Northeast Utilities Service Co. v. Federal Energy Regulatory Commission

993 F.2d 937

Opinion

BOWNES, Senior Circuit Judge.

These petitions for review challenge the Federal Energy Regulatory Commission’s (“FERC” or “the Commission”) decision to conditionally approve the merger of Northeast Utilities (“NU”) and the Public Service Company of New Hampshire (“PSNH”). Certain joint petitioners and intervenors 1 contend that FERC erred when it: (1) held that the benefits of the merger outweighed its costs; and (2) failed to condition the merger on NU’s waiver of single participant status (“SPS”) in the New England Power Pool (“NEPOOL”). A group of public and private electric utilities, state commissions, state agencies, independent power producers, cogenerators and electric end users 2 claim that FERC erred when it: (1) allowed the consummation of the merger upon the filing of, rather than upon approval of, a transmission tariff; (2) adopted transmission access conditions that gave “native load” customers a priority over other customers; and (3) endorsed “opportunity cost” pricing principles. The Holyoke Gas & Electric Department (“Holyoke”) argues that FERC erred when it failed to: (1) conduct an appropriate review of the environmental impact of the proposed merger; and, (2) make findings regarding allegations of anticompetitive consequences of the merger that were unique to Holyoke. Finally, Northeast Utilities Service Company (“ÑUSCO”) asserts that FERC’s orders changing the terms of three rate schedules filed in conjunction with its merger application were arbitrary, capricious, and an abuse of discretion.

For the reasons which follow, we reject petitioners’ arguments and affirm the Commission’s decisions with the exception of the Commission’s decision to change the terms of the Seabrook Power Contract which we remand for consideration under the “public interest” standard.

1. BACKGROUND.

A. Parties to the Approved Merger.

Northeast Utilities (“NU”) is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). 15 U.S.C. § 79 et seq. (1988). Northeast Utilities Service Company (“ÑUSCO”) is a service company subsidiary of NU and supplies centralized administrative and support services to NU’s operating companies. 3

Prior to the merger, Public Service Company of New Hampshire (“PSNH”) was the largest electric utility in New Hampshire, supplying electric service to some 375,000 retail customers, approximately three-quarters of the State’s population, in every county in the State. PSNH also provided wholesale service to the New Hampshire Electric Cooperative, three New Hampshire municipalities, and one investor-owned utility, Vermont Electric Power Company. PSNH had the largest ownership share, approximately 35.6 percent, of Seabrook Unit No. 1, a nuclear generating facility declared to be available for service on June 30, 1990.

B. The Merger Proposal.

On January 28, 1988, PSNH filed a voluntary petition in the United States Bankruptcy Court for the District of New Hampshire for reorganization under Chapter 11 of the Bankruptcy Code. 11 U.S.C. § 1101 et seq. (1988). PSNH alleged that it was unable to recover in its rates the outlays it had made in the construction and operation of the Sea-brook nuclear power plant. On April 20, 1990, after sifting through several competing reorganization plans, the bankruptcy court approved NU’s proposal to merge with PSNH and to acquire and operate all of PSNH’s power facilities. See In re Public Service Co. of New Hampshire, 963 F.2d 469, 470 (1st Cir.), cert. denied, Rochman v. Northeast Utilities Service Co., - U.S. -, 113 S.Ct. 304, 121 L.Ed.2d 226 (1992).

NU’s proposal contained a two-step process: first, PSNH would emerge from bankruptcy as a stand-alone company bound to a merger agreement with NU; second, PSNH would be merged with an NU subsidiary created solely for the acquisition (NU Acquisition Corporation), with PSNH emerging as the surviving entity. After the merger, PSNH would be a wholly-owned subsidiary of NU and would transfer its ownership interest in Seabrook to a newly formed NU subsidiary, North Atlantic Energy Corpora tion (“North Atlantic”). The second step would occur only after all necessary approvals were received from the relevant regulatory agencies.

C. Procedural History.

On January 8, 1990, ÑUSCO, on behalf of NU and NU’s operating subsidiaries, filed an application with FERC under section 203 of the Federal Power Act (“FPA”), 16 U.S.C. § 824b (1988), seeking authorization for PSNH to dispose of all of its jurisdictional facilities and concurrently to merge with, and become a subsidiary of, NU. In connection with this application, ÑUSCO filed four rate schedules with FERC pursuant to § 205 of the FPA: the Seabrook Power Contract, 4 the Sharing Agreement 5 and two Capacity Interchange Agreements. 6

The Commission consolidated consideration of the merger application and rate schedules, accepted the rate schedules for filing and suspended their effectiveness, and set for hearings before an administrative law judge (“ALJ”) the questions of whether the Commission should grant the § 203 application and approve the rate schedules. See Northeast Utilities Service Co., 50 F.E.R.C. ¶ 61,266, reh’g granted in part and denied in part, 51 F.E.R.C. ¶ 61,177 (1990). In its order, the Commission directed the parties to address the effect of the proposed merger on NU’s market power and “whether any transmission conditions are necessary to eliminate any adverse effect of the proposed merger and, if so, what specific conditions should be imposed.” 50 F.E.R.C. at 61,834-35.

On December 20, 1990, the ALJ issued its Initial Decision approving the § 203 application and the rate schedules with certain modifications and conditions. Northeast Utilities Service Co., 53 F.E.R.C. ¶ 63,020 (1990). The Commission, in Opinion No. 364, issued on August 9, 1991, affirmed in part and reversed in part the ALJ’s decision, conditionally approving the § 203 application and the rate schedules. Northeast Utilities Service Co., 56 F.E.R.C. ¶ 61,269 (1991). On January 29, 1992, after considering additional filings by the parties and oral argument on transmission pricing issues, the Commission issued Opinion No. 364-A, affirming its conditional approval of the § 203 application and rate schedules. Northeast Utilities Service Co., 58 F.E.R.C. ¶ 61,070 (1992).

Petitions for review of Opinions No. 364 and 364-A were filed in this court and in the District of Columbia Circuit Court. The Judicial Panel on Multidistrict Litigation consolidated these petitions for review in this court, where further petitions for review were filed. 28 U.S.C. § 2112(a) (1988). Subsequently, in Opinion No. 364-B, the Commission denied a request for rehearing of Opinion No. 364-A. Northeast Utilities Service Co., 59 F.E.R.C. ¶ 61,042 (1992). A petition for review of Opinions No. 364-A and 364-B was filed in this court, where it was consolidated with the earlier filed petitions. We review the Commission’s orders under the jurisdiction established by 16 U.S.C. § 825Í.

II. STANDARD OF REVIEW.

On review, we give great deference to the Commission’s decision. U.S. Dep’t of Interior v. FERC, 952 F.2d 538, 543 (D.C.Cir.1992). FERC’s findings of fact are reviewed under the “substantial evidence” standard of review. 16 U.S.C. § 825i (“The finding of the Commission as to the facts, if supported by substantial evidence, shall be conclusive.”). Therefore,

[w]e defer to the agency’s expertise, particularly where the statute prescribes few specific standards for the agency to follow, so long as its decision is supported by “substantial evidence” in the record and reached by “reasoned decisionmaking,” including an examination of the relevant data and a reasoned explanation supported by a stated connection between the facts found and the choice made.

Electricity Consumers Resource Council v. FERC, 747 F.2d 1511, 1513 (D.C.Cir.1984). “Pure” legal errors require no deference to agency expertise, and are reviewed de novo. Questions involving an interpretation of the FPA involve a de novo determination by the court of Congressional intent; if that intent is ambiguous, FERC’s conclusion will only be rejected if it is unreasonable. Chevron USA v. Natural Resources Defense Council, 467 U.S. 837, 842-45, 104 S.Ct. 2778, 2781-83, 81 L.Ed.2d 694 (1984); Boston Edison Co. v. FERC, 856 F.2d 361, 363 (1st Cir.1988).

