1471, the petitioners argued that BPA’s adoption of its near-term interim Intertie⁶ access policy was a rate-making and thus required FERC approval before judicial review was available. The access policy established the conditions under which entities could access the Intertie. Id. We held that the policy was not a rate because it was not a “charge[ ] BPA imposes on its customers for the provision of service.” Id. at 1472 (quoting City of Seattle v. Johnson, 813 F.2d 1364, 1367 (9th Cir.1987)). Rather, a “ ‘rate’ when used in connection with public utilities [is a] ‘price stated or fixed for some commodity or service ... measured by a specific unit or standard.’” Id. (quoting Black’s Law Dictionary 1134 (5th ed.1979)).

Additionally, BPA and the DSIs correctly note that every contract will have terms that may “materially affect the economic bargain struck,” but the Northwest Power Act nevertheless does not require BPA to engage in a section 7(i) proceeding whenever it enters into a contract. See California Energy Comm’n, 909 F.2d at 1305 (“[T]he mere fact that an agency action has an indirect effect 0n revenues does not mean that the action constitutes ratemaking.”). Rather, the section 7(i) proceeding is appropriate only when BPA is establishing a true rate. See California Energy Resources Conservation and Dev. Comm’n v. Johnson, 807 F.2d 1456, 1465 (9th Cir.1986) (“Section 7(i) does not require that contract provisions be adopted after full ratemaking proceedings. Rather, it requires that rates be set according to certain procedures.”).

In support of their position, Petitioners direct our attention to several sources that define “rate schedule” to include terms and conditions. Department of Energy regulations define “rate schedule” as a document “which designates the rate or rates applicable to a class of service specified therein and may contain other terms and conditions relating to the service.” 10 C.F.R. § 903.2(n) (emphasis added). FERC regulations define “rate schedule” as a document describing the type of service to which the rate is to be applied and “other provisions which directly affect such rates and charges.” 18 C.F.R. § 300.1(b)(7). Read closely, these authorities do not contradict the reasonableness of BPA’s definition of “rate” as excluding contractual terms and conditions that do not establish monetary charges for the sale of electric power or transmission services. Thus, we find BPA’s construction reasonable and entitled to Chevron deference, and we reject Petitioners’ suggestions to the contrary.

3. Impact of Contractual Terms on Rates

Relying on a series of Ninth Circuit cases, Petitioners argue that even if the terms and conditions in a contract are not by themselves subject to section 7(i) ratemaking procedures, contractual terms and conditions can sometimes be so closely tied to the rate as to require consideration in a rate case.

In Portland Gen. Elec. Co., 754 F.2d at 1478, BPA sold firm power to some of the DSIs at the lower nonfirm rate, which was not available to them under the rate structure. We held that a change in the availability provisions of the rate schedules was a ratemaking: “When BPA offers to sell power to a class of customers at a rate unavailable to that class under the established rate structure, it has modified the rate structure and generally must follow the statutorily-prescribed ratemaking procedures.” Id. at 1481.

In California Energy Resources Conservation and Dev. Comm’n v. Bonneville Power Admin., 754 F.2d 1470, 1472 (9th Cir.1985) (CERCDC II), BPA purchased virtually worthless scheduling rights to the Trojan nuclear power plant from two utilities for $13.1 million in exchange for the utilities’ agreements to purchase their power requirements from BPA. We found this to be a rebate to the utilities which changed the rate they paid for BPA power outside the rate case in violation of section 7(i). Id. at 1475.

In Atlantic Richfield Co. v. Bonneville Power Admin., 818 F.2d 701, 705 (9th Cir.1987), we held that a fixed customer charge unrelated to actual energy usage that BPA imposed as part of its overall charge for energy was a “rate for the sale or disposition of power.” Similarly, in City of Seattle, 813 F.2d at 1367, we held that an “availability charge” (a fixed fee imposed to recover some fixed costs associated with BPA’s duty under the contracts to stand ready to deliver energy when demanded) was a rate.

Petitioners argue these cases prove that certain terms and conditions in the Block Sale Contract could be so closely tied to the rate that they should be subject to the section 7(i) procedural requirements. While this general proposition may be true, it is not applicable in this case because none of the terms Petitioners challenge are sufficiently intertwined with the rate as to modify the monetary price paid for power. A brief examination of the provisions which Petitioners contest demonstrates the point.

The stranded cost protection afforded in section 5 is not a “rate” because it does not set a monetary charge for the sale of electric power or transmission services. The fact that BPA may attempt to recoup some stranded costs through a general cost recovery surcharge does not change this conclusion. In fact, if we were to endorse Petitioners’ theory that the section 5 stranded cost protection is a rate because it sets the charge for the DSIs’ stranded costs at zero, virtually all contractual provisions would be subject to rate proceedings because of their potential indirect cost implications.

Section 17’s provision of liquidated damages in the event of an extended power interruption represents recompense for damage to a DSI’s facilities and operations that may result from such an interruption, not a reduction in the rate the DSI generally pays for its power. Accordingly, it is not a rate within the meaning of the Northwest Power Act or BPA implementing regulations.

Section 18 of the Block Sale Contracts contains two provisions which offer the DSIs limited relief from their take-or-pay power purchase obligations. A DSI may exercise a one-time option to curtail its power purchases in exchange for a “curtailment fee.” Alternatively, a DSI may choose to exercise a one-time option to have BPA re-market power it does not want or cannot use. Under this “re-marketing” provision, BPA will resell the excess power to another customer and credit the DSI with the sale price, minus a re-marketing fee. Contrary to Petitioners’ contentions, section 18(b)’s re-marketing language does not permit the DSIs to resell BPA power; rather, it allows BPA to resell the power for which it has already billed the DSI at the full section 7(i) rate and to credit the DSI’s bill with the proceeds, minus an administrative fee. Under both the re-marketing and curtailment provisions, the DSIs remain liable for the full rate. The section 18(a) curtailment provision merely permits a DSI to reduce its power purchases, but that amount it continues to purchase is still sold at whatever rate is established in the rate case. While this service is provided for a fee, this fee is not a charge for the sale of electric power or transmission services and is therefore not a rate. The section 18(b) re-marketing provisions also hold the DSIs to the full rate established in the rate case and charge an administrative fee that is not a rate.

The wheeling rights granted in section 19 differ from the rebate determined to be a rate in CERCDC II. Under the contractual terms at issue, the transmission services that BPA agreed to provide the DSIs will be at the transmission rates established in the section 7(i) proceeding. Purchasing services at the rate established in accordance with section 7(i) procedures is not a rebate within the meaning of CERCDC II. Section 19 establishes transmission rights, not rates.

A provision in three Block Sale Contracts under which BPA agreed to act as a power broker when those customers desired to purchase additional power is not a rate. This power is sold in accordance with a power and transmission rate schedule duly approved by FERC after a proper section 7(i) proceeding. The broker’s fee paid to BPA under those provisions is a “demand” rate set pursuant to the rate schedule which permits the rate to be adjusted “as mutually agreed by BPA and the purchaser.” This does not violate section 7(i).

Thus, none of the sections to which Petitioners refer contain any terms and conditions which might rightfully constitute a rate. Additionally, to the extent there were terms and conditions in the Block Sale Contracts Petitioners believed affected the value of the agreement either to BPA or the DSIs, Petitioners were free to explore their concerns and examine those terms in the section 7(i) proceeding. The Block Sale Contracts are a part of the ratemaking record, and they become effective only upon FERC’s approval of the rates established in the section 7(i) proceeding. 16 U.S.C. §§ 839e(a)(2), 839e(i)(6). Although FERC might well have concluded, as we have, that the provisions at issue are not rates (and therefore not the proper subject of the proceedings), nothing prevented Petitioners from raising the question.

4. The Rate Test

Clark County argues that the rate test constitutes a ratemaking outside of a rate case. The essence of this argument is that the rate test established a ceiling above which the Administrator dared not go, because it would almost certainly mean losing the Block Sale Contracts. As such, Clark County claims, the rate test was an improper attempt to influence the outcome of the section 7(i) proceedings.

We considered an identical argument in California Energy Resources Conservation and Dev. Comm’n v. Johnson, 807 F.2d 1456, 1463 (9th Cir.1986) (“The existence of [the rate ceiling] would prevent BPA from acting freely and fairly during a subsequent rate-making hearing[.]”). The Johnson contract required BPA to conduct a section 7(i) rate hearing before the rate ceiling provision went into effect. Id. We refused to reach the question of whether the rate ceiling violated the section 7(i) procedures because it found the issue to be unripe-there had been no ratemaking proceeding, and the challenged contract provision had never been implemented. Id. at 1463-64.

Here there has been a section 7(i) rate-making, but neither Clark County nor any other of the petitioners challenges BPA’s proposed rates as such. Nor could they, unless those rates have already been approved by FERC. See Public Utilities Comm’n of State of Cal. v. F.E.R.C., 814 F.2d 560, 561 (9th Cir.1987) (holding we will not review a BPA rate determination until it has been confirmed by FERC). Thus, pursuant to Johnson, Clark County’s challenges are not ripe. The appropriate vehicle for Clark County’s claims is a challenge to the Administrator’s proposed rates before FERC in the rate case, or an even later challenge to the FERC approval order before this Court.

Clark County maintains the rate test mechanism contained in the Block Sale Contract cabined the Administrator’s ability to discharge his duties in accordance with the rate directives. However, Clark County

has not brought to our attention a single rate adopted in contravention of section 7(i). There are no facts before the court as to the effect of [the contract provision] on the establishment of rates. We will not invalidate [a contract provision] on the ground that it limits BPA’s discretion during ratemaking proceedings without some evidence, beyond [petitioner’s] speculation, that it does so.

Johnson, 807 F.2d at 1465. Although Clark County urges its argument is one of policy rather than evidence, to be true to Johnson, Clark County’s arguments must be considered in a challenge to the rates themselves rather than to the contract.

B. UNLAWFUL DISCRIMINATION

Petitioners argue that section 6 of the Transmission Act prohibits BPA from discriminating among retail power consumers in providing transmission and other services, thereby precluding BPA from offering to wheel non-federal power to the DSIs without also offering the same to utility consumers. We rejected this argument in connection with the Long-Term Extension Agreements, and our reasoning is equally applicable to the Block Sale Contracts.

C. ARBITRARY AND CAPRICIOUS ACTION

We must uphold BPA’s approval of the Block Sales Contracts unless it is arbitrary, capricious, an abuse of discretion, or in excess of statutory authority. 16 U.S.C. § 839f(e)(2); 5 U.S.C. § 706; California Energy Comm’n, 909 F.2d at 1306. This deferential standard of review presumes BPA’s action to be valid. Citizens to Preserve Overton Park v. Volpe, 401 U.S. 402, 415, 91 S.Ct. 814, 823, 28 L.Ed.2d 136 (1971). Notwithstanding this deference, our factual inquiry must be “searching and careful,” although we are not to substitute our judgment for that of the agency. Department of Water & Power, 759 F.2d at 691 (quoting Overton Park, 401 U.S. at 416, 91 S.Ct. at 823-24).