III. DISCUSSION.

A. Conditional Approval of the Merger.

1. Background.

In reaching his decision to approve the NU-PSNH merger, the ALJ found that the merger would produce significant benefits. Specifically, he found that: (1) PSNH would emerge from bankruptcy as a viable utility on a solid financial footing, 53 F.E.R.C. at 65,211; (2) improved management techniques and economies of scale would reduce the operating costs of Seabrook by some $527 million, 7 id. at 65,212; (3) application of NU operating procedures to PSNH’s fossil steam plants would save $100 million, id. at 65,213; (4) reductions in administrative and general expenses would save $124 million, id.; (5) NU’s record of buying lower-priced coal on the spot market would save $39 million, id.; and (6) the merger would yield $360 million in savings for NU because of its ability to elect “single participant status” in the New England Power Pool (NEPOOL), a power pool comprised of most of the utilities in New England. Id.

The ALJ also found that unless several conditions were imposed, the merger would have short- and long-term anticompetitive consequences because of the merged company’s increased market power over key transmission facilities in both the New England region and the Rhode Island and Eastern Massachusetts submarket (“Eastern REM-VEC”). 53 F.E.R.C. at 65,214-19. Under the authority of § 203(b) of the FPA, 16 U.S.C. § 824b(b), the ALJ approved the merger subject to several conditions, including the following: (1) the merged company must offer firm (non-interruptible) transmission service for a minimum of 30 days and a maximum of 20 years, 53 F.E.R.C. at 65,220-21; (2) non-firm service must be offered for a one-day minimum term, id. at 65,220; (3) the merger would be consummated concurrently with the filing of a compliance tariff which fully reflects all of the terms and conditions set out in the ALJ’s Initial Decision, id. at 65,221; (4) NU must implement its New Hampshire Corridor Proposal, 8 thereby making available 400 MW of transmission capacity for wheeling 9 by utilities in both northern and southern New England, id. at 65,225-27; and (5) the merged company’s veto power on NEPOOL’s Management Committee would be restricted for the ninety day period immediately following consummation of the merger, id at 65,230-31.

In Opinion No. 364, the Commission affirmed the ALJ’s finding that the merger, with appropriate conditions, was consistent with the public interest. 56 F.E.R.C. at 62,011. It held, however, that the $364 million cost-shift between NU-PSNH and other NE-POOL members should not have been counted as a benefit of the merger because it simply shifted costs dollar-for-dollar among the membership without any net savings. 10 56 F.E.R.C. at 61,997. The Commission also held that, in evaluating the costs and benefits of the merger, the ALJ correctly attributed the benefits resulting from the merger to the merger even if those benefits could have been achieved by other means. 11 Id. at 61,-994-96. This conclusion was reiterated on rehearing in Opinion No. 364-A. 58 F.E.R.C. at 61,186-87.

Petitioners and intervenors argue that FERC erred, as a matter of law, in holding that the benefits of the merger outweighed its costs.

2. The Statutory Standard.

FERC’s authority to consider the merger applications of utilities is set forth in § 203(a) of the FPA, 16 U.S.C. § 824b(a): the Commission “shall approve” a proposed merger of utility facilities if, “[ajfter notice and opportunity for hearing, ... the Commission finds that the proposed disposition, consolidation, acquisition, or control will be consistent with the public interest.” Id. The Commission has the additional authority to grant approval for such transactions “upon such terms and conditions as it finds necessary or appropriate to secure the maintenance of adequate service and the coordination in the public interest of facilities subject to the jurisdiction of the Commission.” 16 U.S.C. § 824b(b). As the Commission noted when it reviewed the Initial Decision of the ALJ,

[mjerger applicants need not show that a positive benefit will result from a proposed merger. The applicant must fully disclose all material facts and show affirmatively that the merger is consistent with the public interest. It is sufficient if the “probable merger benefits ... add up to substantially more than the costs of the merger.”

56 F.E.R.C. at 61,994 (quoting Utah Power & Light Co., 47 F.E.R.C. at 61,750 (1989) (footnotes omitted); see also Pacific Power & Light Co. v. Federal Power Commission, 111 F.2d 1014, 1016 (9th Cir.1940). We review the record, therefore, to determine whether the Commission’s finding that the probable benefits of the NU-PSNH merger were substantially more than its costs was supported by substantial evidence.

3. Discussion.

Petitioners make two claims with regard to FERC’s evaluation of the costs and benefits of the NU-PSNH merger. First, they argue that the Commission should not have included resolution of PSNH’s bankruptcy as a benefit of the merger because: (1) PSNH actually emerged from bankruptcy on May 16, 1991, the effective date of the Reorganization Plan (“RP”); and (2) prior to gaining the bankruptcy court’s approval of the two-step RP, PSNH had to show that it would be financially viable as a stand-alone entity because regulatory approval for the second step of the RP (merger with and into NU) was not assured. These two facts, however, do not imply that it was error for FERC to consider the “resolution of PSNH’s bankruptcy” as a benefit, indeed as a principal benefit, of the merger.

It is true that PSNH, as a technical matter, “emerged” from bankruptcy prior to FERC’s consideration of the proposed merger. The ALJ and the Commission did not hold otherwise. The ALJ stated, and the Commission summarily affirmed the fact that “[t]he merger is part of apian which enables a reorganized PSNH to emerge from bankruptcy.” 53 F.E.R.C. at 65,211 (emphasis added); see also 56 F.E.R.C. at 61,993. Like the state regulators who approved the two-step merger plan, the Commission evaluated the plan as a whole, anticipating “the merger — not ‘stand alone’ PSNH — as the ultimate destiny for the reorganized company.” 53 F.E.R.C. at 65,211. “All parties to the reorganization contemplated [stand alone] status as an interim step en route to the merger.” Id. It was the entire plan, which admittedly had two sequential and severable steps, that allowed PSNH to emerge from bankruptcy. There is no evidence that the state regulators would have approved a plan to allow PSNH to emerge from bankruptcy that included only the first “stand alone” step. Indeed, there is evidence to the contrary.

FERC also found that “resolving” PSNH’s bankruptcy meant more than simply the emergence of PSNH from the protection of bankruptcy court. FERC held that the final resolution of PSNH’s bankruptcy included the treatment of its creditors and stockholders who stood to lose approximately $250 million in the absence of the merger. As the ALJ observed, the Commission “regard[s] the right of these public bondholders as of primary importance after the consumers have been protected.” 53 F.E.R.C. at 65,211 (quoting In re Evans, 1 F.P.C. 511, 517 (1937) (approving an acquisition involving the reorganization of a bankrupt utility)). The Commission also held that it was in the public interest to approve the creation of a stronger, more viable merged entity, rather than leaving PSNH in a “weakened”, “stand alone” state. This holding was sufficiently supported by evidence in the record.

Petitioners also claim that, given the bankruptcy court’s “feasibility finding” required by 11 U.S.C. § 1129(a)(ll), 12 the Commission was estopped from reaching the conclusion that a “stand alone” PSNH would be “weak.” We disagree. The bankruptcy court and FERC evaluated the merger proposal under different standards. The bankruptcy court was required to determine the likelihood of further liquidation or reorganization proceedings were the plan to be approved. FERC was obliged to determine whether the plan was “consistent with the public interest.” It was not inconsistent for FERC to find that although PSNH was capable of surviving as a stand alone entity, it would not be “consistent with the public interest” to prevent a merger that would result in an even stronger utility. The principles of estoppel simply do not apply in a case such as this, where the issues litigated and the standards applied in the two proceedings are so different.

Even were petitioners correct in their asseveration that FERC improperly counted the resolution of PSNH’s bankruptcy as a benefit of the merger, “the Commission’s error would be immaterial in light of the overwhelming excess of other benefits ($791 million) over the costs (0) still attributable ... to the acquisition.” City of Holyoke Gas & Elec. Dep’t v. S.E.C., 972 F.2d 358, 362 (D.C.Cir.1992).

Second, petitioners argue that FERC erred as a matter of law in weighing as merger benefits results or alleged savings that were, or could be, achieved by “alternate means.” Specifically, petitioners contend that FERC’s failure to apply the “alternate means” test contradicted general agency policy and general antitrust principles.