The Project Act gives the Administrator broad authority to enter into power sales contracts “upon such terms and conditions and in such manner as he may deem necessary.” 16 U.S.C. § 832a(f). ALCOA commands that we give the Administrator wide authority to set the terms of BPA’s power sale contracts as he deems proper: “It is the responsibility of the Administrator to manage the complex relationship among these various aspects of the statute, and, absent an express statutory statement requiring particular terms in the contracts, it is appropriate that we give him broad discretion to determine them.”⁷ ALCOA, 467 U.S. at 400, 104 S.Ct. at 2485. With this weighty deference to the Administrator’s business decisions in mind, we now consider his approval of the Block Sale Contracts.

The primary challenge to the Block Sales Contracts involves the stranded cost protection afforded the DSIs. “Stranded costs” (or “stranded investment”) are those costs a wholesale supplier of electricity incurs in anticipation of serving a customer which later become unrecoverable-“stranded”-because the customer ceases to purchase power from that supplier, and the supplier cannot recover those costs by selling the power elsewhere. See FERC Order No. 888, 61 Fed. Reg. at 21,628; Cajun Elec. Power Coop. v. F.E.K.C., 28 F.3d 173,175 (D.C.Cir.1994) (defining “stranded costs” as “costs [a transmitting utility] incurs due to any surplus in generation (or other) facilities resulting from the introduction of open access to its transmission services”). That is, when a utility spends money to build power generation or transmission facilities it plans to use to serve the needs of a particular customer, and that customer takes its business elsewhere, the utility is suddenly left with more facilities than it needs to serve its remaining customers. Unless it can find a new customer to serve with its excess facilities, the money it spent on acquiring the new facilities will be “stranded.” The emergence of stranded costs is, in part, the product of a shift in utility rate philosophy from a rate design based on “cost plus rate of return” to a market-driven rate.

Of course, the term “stranded costs” is something of a misnomer, for someone always pays for them. Petitioners fear, with some justification, that approval of the Block Sale Contracts means that the stranded cost bell will toll for some of them. Naturally, they think that is a bad idea.

Petitioners argue that stranded cost protection is crucial to any entity wishing to purchase non-BPA power. Without that protection, a BPA customer could be saddled with an enormous charge upon ceasing its BPA power purchases, particularly given BPA’s colossal debt from its failed nuclear projects. This danger provides a tremendous disincentive to customers leaving BPA to purchase power elsewhere. Petitioners contend that BPA’s decision to provide the DSIs with stranded cost protection is arbitrary and capricious because it places the DSIs in the position where, for the first time, it is economically feasible for them to leave the BPA system entirely and purchase competitive non-federal power, particularly since BPA has given them access to its transmission system in the Long-Term Extension Agreements.

BPA’s strategy for addressing the issue of stranded costs is to retain its customer base, thereby avoiding or eliminating stranded costs. As BPA stated in its Block Sale ROD, “the whole purpose of the [Block Sale Contract] is to avoid the issue of stranded cost by recovering sufficient revenue from the DSIs to compensate fully for the costs of serving them.” As support for the viability of its strategy, BPA points out that: (1) in exchange for the stranded' cost protection embodied in section 5(b)(2), BPA obtained a sufficient revenue stream to ensure there would be no stranded costs; (2) the Block Sale Contracts contain take-or-pay commitments, more attractive than the requirement commitments in the 1981 Contracts because it guarantees BPA a significant stream of revenue whether or not it is providing power; (3) the Block Sale Contracts offer the DSIs the right to terminate the contract only under limited circumstances, unlike the 1981 Contracts, which permitted the DSIs to terminate for any reason with one-years’ notice; (4) by retaining the DSIs as customers, at least for the next five years, BPA has secured the continued use of DSI power as reserves; and most importantly (5) the Block Sale Contracts enabled BPA to retain a substantial portion of the previous DSI load commitment in the face of intense competition, thereby ensuring BPA’s continued ability to discharge is statutory duties to repay idle federal treasury and to preserve the Columbia River ecosystem.

Petitioners argue that BPA offered no evidence that the Block Sale Contracts would avoid the existence of any stranded costs, particularly given BPA’s staggering debt from the semi-completed nuclear projects it abandoned in the 1980s.

First, we note that BPA and the DSIs interpreted the 1981 Contracts to permit BPA to recover only the unrecoverable cost associated with dedicated transmission facilities, not for any nuclear debt. Second, the Block Sale ROD-in a section entitled “Analysis of DSI Load Commitments”-explains with particularity how BPA arrived at the target rate for the rate test; why BPA believed it would be better off in the future by executing the Block Sale Contracts, with numerical comparisons and due regard for BPA’s public and statutory responsibilities and the restructuring of the power industry in the Pacific Northwest;⁸ and exactly why BPA approached the stranded cost issue as it did in the Block Sale Contracts.

Further, the Block Sale Contracts do not afford complete stranded cost protection. Rather, they provide a limited stranded cost protection, applicable only if a DSI terminates the contract for certain listed reasons during certain times. BPA argues these provisions only prohibit the Administrator from assessing a charge related to past purchases under a previous contract, purchases under the Block Sale Contracts, or reductions in those purchases to recover stranded costs from the DSIs on an individual basis-they keep BPA from targeting a specific DSI upon termination or expiration of that DSI’s Block Sale Contract. However, BPA asserts that the Block Sale Contracts allow it to assess a DSI a general cost-recovery surcharge not based on past purchases under a previous contract, purchases under the Block Sale Contract, or reductions in those purchases, and the DSIs remain obligated to pay for the unrecovered cost of transmission facilities dedicated to serve them to the extent BPA cannot mitigate those costs. Although the full contours of the stranded cost protection afforded in the Bulk Sale Contract are yet to be defined, it is not as complete as portrayed by Petitioners.

In short, the record does not support a charge that BPA acted arbitrarily and capriciously in approving the Block Sales Contracts. The Administrator made a reasoned business decision. As with all such choices in an uncertain market, we cannot foretell whether the strategy will succeed or not. Time may prove the Administrator’s plan unsound. However, it would be improper of us to substitute our business acumen, or lack of it, for the Administrator’s. Our judicial review is confined to assessing whether the Administrator’s actions were arbitrary and capricious. They were not.

III. NEPA CHALLENGES

A. TIMELINESS OF APAC’S PETITION FOR REVIEW

BPA published its Business Plan EIS in the Federal Register on June 12, 1995. After selecting the Market-Driven alternative described in the Business Plan EIS, BPA executed the Business Plan ROD on August 15, 1995 and sent copies to all interested parties, including APAC. The Business Plan ROD was published in the Federal Register on August 31, 1995 as required by the Department of Energy’s NEPA Implementing Procedures. 10 C.F.R. §§ 1021, 1021.315(c) (1996); 57 Fed.Reg. 15,-122,15,149 (1992).

As a first step to implementing the Market-Driven alternative, BPA designed a Business Plan which was made available to the public on September 1, 1995. APAC filed its petition on November 27,1995.

Jurisdiction for APAC’s petition is provided by the Northwest Power Act, 16 U.S.C. § 839f. See Central Montana Elec. Power Coop. v. Administrator of the Bonneville Power Admin., 840 F.2d 1472, 1476 (9th Cir.1988) (holding that suits challenging BPA final actions and decisions must be brought under the Northwest Power Act).

Section 839f(e)(5) of the Northwest Power Act provides the time limits with which a party challenging a final BPA action must comply:

Suits to challenge ... final actions and decisions taken pursuant to this chapter ... or the implementation of such final actions ... shall be filed in the United States court of appeals for the region. Such suits shall be filed within ninety days of the time such action or decision is deemed final, or, if notice of the action is required by this chapter to be published in the Federal Register, within ninety days from such notice, or be barred.

APAC’s petition was filed more than ninety days after the Business Plan ROD was executed but within ninety days of publication of the Business Plan ROD in the Federal Register. Thus, APAC’s petition was untimely unless publication was required by the Northwest Power Act.

We conclude that the Northwest Power Act did not require BPA to publish the Business Plan ROD. Section 839d(e) requires publication of proposals which involve the acquisition of a major resource or the implementation of a conservative measure which will conserve an amount of electric power equivalent to that of a major resource. Although the Market-Driven alternative calls for the acquisition of several resources of over a 50 average megawatt capacity, and new conservation resource acquisitions totaling 460 average megawatt capacity, the Business Plan ROD was not a proposal to acquire these resources. Rather, the Business Plan EIS was the proposal to choose the Market-Driven alternative, and the Business Plan ROD was BPA’s announcement of its final choice. The benefit to the public of requiring publication is to allow public comment and participation prior to a final agency decision. The publication of the Business Plan EIS generated exactly this result. Nothing in the Northwest Power Act requires publication of BPA’s ultimate decision after the proposal has been published in the Federal Register.

Additionally, BPA’s interpretation of the Northwest Power Act as not requiring publication of the Business Plan ROD is entitled to substantial deference, and ought not be disturbed unless it is unreasonable. ALCOA, 467 U.S. at 389-90, 104 S.Ct. at 2479-80; Pacificorp v. Bonneville Power Admin., 856 F.2d 94, 96 (9th Cir.1988). APAC has not demonstrated that BPA’s interpretation of the Northwest Power Act is unreasonable.

The equities involved, however, persuade us that our decision on the publication issue should be a prospective one. The Business Plan ROD was, in fact, published in the Federal Register. Although we conclude that the Northwest Power Act did not require it to be, no case law existed on this point and it was by no means clear at the time that publication had occurred pursuant to Department of Energy regulations, instead of pursuant to the Northwest Power Act. APAC thus had insufficient warning that the time for appeal had begun to run from the date of the execution of the Business Plan ROD instead of the date of its publication, and retroactive application of our decision would work substantial hardship. Therefore, our judgment on this point has prospective application only, and we will consider the merits of APAC’s petition. See United States v. Washington, 761 F.2d 1404, 1409-10 (9th Cir.1985).

B. STANDARD OF REVIEW FOR NEPA CHALLENGES⁹

We review substantive agency decisions concerning NEPA under the “arbitrary and capricious”- standard of the Administrative Procedure Act, 5 U.S.C. § 706(2)(A) (1994). Environmental Coalition of Ojai v. Brown, 72 F.3d 1411, 1414 (9th Cir.1995), cert. denied, - U.S. -, 116 S.Ct. 2500, 135 L.Ed.2d 192 (1996).

Our role “in reviewing the sufficiency of an agency’s consideration of environmental factors is a limited one.” Vermont Yankee Nuclear Power Corp. v. Natural Resources Defense Council, Inc., 435 U.S. 519, 555, 98 S.Ct. 1197, 1217, 55 L.Ed.2d 460 (1978). We are not free to substitute our judgment for that of the agency as to the environmental consequences of its actions. Id. Instead, our task “is simply to ensure that the agency has adequately considered and disclosed the environmental impact of its actions and that its decision is not arbitrary or capricious.” Baltimore Gas & Elec. Co. v. Natural Resources Defense Council, Inc., 462 U.S. 87, 97-98, 103 S.Ct. 2246, 2252-53, 76 L.Ed.2d 437 (1983); see Oregon Envtl. Council v. Kunzman, 817 F.2d 484, 492 (9th Cir.1987).

If the EIS “contains a reasonably thorough discussion of the significant aspects of the probable environmental consequences,” by making “a pragmatic judgment whether the EIS’s form, content and preparation foster both informed decision making and informed public participation,” a court should not disturb the agency’s decision. Half Moon Bay Fishermans’ Mktg. Ass’n v. Carlucci, 857 F.2d 505, 508 (9th Cir.1988) (quotation omitted). The agency’s decision should stand if the agency has taken a “hard look” at the environmental consequences of the decision. Kleppe v. Sierra Club, 421 U.S. 390, 410 n. 21, 96 S.Ct. 2718, 2730 n. 21, 49 L.Ed.2d 576 (1976).