It is undisputed that utilities are “not immune” from antitrust laws. Otter Tail Power Co. v. U.S., 410 U.S. 366, 372-75, 93 S.Ct. 1022, 1027-28, 35 L.Ed.2d 359 (1973); Town of Concord v. Boston Edison, 915 F.2d 17 (1st Cir.1990), cert. denied, - U.S. -, 111 S.Ct. 1337, 113 L.Ed.2d 268 (1991). At issue in this case is whether FERC is required by statute, or otherwise, to engage in “standard” antitrust analysis before passing on § 203 merger applications. In claiming that FERC has such an obligation, petitioners rely on a statute governing agency approval of bank mergers (the “Bank Merger Act”) which states that the agency with jurisdiction over a proposed bank merger, 13

shall not approve — •

(A) any proposed merger transaction which would result in a monopoly, or which would be in furtherance of any combination or conspiracy to monopolize or to attempt to monopolize the business of banking in any part of the United States, or

(B) any other proposed merger transaction whose effect in any section of the country may be substantially to lessen competition, or to tend to create a monopoly, or which in any other manner would be in restraint of trade, unless it finds that the anticompetitive effects of the proposed transaction are clearly outweighed in the public interest by the probable effects of the transaction in meeting the convenience and needs of the community to be served_

(6) The responsible agency shall immediately notify the Attorney General of any approval by it pursuant to this subsection of a proposed merger transaction.

12 U.S.C. § 1828(c)(5) — (6). The Supreme Court, interpreting the Bank Merger Act, has held that before a bank merger which is injurious to the public interest may be approved, “a showing [must] be made that the gain expected from the merger cannot reasonably be expected through other means.” U.S. v. Phillipsburg Nat. Bank & Trust Co., 399 U.S. 350, 372, 90 S.Ct. 2035, 2048, 26 L.Ed.2d 658 (1970). Petitioners claim that the language of the Bank Merger Act is sufficiently similar to the statute governing FERC’s approval of proposed mergers, 16 U.S.C. § 824b(a), because both contain a “public interest” standard, to require FERC to use the “alternate means” test which bank regulators must use in evaluating proposed bank mergers. We disagree.

As with any matter of statutory construction, we first examine the language of the statute. Under 16 U.S.C. § 824b(a), the Commission is required, after notice and opportunity for hearing, to approve a proposed merger of utility facilities if it finds that the proposal “will be consistent with the public interest.” That is all the statute says. There is no explicit reference to antitrust policies or principles. There is no evidence that Congress sought to have the Commission serve as an enforcer of antitrust policy in conjunction with the Department of Justice and the Federal Trade Commission. The Bank Merger Act reveals a quite different intention. There, Congress explicitly set out standards for approval of bank mergers that incorporate principles embodied in the Sherman and Clayton Acts. 12 U.S.C. § 1828(c)(5). By requiring the reviewing agency to notify the Attorney General of any decision to approve a proposed bank merger, 12 U.S.C. § 1828(c)(6), Congress expressed its desire to have bank regulators serve as pre-screening bodies of mergers which, because of their importance or character, in most cases also deserve the attention of the Department of Justice.

The Bank Merger Act carries with it the implicit presumption that mergers are to be disapproved (the agency “shall not approve” a bank merger “unless it finds that the anticompetitive effects are clearly outweighed in the public interest” by the benefits of the merger, 12 U.S.C. § 1828(c)(5)). The FPA, on the other hand, requires the Commission to approve any merger that is “consistent with the public interest.” 16 U.S.C. § 824b(a). Antitrust considerations are, of course, relevant in FERC’s consideration of the “public interest” in merger proposals. The statute, however, does not require FERC to analyze proposed mergers under the same standards that the Department of Justice or bank regulators must apply.

Although the Commission must include antitrust considerations in its public interest calculus under the FPA, it is not bound to use antitrust principles when they may be inconsistent "with the Commission’s regulatory goals. See Otter Tail, 410 U.S. at 373, 93 S.Ct. at 1028 (“[although antitrust considerations may be relevant [in determining the public interest], they are not determinative”). In Town of Concord, this court observed that indiscriminate incorporation of antitrust policy into utility regulation “could undercut the very objectives the antitrust laws are designed to serve.” 915 F.2d at 22. Therefore, “antitrust analysis must sensitively ‘recognize and reflect the distinctive economic and legal setting’ of the regulated industry to which it applies.” Id. (quoting Watson & Brunner, Monopolization by Regulated “Monopolies”: The Search for Substantive Standards, 22 Antitrust Bull. 559, 565 (1977)).

Petitioners may rest assured that were FERC to approve a merger of utilities which ran afoul of Sherman Act or other antitrust policies, the utilities would be subject to either prosecution by government officials responsible for policing the antitrust laws, or to suit by private citizens meeting the requirements of standing. See Otter Tail, 410 U.S. at 374-75, 93 S.Ct. at 1028.

B. FERC’s Failure to Condition Merger on NU’s Waiver of Single Participant Status.

Petitioners argue that the Commission erred in failing to condition the merger on waiver by NU and PSNH of “single participant status” (“SPS”) in the New England Power Pool (“NEPOOL”), thereby preventing the imposition of a $364 million cost shift from NU and PSNH to the other members of NEPOOL.

NEPOOL is a power pool comprised of most of the utilities in New England. The association is governed by the New England Power Pool Agreement (“the Agreement”) which establishes a “comprehensive interconnection and coordination arrangement” among its members in order “to achieve greater reliability and economies in the production of electricity.” Groton v. FERC, 587 F.2d 1296, 1298 (D.C.Cir.1978). Section 202(a) of the Federal Power Act encourages such voluntary interconnection and coordination of electricity generating facilities in order to achieve economies of scale. 16 U.S.C. § 824a; see also 16 U.S.C. § 824a-l (regarding pooling agreements). The Agreement was approved as a filed rate schedule by FERC’s predecessor, the Federal Power Commission. 53 F.E.R.C. at 65,213. Under its terms, each member is required to supply the pool with resources (“Capacity Responsibility”) according to a formula based upon the relationship of the member’s peak load to an estimate of aggregate peak load of all members.

NU experiences its peak load in the summer, and PSNH experiences its peak load in the winter. By aggregating these two, complementary, peak loads, NU-PSNH can achieve a lower Capacity Responsibility than would be the case if the two utilities remained separate. Because the overall capacity requirements of NEPOOL will not change as a result of the merger, the Capacity Responsibilities of other members must rise to make up for the savings accruing to NU-PSNH. The ALJ accepted the “undisputed” estimate that “single participant status” (SPS) will result in a shifting of some $360 million in costs from NU-PSNH to other members of the pool. Id.

2. Discussion.

Petitioners offer six arguments to support their claim that FERC erred in failing to condition the merger on waiver of SPS by NU and PSNH. First, petitioners claim that the Commission did not properly interpret the provision of the NEPOOL Agreement which governs the election of SPS. We agree with the Commission’s finding that the Agreement both specifically allows for the election by NU-PSNH of SPS, and encourages such elections. Section 3.1 of the Agreement provides in relevant part that:

All Entities which are controlled by a single person (such as a corporation or a common law business trust) which owns at least seventy-five percent of the voting shares of each of them shall be collectively treated as a single Participant for purposes of this Agreement, if they elect such treatment. They are encouraged to do so. Such an election shall be made by signing the appropriate form at the end of a counterpart of this Agreement.

(Emphasis supplied.) Both the ALJ and the Commission interpreted section 3.1 to be an explicit endorsement of the election of SPS by NU-PSNH. The ALJ stated that “[i]t is undisputed that NU and PSNH qualify for such [single participant] status under the Agreement.” 53 F.E.R.C. at 65,213. The Commission gave great weight to the unre-butted testimony of witness Bigelow, who participated in the negotiation of the NE-POOL Agreement regarding the intent of the original signatories to the Agreement and their recognition of such potentially large cost-shifts among NEPOOL members. Bigelow stated:

[W]hen we put NEPOOL together 20 years ago, we recognized that these things might happen. This is not something that snuck up on people_ And we did discuss at length what would happen because ... we were then coming up to a potential merger of Boston Edison, Eastern Utilities, New England Power. It was recognized that these kinds of things could happen in the future and we spelled out the ground rules and recognized that that would happen when it happened. And the people who didn’t like it got something else for it.