C. THE VALIDITY OF PROGRAMMATIC EISs

Petitioners argue that BPA was not permitted to tier the ROD for specific contracts to the BP EIS, but instead was required to issue a separate EIS for each contract ROD. Petitioners rely on the following text from Environmental Defense Fund, Inc. v. Andrus, 596 F.2d 848, 851 (9th Cir.1979): “NEPA provides that an impact statement must be prepared and included ‘in every recommendation or report on proposals for legislation and other major Federal actions significantly affecting the environment.’ ” (quoting 42 U.S.C. § 4332(2)(C)).

Petitioners’ position is unpersuasive. “So long as the ... NEPA analysis of the overall program is prepared, we think it of little moment whether that analysis is issued as a separate NEPA statement or whether it is included within a NEPA statement on a particular facility.” Scientists’ Inst. for Public Info., Inc. v. Atomic Energy Comm’n, 481 F.2d 1079, 1092 (D.C.Cir.1973). The D.C. Circuit’s conclusion on this point is consistent with our own precedent which notes that “[t]he reviewing court may not ‘fly speck’ an EIS and hold it insufficient on the basis of inconsequential, technical deficiencies.” Kunzman, 817 F.2d at 492 (quotation omitted). See Salmon River Concerned, Citizens v. Robertson, 32 F.3d 1346, 1356 (9th Cir.1994) (“A comprehensive programmatic impact statement generally obviates the need for a subsequent site-specific or project-specific impact statement....”).

Port of Astoria v. Hodel, 595 F.2d 467 (9th Cir.1979), cited by Petitioners, is not to the contrary. In Port of Astoria, a change in location for a power plant and transmission lines had occurred after the EIS had been issued. We held that under these circumstances, BPA was required to prepare another EIS. Id. at 477. In this situation, however, Petitioners have pointed to no intervening-changes in the months between the issuance of the BP EIS and the contracts being signed which would have caused the BP EIS to become outdated. We note that significant circumstantial change is the triggering factor requiring a new or supplemental EIS, not the passage of time alone.

In many ways, a programmatic EIS is superior to a limited, contract-specific EIS because it examines an entire policy initiative rather than performing a piecemeal analysis within the structure of a single agency action. Absent intervening changes which would raise staleness concerns, the Administrator did not err by issuing a single, programmatic EIS.

D.CONSIDERATION OF CUMULATIVE EFFECTS OF CONTRACTS

An agency must consider cumulative impacts in the EIS. Resources Ltd., Inc. v. Robertson, 35 F.3d 1300, 1305 (9th Cir.1993). Petitioners argue that the BP EIS is defective because it does not analyze the cumulative effects of the Initial Transmission Agreements, the Block Sale Contracts, and the Long-Term Extension Agreements. This argument is, of course, somewhat contradictory to Petitioners’ claim that an EIS may only be performed in the context of a single contract. This claim also underscores the validity of a programmatic approach. Those observations notwithstanding, Petitioners’ claim is without merit.

The Market-Driven alternative in the BP EIS is defined by the same elements which form the contracts at issue. The Market-Driven alternative is defined to include the following actions: “provide transmission access to wholesale power producers and purchasers, including DSIs”; “rely to some extent on planned market purchases rather than on long-term acquisition of generating resource output to meet any increases in BPA loads”; “include in power rates the embedded transmission costs of delivering Federal Power to existing points of delivery”; and “market competitively priced, unbundled power products and services.”

Thus, the BP EIS adequately considered the cumulative impact of the challenged contracts when it analyzed the Market-Driven alternative.

E.FLAWED DECISION-MAKING PROCESS

Petitioners complain that negotiations with the DSIs over the stranded cost protection component were privately conducted, and thus, the decision to offer stranded cost protection was not subjected properly to public scrutiny or comment.

Only final BPA actions are reviewable under 16 U.S.C. § 839f(e)(5). Public Utility Comm’r v. Bonneville Power Admin., 767 F.2d 622, 630 (1985) (concluding that “action taken by an agency ... must be a final agency action before it is reviewable in the court of appeals”); see Western Radio Servs. Co., Inc. v. Glickman, 123 F.3d 1189, 1196 (9th Cir.1997) (“The APA thus insulates from immediate judicial review the agency’s preliminary or procedural steps.”). Negotiations, which are not final actions, therefore are not reviewable, and we decline to consider them.

In addition, Petitioners argue that Forelaws on Board v. Johnson, 743 F.2d 677 (9th Cir.1984), requires an EIS prior to the negotiations for the contract.

Petitioners read Forelaws too broadly. Although Forelaws does suggest an order for events to take place which places an EIS prior to negotiations, Fore-laws does not hold that failure to conduct an EIS prior to negotiations violates NEPA. Additionally, an agency can formulate a proposal or even identify a preferred course of action before completing an EIS. Natural Resources Defense Counsel, Inc. v. Hodel, 819 F.2d 927, 929-30 (9th Cir.1987); see Kleppe, 427 U.S. at 405-06, 96 S.Ct. at 2728. Council on Environmental Quality (“CEQ”) regulations¹⁰ actually encourage identification of a preferred course of action during the NEPA process: Agencies shall “[identify the agency’s preferred alternative or alternatives, if one or more exists, in the draft statement and identify such alternative in the final statement....” 40 C.F.R. § 1502.14(e). Therefore, Forelaws does not foreclose BPA’s prefatory formulation.

F. ADEQUACY OF STRANDED COST PROTECTION ANALYSIS

Petitioners maintain that stranded cost protection is a component which the BP EIS does not examine and that BPA announced its intention to allow stranded cost protection for the first time in the Block Sale ROD.