53 F.E.R.C. at 65,214. Both the ALJ and the Commission rejected petitioners’ claim on the basis of both the language of the Agreement, and Bigelow’s unrebutted testimony that not only had the signatories been aware of such a potentially large savings shift, but that those utilities that were dissatisfied with this risk received additional concessions as compensation. We will not disturb the Commission’s findings.

Second, petitioners claim that the Agreement, as interpreted in NEPOOL Power Pool Agreement, 56 F.P.C. 1562, 1580 (1976), aff'd sub nom. Municipalities of Groton v. FERC, 587 F.2d 1296 (D.C.Cir.1978), prohibits utilities with peak loads in different seasons from electing SPS. As the Commission explained, this argument mischaracterizes the Agreement and the decision of the Federal Power Commission (“FPC”) in NE-POOL.

The NEPOOL Agreement, as initially filed and as approved, allowed single participant status for utilities controlled by a single “person” owning at least 75 percent of the voting shares of each utility. An exception was expressly allowed in the filed agreement for any Vermont utility which elected to be grouped with Vermont Electric Power Company. This exception was approved for essentially two reasons: (1) the Vermont utilities had long acted as a single contiguous integrated electric entity; and (2) since they all experienced their peak loads in winter, single participant status would not give them a lower NEPOOL Capability Responsibility (and consequent savings). A broader exception was denied, however, for a group of municipal utilities (represented by MMWEC) that was not entitled to single participant status and that lacked the two cited attributes of the Vermont utilities. The basis for the denial was that allowing such status for “any group of systems, such as MMWEC, could well be detrimental to the functioning of NEPOOL.”

The NEPOOL decision, thus, does not stand for the proposition that single participant status is available only to utilities having their peak loads in the same season. Instead, another way, indeed the primary way, in which utilities may qualify is if they are controlled by a single person with at least 75-percent common ownership. That is the basis upon which NU and PSNH will presumably seek to qualify if the merger is approved. Such status is expressly allowed under the NEPOOL Agreement regardless of when NU and PSNH experience their peak loads.

56 F.E.R.C. at 61,996-97. The reasons offered by the FPC in its decision to grant a special exception for Vermont utilities seeking SPS were not intended to be, and are not, conditions, in addition to those set out in the Agreement, which must be satisfied to elect SPS. The FPC did not narrow the scope of Section 3.1 to apply only to utilities sharing the same peak load season; rather, it created a special exception to the 75 percent rule to accommodate the unique situation faced by Vermont utilities.

Third, petitioners claim that FERC failed to give proper consideration to Section 4.2 of the Agreement, “the interests of other pool members, and the purpose of the Agreement as a whole.” Essentially, petitioners argue that allowing NU-PSNH to elect SPS would violate a general provision of the Agreement, which states that participants “shall not ... take advantage of the provisions of this Agreement so as to harm another Participant or to prejudice the position of any Participant in the electric utility business.” We reject this argument for the same reasons expressed by the Commission in its decision denying petitioners’ request for a rehearing:

[W]e find more relevance in the NEPOOL Agreement’s explicit endorsement of single participant status than in the agreement’s general goal of “equitable sharing” and prohibition on members “taking advantage” of the agreement to harm or prejudice other members. The NEPOOL Agreement specifically encourages eligible parties to seek single participant status; the provisions cited by the intervenors are general, not specific. Construing the general consistent with the specific, we find single participant status for the merged company consistent with an equitable sharing, as envisioned by the NEPOOL Agreement, and not violative of the ban on taking advantage of the agreement’s provisions to harm or prejudice other members.

58 F.E.R.C. at 61,189. We agree with FERC’s interpretation of the Agreement. The NEPOOL signatories explicitly encouraged qualified members to seek SPS, indeed they contemplated that members that merged might choose to do just that. We agree with the Commission’s construction of the Agreement which avoids a direct conflict between Sections 3.1 and 4.2, and instead gives both provisions reasonable effect.

Fourth, petitioners argue that failure to condition the merger on waiver of SPS would create “serious disincentives” for current members to continue their membership in NEPOOL, and that the breakup of NEPOOL is contrary to the public interest. Petitioners imply that FERC did not take seriously their complaints about SPS, but rather rested its decision not to require a waiver solely on the fact that the Agreement allowed the election of SPS., This is simply not so.

The Commission reversed the ALJ on the issue of whether SPS savings should be counted as a, benefit of the merger. The Commission found that because the cost shift amounted to a zero-sum transaction, with NU and PSNH benefiting and the other members burdened dollar-for-dollar, the shift could not be counted as a benefit of the merger. 56 F.E.R.C. at 61,997. , Thus, the Commission did not dismiss petitioners’ claims regarding SPS without thought.

Also, the ALJ found, and the Commission agreed, that SPS was essential to the merger, and that the merger, as conditioned, was in the public interest. FERC must approve a proposed merger if it is consistent with the public interest. 16 U.S.C. § 824b(a). FERC has the discretion to add conditions to a proposed merger to ensure that the merger will, taken as a whole, be in the public interest. 16 U:S.C. § 824b(b). FERC need not, however, explain why every condition, or failure to establish a condition is consistent with the public interest when considered separately and apart from the entire transaction. Petitioners seem to argue that FERC was required by law to state why it was consistent with the public interest to follow the explicit terms of the approved fifteen year-old NEPOOL Agreement rather than to condition the merger on waiver of a membership right established by the Agreement. FERC had no such obligation. It need not have explained why it failed to add a particular condition prior to approving a merger. The statute simply provides that “[t]he Commission may grant any application for an order under this section in whole or in part and upon such terms and conditions as it finds necessary or appropriate to secure the maintenance of adequate service and coordination in the public interest of facilities subject to the jurisdiction of the Commission.” 16 U.S.C. § 824b(b). In this case, the Commission set forth a reasonable basis for approving the merger as consistent with the public interest in light of the supplementary conditions the Commission found necessary. FERC need not have gone further than this to explain why it failed to place further conditions on the merger.

Fifth, petitioners allege that FERC acted inconsistently in its treatment of the NEPOOL Agreement’s provisions regarding voting rights and SPS. The Commission adopted a condition limiting the merged company’s NEPOOL voting rights to prevent PSNH and NU from gaining a veto power in NEPOOL. 56 F.E.R.C. at 62,043-45. FERC reasoned that, while there was evidence that the signatories anticipated that large cost-shifts would accompany the election of SPS in merger situations, there was no evidence that they anticipated the voting rights implications of such mergers. 58 F.E.R.C. at 61,189. It was not, contrary to petitioners’ argument, inconsistent as a mat ter of logic to condition voting rights where the Agreement was silent on the need or lack of need to do so, while failing to condition SPS where the Agreement explicitly favored the election of SPS. Furthermore, it was not an error of law to condition voting rights while leaving SPS rights untouched. Petitioners do not contest the Commission’s decision to condition NU-PSNH’s voting rights. We will uphold whatever conditions the Commission imposes on a proposed merger so long as their necessity is supported in the record by substantial evidence.

Finally, petitioners contend that the Commission “failed to explain why burdening other NEPOOL members with $864 million in additional costs with no offsetting benefits to them is consistent with the public interest.” In making this argument, petitioners imply that each and every piece of a complex package of merger agreements and conditions must be able to withstand “public interest” analysis without regard to other pieces of the package or to other conditions imposed by the Commission. Petitioners also imply that if any individual or group is harmed by a piece of the package, that provision is not in the public interest and must therefore be stricken or modified. Both implicit arguments are deeply flawed.

In evaluating a transaction such as the one at issue here, the Commission is required to find that the entire transaction, taken as a whole, is consistent with the public interest. 16 U.S.C. § 824b(a). Each element of the transaction need not benefit every utility or individual which might be affected; rather, the whole transaction must be consistent with the interest of “the public.” There is no reason to think that the interest of individual NEPOOL members is synonymous with the “public” interest. As has already been noted, FERC may add conditions to a proposed merger before granting approval. 16 U.S.C. § 824b (b). The statute does not require, however, that FERC establish conditions so that every effect of an approved merger could withstand the “public interest” test.