Petitioners are incorrect. The BP EIS does examine stranded cost protection. The definition of the Market-Driven option lists as a component: “include in power rates the embedded transmission costs of delivering Federal power to existing points of delivery.” The BP EIS looks at both implementing a stranded cost charge “to make it more costly for customers- to shift away from BPA,” and, under the preferred Market-Driven alternative, “not implementing] a stranded investment charge (as incompatible with the concept of Market-Driven).” The environmental impacts of each of these alternatives are examined within Chapter 4 of the BP EIS. The BP EIS concludes that implementing a stranded cost charge would significantly decrease the DSI loads served by BPA, as demonstrated by the BPA Influence alternative. The environmental harms from the loss of DSI patronage are examined within the DSI service module.

Petitioners argue that even if the general decision to offer some kind of stranded cost protection is supported by the BP EIS, no analysis on variations, alternatives, and mitigation for the specific kind of stranded cost protection offered was done.

The force of this argument is considerably diminished by the following considerations. First, BPA had to act quickly to secure DSI power contracts or lose the contract opportunity for five years. Second, petitioners failed to champion the environmental concerns associated with stranded cost protection in the administrative proceedings. See City of San Francisco v. United States, 615 F.2d 498, 502 (9th Cir.1980) (finding that the Navy acted reasonably in not considering an alternative “not raised until this litigation [was] commenced” by a party “involved in the leasing process from the beginning”); CERCDC I, 831 F.2d at 1475 (declining to evaluate an alternative transmission access policy that the petitioners did not raise before BPA).¹¹ Third, petitioners advance little evidence that offering stranded cost protection seriously endangers the environment in any area.

An agency is required to examine only those alternatives necessary to permit a reasoned choice. Save Lake Washington v. Frank, 641 F.2d. 1330, 1334 (9th Cir.1981). “The ‘rule of reason’ guides both the choice of alternatives as well as the extent to which the Environmental Impact Statement must discuss each alternative.” City of CarmelBy-The-Sea v. United States Dep’t of Transp., 123 F.3d 1142, 1154-55 (9th Cir.1997). Under the facts of this case, we conclude that the BP EIS was not deficient for failing to provide more variations and alternatives to the stranded cost protection provision.

G. ADEQUACY OF CONSIDERATION OF ENVIRONMENTAL CONSEQUENCES OF TRANSMISSION AGREEMENTS AND STRANDED COST PROTECTION

Petitioners argue that the BP EIS fails to consider adequately a number of adverse environmental effects which relieving the DSIs of stranded cost liability and permitting transmission access will cause.

First, Petitioners maintain that the Block Sale Contracts, the Initial Transmission Agreements, and the Long-Term Extension Agreements will allow more DSIs to survive and thus the BP EIS, which did not consider this aspect, is defective.

Petitioners’ argument fails because the BP EIS adequately considers this aspect of the Market-Driven alternative. “[I]f market conditions changed substantially, DSI operation which are expected to be the same across all Business Plan alternatives could change. In that case, there could be an increase or decrease in the environmental impacts of DSIs, shown on a per-megawatt basis on table 4.3-1.”

Second, Petitioners argue that other energy producers can produce energy at lower prices than BPA and thus, by relieving the DSIs of the obligation to pay stranded costs, the DSIs have an incentive to purchase this cheaper, less clean power. Petitioners also argue that the Transmission agreements facilitate the purchase of “dirty” power by giving easier access to other power sources.

The BP EIS examines the environmental consequences of the possible “[u]tility decisions to purchase non-BPA power instead of BPA requirements service” and “[c]onsumer responses to retail price, including fuel switching.” Different DSI load scenarios were integrated into each alternative examined by the BP EIS, and the resulting environmental effects were examined in chapters 4.3 and 4.4. Finally, as we have noted, the BP EIS evaluated potential environmental effects of increased and decreased DSI operations in table 4.3-1. This examination of the issue is sufficient to satisfy NEPA.

Third, Petitioners maintain that the BP EIS fails to examine the environmental impact to BPA’s ability to meet its fish and wildlife obligations should the DSIs leave without paying stranded costs and thus is defective.

However, the BP EIS does examine the impact of its actions on its fish and wildlife obligations. Section 2.4.5.2 discusses BPA’s fish and wildlife obligations, its desire to satisfy them, and the factors which are important for generating sufficient revenues to meet them.

Fourth, Petitioners argue that the BP EIS fails to examine the social effects that could result from the utilities being liable for higher stranded costs and passing those costs onto its lower socioeconomic clients.

NEPA does not require BPA to examine the economic consequences of its actions.

The theme of § 102 [of NEPA] is sounded by the adjective “environmental”: NEPA does not require the agency to assess every impact or effect of its proposed action, but only the impact or effect on the environment. If we were to seize the word “environmental” out of its context and give it the broadest possible definition, the words “adverse environmental effects” might embrace virtually any consequence ... that some one thought “adverse.”

Metropolitan Edison Co. v. People Against Nuclear Energy, 460 U.S. 766, 772, 103 S.Ct. 1556, 1560, 75 L.Ed.2d 534 (1983). The case cited by Petitioners, Goodman Group, Inc. v. Diskroom, 679 F.2d 182, 185 (9th Cir.1982), which suggests that economic impacts should be considered if the action at issue involves major environmental impacts, predates Metropolitan Edison. Additionally, CEQ regulations state that “economic or social effects are not intended by themselves to require preparation of an environmental impact statement.” 40 C.F.R. § 1508.14.

Moreover, Petitioners do not make a credible argument that people in low social economic strata will be significantly affected by BPA’s actions.