At a less theoretical level, the ALJ determined that the NEPOOL savings “were a vital part of the long and strenuous negotiations which culminated in the resulting PSNH reorganization plan,” and the particular savings of $146 million for New Hampshire consumers were relied on specifically by the State of New Hampshire in approving the merged company’s rate package. 53 F.E.R.C. at 65,213. The Commission accepted this finding of the ALJ, while, at the same time, it reversed the ALJ’s decision to count the $360 million as a benefit of the merger. 58 F.E.R.C. at 61,997. The fact that the cost-shift was not a benefit to be counted in weighing the benefits and costs of the merger does not mean that the election of SPS and the concomitant cost-shift is not in the public interest. Election of SPS is in the public interest because it is a central element of the merger plan which, viewed as a whole, was found by FERC to be consistent with the public interest based on substantial evidence in the record. We approve the Commission’s decision not to condition the merger on waiver by NU of SPS.

C. Timing of Merger’s Consummation.

In the proceedings before the ALJ, NU proposed filing a transmission tariff within 60 days following the merger. Inter-venors and Commission staff proposed the filing and approval of an interim transmission rate. The ALJ rejected both proposals and instead held that the merger would be consummated upon the filing of NU’s compliance tariff. He reasoned as follows:

I see no need for requiring one tariff (with potential for controversy, charges, collections and refunds) to be followed by yet another tariff, with its own potential for still other disputes.

Avoiding a transitional period will make it unnecessary to require a transitional tariff. To achieve this result, consummation of the merger must be conditioned on the concurrent filing of a compliance tariff which fully reflects all of the terms and conditions set out in this Initial Decision. Such a condition should encourage a prompt and fair compliance filing because NU could not begin to reap the merger benefits without it.

53 F.E.R.C. at 65,221. The Commission concurred:

We believe the GTC [General Transmission Conditions] and the NH Corridor Proposal, as modified herein, adequately mitigate the merger’s anticompetitive effects without requiring the adoption of the Merger Tariff. Trial Staff stated that the Merger Tariff would make service available immediately upon approval of the merger. We believe that the presiding judge accomplished the same result by allowing consummation of the merger when NU submits its compliance filing.

We further believe that delaying the merger’s consummation until the Commission accepts NU’s compliance submittal for filing would be inappropriate given the uncertainty surrounding issues which may be challenged and subject to further litigation in the compliance proceeding and given our commitment to act before the Merger Agreement’s December 31, 1991 termination date. We believe that NU and PSNH are entitled to a prompt and fair resolution of this proceeding. At the same time the intervenors are entitled to have service begin as soon as practical, together with a fair resolution of any disputes raised regarding NU’s compliance filing. Accordingly, we believe that it is in the best interests of all parties to allow NU to consummate the merger when it submits its compliance filing. We shall also require NU to begin honoring such requests for transmission service under the GTC, as modified herein, at that time. Such transmission service will be provided at either the firm or non-firm transmission rates proposed in NU’s compliance filing, subject to refund, and without a refund floor. In reviewing NU’s filing to ensure compliance with this Opinion, we will hold NU to a very high standard. As NU itself states, “[i]f NU fails to comply with the letter or spirit of such [Commission] requirement, NU would be subject to summary judgment with respect to any aspect of its compliance filing.”

56 F.E.R.C. at 62,025.

Petitioners’ stated concern is that, by allowing the merger to be consummated prior to FERC’s approval of the compliance tariff, FERC did not provide a sufficient guaranty that NU would provide transmission access that would mitigate the merger’s anticompet-itive effects. 14 Petitioners do not, however, seek, to unravel the merger. Rather, they propose that any cost shift under the NE-POOL Agreement, see discussion in Part III(B), supra, be postponed until after the compliance tariff is approved. Petitioners complain that the course chosen by FERC creates an incentive on the part of NU to delay proceedings on the compliance tariff, thereby maximizing competitive advantage. Petitioners do not, of course, point out that their proposal would create an incentive on their part to delay final approval of the compliance tariff, thereby postponing the day when the NEPOOL cost shift will take effect.

The ALJ and the Commission carefully considered the alternatives before reaching their decisions. The Commission held that the anticompetitive effects of the merger would be adequately mitigated by the dual requirements that NU immediately provide transmission access upon the filing of its compliance tariff, and that any fees collected by NU would be subject to refund without a refund floor. Because NU accepted these merger conditions, the Commission can enforce NU’s promise to pay such refunds if the Commission finds them to be appropriate. See Distrigas of Massachusetts Corp. v. FERC, 737 F.2d 1208, 1225 (1st Cir.1984). FERC explicitly warned NU that “[i]n reviewing NU’s filing to ensure compliance with this Opinion, we will hold NU to a very high standard.” 56 F.E.R.C. at 62,025.

The Commission balanced the merging companies’ need for a “prompt and fair resolution” of the merger proceeding against the intervenors’ need “to have [transmission] service begin as soon as practical, together with a fair resolution of any disputes raised regarding NU’s compliance filing.” 56 F.E.R.C. at 62,025. An agency’s discretion is at its “zenith” when it fashions remedies to effectuate the charge entrusted to it by Con gress. Niagara Power Corp. v. FPC, 379 F.2d 153, 159 (D.C.Cir.1967). See also, Consolo v. FMC, 383 U.S. 607, 620-21, 86 S.Ct. 1018, 1026-27, 16 L.Ed.2d 131 (1966); Environmental Action, Inc. v. FERC, 939 F.2d 1057, 1064 (D.C.Cir.1991); Boston Edison Co. v. FERC, 856 F.2d 361, 371 (1st Cir.1988). We hold that FERC’s exercise of its discretion was not inappropriate in these circumstances. FERC did not defer, as petitioners suggest, consideration of the anticom-petitive effects of the merger which FERC itself identified. The Commission recognized the effects, and dealt with them in a reasoned way which balanced the competing interests of all parties. FERC’s remedy is not unreasonable, and we therefore affirm its order.

D. Protection of Native Load Customers.

1. Priority of Services.

a. Background.

In its merger application, NU made a voluntary commitment to provide wholesale transmission service, including third party wheeling service, 15 for any utility over its existing transmission system. At the same time, NU sought to limit this obligation by reserving an absolute priority for power purchases on behalf of native load customers (whose power needs NU is bound by franchise or contract to meet). The ALJ held that although NU may reasonably give native load service priority over wheeling service if NU’s transmission system had insufficient capacity to serve both, 53 F.E.R.C. at 65,221-222, NU could not deny firm wheeling-requests based upon the reservation of transmission capacity for its own non-firm sales, id. at 65,225.

In Opinion No. 364, the Commission balanced the interests of native load customers and third party wheeling customers and affirmed the AL J’s denial of an absolute priority:

we ... deny NU’s proposal to give higher priority to its own non-firm use than to third party requests for firm wheeling in allocating existing transmission capacity. In no event, however, will NU be required to provide firm third party wheeling service out of existing transmission facilities if reliability of service to native load customers would be adversely affected.

56 F.E.R.C. at 62,021 (footnote omitted). The Commission found it “reasonable to allow NU to reserve firm transmission capacity to provide reliable service to its native load customers.” Id. (Emphasis in original.)

On rehearing, NU asked the Commission to clarify the scope of the “reliability” criterion. The Commission “reiterate[d] that under no circumstances will NU be required to provide firm wheeling service out of existing transmission capacity where doing so would impair or degrade reliability of service to native load customers.” 58 F.E.R.C. at 61,199 (emphasis removed). The Commission held the concept of reliability generally encompasses the: (1) reservation of transmission capacity to back up large generating units; (2) provision of generation reserves; and (3) coverage of certain future needs. As to the coverage of future demand requirements, the Commission specifically ordered that “any capacity needed for reliability purposes within a reasonable planning horizon must be offered for wheeling use until NU expects to need the capacity for reliability reasons.” Id. at 61, 199-200.

Petitioners assert that the decision to accord a priority to native load over transmission load is arbitrary, discriminatory, and anticompetitive. They argue that FERC neither defined nor justified the priority granted by allowing reservation of transmission capacity for native load service and that any such priority creates competitive advantages for NU. We hold that the Commission adequately defined and reasonably justified its decision to allow such a reservation and properly addressed the anticompetitive concerns raised by the intervenors.

b. Discussion.

Although the Commission reaffirmed the general rule that firm transmission service should be accorded priority over non-firm service, even if the latter would benefit native load, it nonetheless allowed NU to reserve firm transmission capacity needed to ensure reliability of native load service and allowed the use of this capacity for non-firm transactions. 58 F.E.R.C. at 61,196. Thus, native load service will receive a “priority” over third-party wheeling service in allocating existing transmission capacity when reliability of service to native load would be adversely affected. The Commission specifically qualified this priority by requiring NU to offer the capacity for wheeling use until NU needed it to assure reliability to native load customers.

There is nothing arbitrary or discriminatory about FERC’s decision. It struck a reasonable balance between the competing interests of native load customers and third-party wheeling customers. NU-PSNH is obligated to serve its native load customers. In return for this obligation to serve, the native load customers regularly bear the cost of transmission facilities; native load customers pay for them, use them, plan on them, and rely on them. As the ALJ noted, “[e]very New England utility favors its own native load. Nothing in the NEPOOL agreement requires its members to surrender their native load preference, and none do.” 53 F.E.R.C. at 65,222. Thus, “NU should be allowed to give priority over safe and reliable service to its native load customers using existing transmission capacity built to serve those customers.” 58 F.E.R.C. at 61,199. FERC explicitly defined and justified the challenged native load “priority.”

2. Transmission Upgrades Pricing.

NU’s commitment to provide third-party transmission service includes the obligation to build additional transmission facilities as necessary to relieve transmission constraints on its system. 58 F.E.R.C. at 61,204-10; 56 F.E.R.C. at 62,021-24. The issue then becomes, how should the cost of constructing such transmission upgrades be allocated. The ALJ stated that questions of cost allocation are best addressed in future proceedings regarding the particular responsibilities for particular facilities. Nevertheless, the ALJ adopted the “but for” analysis for determining responsibility proposed by NU witness Schultheis:

[W]heeling customers must make a pro rata contribution whenever the facilities would not have been needed but for the wheeling transfers across a constrained interface. This means that NU’s native load customers pay for the new facilities they create the need for and wheeling customers pay for the facilities they create the need for.

53 F.E.R.C. at 65,223. The ALJ also noted that the financial exposure of transmission customers was limited by the cost caps to which NU was committed. 16 Id. at 65,224. The Commission agreed that cost questions should be litigated in the context of a specific proposal, and accepted the concept of the “but for” test as a framework for ascertaining cost responsibility and the use of the proposed cost caps as a reasonable means of limiting the transmission customers’ responsibility for future upgrades. 56 F.E.R.C. at 62,028-030. The Commission reaffirmed that decision on rehearing. 58 F.E.R.C. 61,204-207.

Petitioners contend that the Commission failed to adequately explain the pricing policy it will employ in pricing transmission upgrades. Basically, petitioners claim the ruling is too ambiguous to determine whether, or how, the Commission changed its policy from the traditional “rolled-in” approach used in pricing transmission service. We hold that the Commission provided a clear and reasoned justification for the principles that will guide its future determinations of transmission upgrade pricing. We affirm the Commission’s decision not to modify the basic principles adopted in its order.

b. Discussion.

In accepting as reasonable the “but for” test, the Commission has done no more than approve a framework for determining cost responsibility which furthers the general principle that transmission costs should be borne by those entities responsible for the cost. 58 F.E.R.C. 61,205. Under this test, incremental cost pricing could be found appropriate when firm wheeling across a particular interface would degrade reliability absent upgrades. The Commission specifically declined, however, to answer the requests of the intervenors to decide the “rolled-in versus incremental” rate 17 issue in the abstract and chose instead to evaluate it only within the context of a particular rate proposal or upgrade. Id. The Commission articulated how it envisioned pricing transmission upgrades and adopted a condition limiting the amount NU may propose to collect from a transmission customer to the greater of

(1) the incremental cost of new network facilities required at the time the customer’s new transmission load is added or (2) the rolled-in cost of all network facilities required to serve the combined transmission loads of [NU], including any required transmission additions.

Id. at 61,206. Thus, a wheeling customer may be charged the greater of rolled-in cost rates or incremental cost rates.

The Commission- acknowledged that the introduction of incremental cost pricing principles is a departure from its traditional pricing policies 18 and justified this new policy on NU’s unprecedented obligation to provide third party transmission service. Id. The Commission noted that incremental cost pricing may be appropriate in certain circumstances, but decided to leave the details of cost responsibility questions to a future specific section 205 rate case. When such a case arises, NU will bear the burden of justifying “any direct assignments of costs and supporting] any arguments that reliability is degraded by a particular firm transmission service. No presumption is created by NU’s ‘but for’ criterion that firm wheeling customers always cause the need for upgrades.” Id. at 61,207 (quoting 56 F.E.R.C. at 62031). The Commission also allowed that any reliance by NU upon the “but for” test may be challenged in future actions. The Commission sufficiently explained and justified the principles that will guide its transmission upgrade pricing.

E. Opportunity Cost Pricing.

As has already been discussed, the Commission found it necessary to impose a number of conditions on the proposed NU-PSNH merger to mitigate the merged company’s market power in the markets for transmission and short-term bulk power. 58 F.E.R.C. at 61,195. Specifically, the Commission held that NU must provide firm transmission service out of existing capacity for any utility, subject only to a reservation of sufficient capacity to maintain reliable service to its native load customers and to honor existing contractual obligations. NU was prohibited, however, from denying a request for firm transmission service by reserving capacity for non-firm transactions that would enable it to provide more economical service to its, native load customers. 56 F.E.R.C. at 62,014-21; 58 F.E.R.C. at 61,196-200. FERC also held that NU must build additional transmission facilities as needed to provide transmission where insufficient capacity exists. 56 F.E.R.C. at 62,021-24; 58 F.E.R.C. at 61,204-10. The Commission found that these and other conditions would “adequately mitigate” the merger’s anticom-petitive effects. 58 F.E.R.C. at 61,213.

On rehearing, NU and the States of Connecticut and New Hampshire argued that the Commission should address the issue of firm transmission pricing because, in Opinion No. 364, FERC had established principles governing the related issue of firm transmission priority which made NU’s ability to purchase inexpensive power (which would lower its cost of serving its native load customers) subordinate to its obligation to provide firm transmission for third parties. 58 F.E.R.C. at 61,201-02. The Commission agreed, but declined to approve “opportunity cost pricing” 19 outside the context of a specific tariff proposal. Instead, the Commission announced three “basic goals” to guide its future decisions on the pricing of firm transmission service on the merged company’s existing capacity, and left the door open to NU to propose a tariff based on opportunity costs or any other methodology that would meet the three goals. The Commission explained its decision as follows:

We are now confronted with the need to provide NU with enough specificity regarding what it will be allowed to propose for the pricing of future third-party wheeling service, so that the company can decide whether to proceed with the merger. We also cannot ignore the need to act as expeditiously as possible given the commercial realities and time pressures presented in corporate matters subject to our jurisdiction, and in particular the need to resolve a bankruptcy situation. At the same time we are confronted with the need to ensure an adequate record on pricing issues and to afford all parties an adequate opportunity to voice their objections.

Balancing these respective needs, we conclude that the best course is to provide guidance on pricing issues, but to defer specific pricing issues to the compliance phase of this proceeding, or to subsequent cases where the Commission may consider specific proposals from NU in a concrete, factual setting and with a more developed record.

First, the native load customers of the utility providing transmission service should he held harmless. Second, transmission customers should he charged the lowest reasonable cost-based rate for third-party transmission service. Third, the pricing should prevent the collection of monopoly rents by the transmission owner and promote efficient transmission decisions. In ruling on specific proposed rates, we will balance these three goals in light of the facts and circumstances presented at that time.