Fifth, Petitioners assert that the loss of DSI loads will affect the flexibility of the hydroelectric system. It is unclear what environmental effect this situation would create. In any event, the BP EIS considers the issue of the potential effects on the hydroelectric system’s flexibility in section 4.5.3.

Sixth, Petitioners claim that the BP EIS inadequately examines the impact the Block Sale Contracts will have on the aluminum smelter operations. However, the BP EIS analyzes the effect on the smelter operations by incorporating the Direct Service Industry Options Final EIS (“DSI EIS”).¹² “While some conditions have changed, the [DSI] EIS continues to be a substantially accurate assessment of the environmental and socioeconomic impacts of smelters.” With regard to whether transmission access for the DSIs would have any. direct impact on overall smelter operations, the BP EIS states:

All PNW smelters [a]re expected to continue operating at full capacity for the near future due to low prices for power.

The recent decline in wholesale prices for electricity has benefited the region’s aluminum smelters because BPA is no longer the least-cost supplier of electricity in the Northwest. Smelters that were formerly considered ‘at risk’ of closure can now operate through most swings of the aluminum price cycle if they can purchase power at an average cost of 20 mills/kWH, as some offered power sales demonstrate.

Although the DSI EIS is ten years old and some of the DSI aluminum operations are not smelter operations, we conclude that the DSI EIS is an adequate enough study to meet the “hard look” requirements of NEPA.

Seventh, Petitioners maintain that the BP EIS does not contain sufficient mitigation analysis. 40 C.F.R. § 1505.2(e) requires that the ROD “[s]tate whether all practicable means to avoid or minimize environmental harm from the alternative selected have been adopted, and if not, why they were not.” The BP EIS, however, contains substantial mitigation analysis. Figure 4.3-1 of the BP EIS summarizes mitigation alternatives for each resource type; conservation, hydro, combustion turbines, cogeneration, solar, geothermal, wind and coal. The information on these pages was extracted from the Resource Programs EIS, and incorporated by reference into the BP EIS. This Resource Programs EIS “provides additional information about the nature of these impacts and typical mitigation measures taken to reduce or eliminate them.” Further possible mitigation measures for the construction of transmission facilities are summarized in Figure 4.3-3 of the BP EIS. Finally, the BPA Influence alternative evaluated a scenario where BPA would apply incentives or conditions to power and services to encourage customers to comply with the Council’s Power Plan and Fish and Wildlife program. Under this alternative, the BP EIS demonstrates that the operations of new combustion turbines would be approximately 20% lower than in the status quo alternative, operations of existing coal plants would be approximately 3% less, and the operations of existing combustion turbines would be approximately the same. Thus, the BP EIS adequately addressed mitigation of potentially adverse environmental effects.

Eighth, Petitioners allege that the transmission agreements will result in inefficient decisions regarding the building and siting of power facilities. Petitioners fail, however, to allege an environmental harm resulting from the alleged inefficiency, and we therefore perceive no NEPA violation.

Ninth, Petitioners assert that the BP EIS failed to consider impacts to the Canadian environment in violation of Executive Order 12114 which requires agencies to develop procedures that take extraterritorial impacts to global commons into account in major Federal actions. In particular, Petitioners claim that the BP EIS does not discuss global warming implications from the effects of greenhouse gases released from increased DSI operations and does not discuss trans-boundary impacts in Canada of continued Canadian gas exploration.

Petitioners are in error because the BP EIS sufficiently considered these issues. Table 4.3-1 examines the environmental impact to increased DSI operations, including C02 output. The environmental effects of gas exploration in Canada is examined in the section entitled, “Effects of Road and Natural Gas Pipeline Building in Canada.”

In summary, none of the many specific EIS concerns Petitioners raise is sufficient for us to find the EIS inadequate.

H.ADEQUACY OF LONG TERM SCOPE OF EIS

Petitioners argue that the BP EIS fails to study the long-term environmental effects but instead focuses on time periods ending around 2002, and thus is inadequate support for the Block Sale Contracts and ROD.

BPA maintains that quantitative numbers of long-term environmental impacts are not available with an acceptable degree of certainty. “Quantifying the multiple permutations of risk factors would provide information of dubious validity and usefulness because each element of risk has a degree of ‘fuzziness,’ and multiplying risk factors multiplies the degree of uncertainty.”

As a substitute for quantitative long-term calculations, BPA has quantitatively evaluated relationships between variables in the short run, and assumed that these relationships will hold true in the long term.

This method complies with the required “hard look” at environmental consequences mandated by NEPA. The requisite “hard look” does not require adherence to a particular analytic protocol. Indeed, such a requirement would not only be counterproductive but, in the end, self-defeating. The specific methodology appropriate in a given circumstance will depend on the variable factors peculiar to that case, and we must judge it under a rule of reason. A court’s task, applying the rule of reason, is to determine whether the EIS contains a reasonably thorough discussion of the significant aspects of the probable environmental consequences. Half Moon Bay, 857 F.2d at 508. When no statistically meaningful projections can be made of future outcomes, relationships between variables may be properly examined, as BPA did here. We conclude that the analysis done in the BP EIS constitutes a reasonably “hard look” at long-term environmental harms.

I.CONSIDERATION OF A TRUE “NO ACTION” ALTERNATIVE

Petitioners assert that the BP EIS does not examine a true “no action” alternative which would involve not signing any agreements for power or transmission with the DSIs.

The “no action” alternative examined by the BP EIS, defined as continuing its pre1994 role which involves continuing its present power sales contracts, is a proper “no action” alternative. CEQ regulations allow the status quo to properly be the no action alternative. “The ‘no action’ alternative may be thought of in terms of continuing with the present course of action until that action is changed.” 46 Fed.Reg. 18026,18027.