58 F.E.R.C. at 61,203 (emphasis added) (footnotes omitted).

FERC was careful to point out that it endorsed opportunity cost pricing only insofar as NU could show that it could “propose rates which include legitimate, verifiable opportunity costs.” Id. The Commission warned NU that any such proposal would be carefully scrutinized and would be subject to challenge. Id. at 61,203-04. Specifically, FERC stated that NU would have to address the following issues should it seek recovery of opportunity costs:

(1) whether opportunity costs should be capped by incremental expansion costs or any other cap; (2) whether current wheeling and wholesale requirements customers should be treated differently from future wheeling and wholesale requirements customers, e.g., by receiving “grandfather” rights to embedded cost rates for the amount of transmission capacity they already use; (3) how NU will identify those customers responsible for growth on its system and what particular new facilities are necessary to accommodate that growth; (4) whether and how third parties should be protected from uncertainty regarding fluctuations in opportunity costs; (5) how the proposed rates will prevent the collection of monopoly rents; and (6) how the proposed opportunity costs will be verified.

Id. The Commission expressly postponed consideration of whether opportunity cost pricing would be inconsistent with nondiscriminatory pricing and nondiscriminatory terms and conditions of service until those issues were raised in a concrete factual context. Id. at 61,204, n. 118.

Petitioners claim that FERC’s decision amounted to an arbitrary endorsement of opportunity cost pricing that was not supported by evidence in the record, was inherently discriminatory, and contrary to FERC’s regulation of natural gas pipelines. Petitioners’ underlying concern seems to be that when the issue arises next in the context of the Commission’s review of NU’s compliance tariff, FERC will simply approve the tariff and dismiss petitioners’ objections on the ground that opportunity cost pricing principles had already been endorsed by the Commission. Although we understand petitioners’ concerns, we believe that they are misplaced and that FERC did not go as far as petitioners fear in endorsing opportunity cost pricing.

Petitioners will have an opportunity to contest any compliance tariff proposed by NU. The Commission itself laid out a number of issues which NU would have to address were it to propose a tariff based on opportunity costs. 58 F.E.R.C. at 61,203. Only after carefully considering the competing interests of providing guidance to NU as to what kinds of tariffs it would consider, and the need to endorse specific methodologies only on the basis of a fully-developed record, did the Commission decide to outline broad pricing goals which would allow for a number of pricing schemes including opportunity cost pricing. Id. It was squarely within the Commission’s power to defer consideration of petitioners’ assertions until after NU filed its compliance tariff. As the Supreme Court has held, “[a]n agency enjoys broad discretion in determining how to handle related yet discrete issues in terms of procedures, and priorities.” Mobil Exploration & Producing Southeast, Inc. v. United Distribution Cos., 498 U.S. 211, 230, 111 S.Ct. 615, 627, 112 L.Ed.2d 636 (1991) (citations omitted). Petitioners argue that deferral was inappropriate in this case because their objections went “to the heart of the public interest determination to be made.” Maryland People’s Counsel v. FERC, 761 F.2d 768, 778 (D.C.Cir.1985). We disagree.

The Commission announced pricing goals and conditions that it determined would keep the merger consistent with the public interest, and would result in “just and reasonable rates.” Until NU proposed a specific tariff regime, the Commission did not have a developed record to evaluate on the merits. The Commission remains free to, and we expect it will, invite objections to NU’s compliance tariff from affected parties, and will reject any proposed tariff that conflicts with its statutory responsibility to approve rates that are “just and reasonable,” and to approve mergers that are, as conditioned, “consistent with the public interest.”

F. Environmental Impact Statement.

The City of Holyoke Gas & Electric Department (“HG & E”) alleges that FERC’s refusal to examine the potential environmental impacts of its approval of the merger was arbitrary and capricious. We disagree.

The National Environmental Policy Act of 1969, 42 U.S.C. §§ 4321 et seq., (“NEPA”) requires federal agencies to consider the potential environmental effects of a proposed major federal action that may significantly affect the quality of the human environment. Section 102(2)(C) of NEPA states:

The Congress authorizes and directs that, to the fullest extent possible: ... (2) all agencies of the Federal Government shall—

(C) include in every recommendation or report on proposals for legislation and other major Federal actions significantly affecting the quality of the human environment, a detailed statement by the responsible official on—

(i) the environmental impact of the proposed action,

(ii) any adverse environmental effects which cannot be avoided should the proposal be implemented,

(iii) alternatives to the proposed action,

(iv) the relationship between local short-term uses of man’s environment and the maintenance and enhancement of long-term productivity, and

(v) any irreversible and irretrievable commitments of resources which would be involved in the proposed action should it be implemented.

42 U.S.C. § 4332(2)(C). Agencies were authorized, under guidelines promulgated by the Council on Environmental Quality (“OEQ”), to create categorical exclusions for actions which do not individually or cumulatively have a significant effect on the human environment. 40 C.F.R. §§ 1507.3, 1508.4. FERC adopted such a category of exclusions, including one for merger approvals such as the one at issue in this case. That regulation states in pertinent part:

(a) General rule. Except as stated in paragraph (b) of this section, neither an environmental assessment nor an environmental impact statement will be prepared for the following projects or actions:

(16) Approval of actions under sections 4(b), 203, 204, 301, 304, and 305 of the Federal Power Act relating to issuance and purchase of securities, acquisition or disposition of property, merger, interlocking directorates, jurisdictional determinations and accounting orders.

18 C.F.R. § 380.4(a)(16). An agency need not issue a “finding of no significant impact” in cases concerning matters that fall into a categorical exclusion. 40 C.F.R. §§ 1501.3, 1501.4, 1508.13.

CEQ guidelines also required agencies adopting categorical exclusions to “provide for extraordinary circumstances in which a normally excluded action may have a significant environmental effect.” 40 C.F.R. § 1508.4. FERC made such provision in its regulations:

(b) Exceptions to categorical exclusions. (1) In accordance with 40 CFR 1508.4, the Commission and its staff will independently evaluate environmental information supplied in an application and in comments by the public. Where circumstances indicate that an action may be a major Federal action significantly affecting the quality of the human environment, the Commission:

(1) May require an environmental report or other additional environmental information, and

(ii)Will prepare an environmental assessment or an environmental impact statement.

(2) Such circumstances may exist when the action may have an effect on one of the following:

(i) Indian lands;

(ii) Wilderness areas;

(iii) Wild and scenic rivers;

(iv) Wetlands;

(v) Units of the National Park System, National Refuges, or National Fish Hatcheries;

(vi) Anadromous fish or endangered species; or

(vii) Where the environmental effects are uncertain.

However, the existence of one or more of the above will not automatically require the submission of an environmental report or the preparation of an environmental assessment or an environmental impact statement.

18 C.F.R. § 380.4(b). 20 HG & E argues that the NU-PSNH merger might “alter mixes of generation in New England by constraining the locations for new plants.” HG & E points to the language of 18 C.F.R. § 380.-4(b)(l)(ii) in support of its position that FERC was compelled, at the least, to explain why it was not obliged to perform the analysis of environmental effects required by NEPA. HG & E also cites FERC’s decision in Southern California Edison Co., 49 F.E.R.C. ¶ 61,091 (1989) (holding that § 380.-4(b) was triggered when approved merger would result in the dumping of hundreds of tons of additional air contaminants into the most polluted air in the United States).

There was no evidence in the record of identifiable environmental harms that would likely result from the NU-PSNH merger. The fact that new generating facilities might wind up in different locations than would have been the case in the absence of the merger does not approach in significance, because its significance is not quantifiable, the known effects of the merger between Southern California Edison Company and San Diego Gas & Electric Company. Thus, the factual situation presented in Southern California Edison is completely distinguishable from that of this ease.