Even so, the BP EIS examines part of the “no action” alternative Petitioners specify. “[N]ot providing long-term wheeling for the DSIs” was evaluated as a component of the status quo alternative, and the resulting harmful environmental implications of this course were examined as well. Petitioners failed to demonstrate that the other part of the requested true “no action” alternative, not offering any power contracts to the DSIs, is a viable alternative. See City of Carmel-By-The-Sea, 123 F.3d at 1154-55 (“The Environmental Impact Statement need not consider an infinite range of alternatives, only reasonable or feasible ones.”).

J.CONSISTENCY OF THE BUSINESS PLAN EIS WITH THE BUSINESS PLAN ON TRANSMISSION ACCESS

The BP EIS concludes that BPA would offer wheeling only to the DSIs and not to retail customers. In the BP, however, BPA recognizes the trend toward increasing access of transmission by retail customers and indicates its willingness to move in these new directions.

This potential inconsistency, however, does not present a ripe injury. No contracts have been offered which would allow retail customers transmission access, and BPA does not commit itself in the BP to provide such access. Certainly no harm to the environment has been demonstrated by an indication that BPA might be willing to offer retail wheeling. Therefore, we are unable to consider the merits of the problem.

K. ENVIRONMENTAL CHALLENGES TO THE INITIAL TRANSMISSION AGREEMENTS.

BPA issued a categorical exclusion determination finding that no further environmental analysis was necessary for the Initial Transmission Agreements on April 5, 1996. The Initial Transmission Agreements were then executed in the period from April to June of 1995.

The first petition filed in this case was filed November 27,1995, which is after the ninety-day period to file suit provided by 16 U.S.C. § 839f(e)(5). Thus, Petitioners are jurisdictionally barred from challenging the Initial Transmission Agreements.

CONCLUSION

Widespread deregulation of the electric power industry has transformed the wholesale power markets, creating legal tensions which will endure at least until the market stabilizes. After a careful examination of all the challenges presented in this appeal, we conclude that the Administrator’s decisions in response to market forces were not arbitrary or capricious, and were in accordance with applicable law. We therefore deny the petitions for review.

1

. BPA is to accomplish these tasks with assistance from the Pacific Northwest Electric Power and Conservation Planning Council, a regional agency created by the Northwest Power Act to facilitate cooperation between the states of the Pacific Northwest in fulfilling Congress’s regional environmental planning goals.

2

. The Public Power Council is a non-profit Washington corporation that represents common interests of municipal utilities, utility districts and electric cooperatives in the Pacific Northwest.

3

. NCAC is a non-profit consortium of over 70 organizations, including public and private utilities, ratepayer and environmental groups, and a number of individuals. NCAC was formed after enactment of the Pacific Northwest Electric Power Planning and Conservation Act of 1980, 16 U.S.C. §§ 839-839h, primarily to monitor governmental compliance with the Act’s environmental and resource conservation provisions.

4

. Prior to the enactment of the Energy Policy Act, section 211(c)(1) of the Federal Power Act, 16 U.S.C. § 824j(c)(l), required FERC to determine whether ordering a utility to provide transmission services to another utility would “reasonably preserve existing competitive relationships” before the order could issue. The Energy Policy Act repealed this requirement, Pub.L. 102-486, § 721(4)(A), 106 Stat. 2915 (1992), because Congress felt it “might impede access to transmission services.” H.R. Rep. No. 474(1), 102d Cong., 2d Sess. 194 (1992), reprinted in 1992 U.S.C.C.A.N. 1953, 2017.

5

. After execution of and before the start of performance under the Block Sale Contracts, BPA’s power sales to the DSIs continue to be governed by the 1981 Contracts. Both the Block Sale Contracts and the 1981 Contracts thus remain in effect until BPA begins delivery of power under the former, at which time the 1981 Contracts are terminated.

6

. The Pacific Northwest-Pacific Southwest Inter-tie is a system of high voltage transmission lines that transmits federal and non-federal power between the two regions. California Energy Comm’n v. Bonneville Power Admin., 909 F.2d 1298, 1302 (9th Cir.1990).

7

. While the ALCOA court was speaking in particular of terms of the 1981 Contracts negotiated in compliance with Congress's command in the Northwest Power Act, 16 U.S.C. §§ 839c(d)(l)(B), 839c(g)(l), we see no reason why this statement would not have equal force in negotiating subsequent contracts with the DSIs.

8

. APAC’s argument (raised for the first time in its reply brief) that BPA failed to analyze the effect of providing stranded cost protection to the DSIs after expiration of the Block Sale Contracts is incorrect. BPA executed the Block Sale Contracts, with the section 5(b)(2) stranded investment protection, in order to position itself for a competitive future. The future it saw without the Block Sale Contracts, the only way to have a future without stranded investment protection, was not as attractive as the future with the Contracts.

9

. BPA challenges APAC's standing to raise NEPA claims. We need not decide this issue because Utility Reform Project and Kevin Bell also raise NEPA claims and it is uncontested that these parties have standing.

10

. “The CEQ regulations, supplemented by the [Federal Highway Administration] regulations, implement NEPA.” Price Road Neighborhood Ass’n, Inc. v. United States Dep’t of Transp., 113 F.3d 1505, 1509 (9th Cir.1997).

11

. Northwest Envtl. Defense Ctr. v. Bonneville Power Admin., 117 F.3d 1520, 1534-35 (9th Cir.1997) is not to the contrary. Northwest Envtl. Defense Ctr. recognized a difference between "an alleged procedural violation of a statute that governs the public comment process” (which the court will address even though the claim was not raised in the administrative process, id. at 1535), and a “failure to raise a specific factual contention regarding the substantive content of an EIS during the NEPA public comment process,” id., which is the situation here.

12

. The DSI EIS, published in 1986, addressed the environmental and socioeconomic impacts of the Northwest primary aluminum smelters, all of which were DSIs.