The character and location of the future environmental effects of the NU-PSNH merger are so uncertain that no meaningful environmental review would have been possible, even had FERC made the effort. Here, FERC was not approving a regional development plan. It was merely approving a merger between utility companies, albeit a merger involving two' of the largest utilities in New England. Energy demand may increase in New England over the following decades, and the fact of the merger may influence how those needs are met. Nevertheless, any attempt by FERC to prepare an EIS would have involved little more than spinning out multiple hypothetical development forecasts, with multiple options for the type, amount and location of future generating facilities. See Kleppe v. Sierra Club, 427 U.S. 390, 401-02, 96 S.Ct. 2718, 2726, 49 L.Ed.2d 576 (1976). Once concrete plans have been established for the construction of transmission or generating facilities, those proposals will be reviewed under NEPA or the applicable state environmental review procedures.

FERC was justified in deciding that neither an environmental assessment nor an environmental impact statement was required prior to approving the NU-PSNH merger.

G. HG & E’s “Unique” Harm.

HG & E also, contends that because it relied on PSNH New Hampshire Corridor facilities for over one-third of its electricity supply, it would be “uniquely threatened” by NU in head-to-head competition for large, industrial loads. To protect itself, HG & E requested that FERC either: (1) disapprove the merger; (2) require the divestiture or restructuring of NU’s retail business in Holyoke (HWP); or (3) grant HG & E grandfather rights to PSNH New Hampshire Corridor transmission. The ALJ rejected the “drastic remedy” of divestiture of HWP, stating that it was “wholly uncalled-for by. anything in this record,” and holding that HG & E would be adequately protected by the conditions to the merger,designed to address the anticompetitive effects on transmission dependent utilities (“TDUs”). 53 F.E.R.C. at 65,232.

As the ALJ described,

[t]he Transmission Dependent Utilities (TDUs) are “entirety-dependent on NU or PSNH for their bulk power transmission needs.” These companies (most of which involve municipal ownership) are not big enough to own or construct sufficient generation to meet their loads. As their brief states, they “are physically unable to engage in any bulk power transaction without using the NU or PSNH transmission systems. Absent economic access to NU’s or PSNH’s transmission facilities, the TDU cannot survive as an independent entity.” The TDUs compete with NU and PSNH in the wholesale bulk power market; each TDU, like NU/PSNH, seeks out attractive sources of supply. TDUs thus “are in the uneasy position of having their only source of essential transmission service in the hands of. their principal competitor.” These small companies, uniquely vulnerable to possible anticompetitive conduct, are entitled to some measure of protective assurance regarding NU/PSNH’s post merger conduct.

53 F.E.R.C. at 65,232-33. The ALJ held that “[a]ll rates, terms and conditions of NU/ PSNH transmission service to the TDUs in effect on this date shall ... be maintained after the merger, unless and until changes are either agreed upon by the merged company and the TDUs, or authorized by the Commission.” 53 F.E.R.C. at 65,233. In short, while finding that TDUs were “uniquely vulnerable” to anticompetitive conduct by NU-PSNH, the ALJ found that HG & E had not shown that it was entitled to protections beyond those given to TDUs generally. The Commission agreed, 56 F.E.R.C. at 62,049, but bolstered the protection for TDUs ordered by the ALJ by imposing the additional condition that NU establish a special tariff for TDUs. Id. at 62,050.

HG & E points to no evidence in the record to indicate that it faced anticompeti-tive consequences of the merger sufficiently different in character or magnitude to warrant greater protections than those given to other TDUs. We therefore affirm the Commission’s actions to protect TDUs, which were adequately explained and supported in the record.

H. Modifications to the Filed Rate Schedules.

The Commission analyzed the Sea-brook Power Contract and Capacity Interchange Agreements filed by ÑUSCO under the “just and reasonable” standard of § 206 of the FPA, 21 and ordered the following modifications to the rate schedules: (1) deletion of the automatically adjusting rate of return on equity provision in the Seabrook Power Contract; (2) reduction of the rate of return on equity in the Seabrook Power Contract from 13.75 percent to 12.53 percent; 22 (3) North Atlantic’s decommissioning expenses under the Seabrook Power Contract and any subsequent changes thereto were made subject to review by the Commission; (4) reduction in the rate of return on equity specified in the two Capacity Interchange Agreements from 14.50 percent to 13.17 percent for the period from July 27, 1990 through August 8, 1991, and thereafter to 12.93 percent; and (5) the Seabrook Power Contract could be modified by the Commission in the future under the “just and reasonable” standard of § 206 of the FPA, rather than the “public interest” standard agreed to by the parties. 56 F.E.R.C. at 61,993; 58 F.E.R.C. at 61,185.

Each of the three parties to the Seabrook Power Contract (“SPC”), NU, PSNH and the State of New Hampshire, waived its right to file a complaint under § 206 regarding the rates contained in the agreement. Section 12 of the SPC also provided that:

[E]ach [party] further agrees that in any proceeding by the FERC under Section 206 the FERC shall not change the rate charged under this Agreement unless such rate is found to be contrary to the public interest.

NU argues that the Commission violated the “Mobile-Sierra ” doctrine 23 when it modified the SPC in disregard of the intent of the parties.

Under the Mobile-Sierra doctrine, the Commission must respect certain private contract rights in the exercise of its regulatory powers. Parties to a contract may: (1) waive their rights to file a complaint challenging that contract, and (2) restrict the power of the Commission to impose rate changes under § 206 to cases in which it finds the rates contrary to the public interest — a more difficult standard for the Commission to meet than the statutory “unjust and unreasonable” standard of § 206. See Papago Tribal Utility Authority v. FERC, 723 F.2d 950, 953 (D.C.Cir.1983), cert. denied, 467 U.S. 1241, 104 S.Ct. 3511, 82 L.Ed.2d 820 (1984). In Papago, the court held that, regardless of the parties’ intent, the Commission retained, in any event,

the indefeasible right ... under § 206 to replace rates that are contrary to the public interest, “as where [the existing rate structure] might impair the financial ability of the public utility to continue its service, cast upon other consumers an excessive burden, or be unduly discriminatory.”

Papago, 723 F.2d at 953, (quoting Sierra, 350 U.S. at 355, 76 S.Ct. at 372). The court went on to note that “unduly discriminatory” in this context “apparently means unduly discriminatory or preferential to the detriment of purchasers who are not parties to the contract.” Papago, 723 F.2d at 953 n. 4.

In this case, seemingly for the first time, the Commission held that it also had the

authority under the public interest standard to modify a contract where: it may be unjust, unreasonable, unduly discriminatory or preferential to the detriment of purchasers that are not parties to the contract; it is not the result of arm’s length bargaining; or it reflects circumstances where the seller has exercised market power over the purchaser.

50 F.E.R.C. at 61,839 (emphasis added). The ALJ interpreted that holding as follows:

The Commission made clear that in the particular circumstances surrounding the Seabrook contract, it retains power— through the “public interest” language — to make modifications under the traditional just and reasonable and nondiscrimination standards.

53 F.E.R.C. at 65,235. The standard established by the Commission, and subsequently applied by the ALJ, conflates the “just and reasonable” and “public interest” standards, thereby circumventing the Mobile-Sierra doctrine. The distinction between the “just and reasonable” and “public interest” standards loses its meaning entirely if the Commission may modify a contract under the public interest standard where it finds the contract “may be unjust [or] unreasonable.” The parties’ express intent was to avoid review of rate schedules under the just and reasonable standard. Mobile-Sierra protects their right to do so, leaving the Commission with the power to modify rates only when required by the public interest.

The Commission found that the SPC might unduly discriminate against entities not parties to the contract, and that there was no genuine arm’s-length bargaining because NU and PSNH negotiated the' agreement at a time when they knew they were about to merge and have identical interests. The Commission held that, in this context, it could “carefully scrutinize the rates, terms and conditions of the contract” to determine if they were just. Id.

The Commission’s explanation for employing a just and reasonable standard seems to us inadequate. To the extent the Commission is relying on NU’s prospective ownership of PSNH, it is unclear why the Commission should be concerned about protecting PSNH from a perceived disadvantageous arrangement imposed by its prospective owner since any disadvantage visited on the prospective subsidiary will be borne by its owner. If NU chooses to allocate risks among its operating subsidiaries and one of its subsidiaries is disfavored in this calculation, there would seem to be little justification for the Commission stepping in on behalf of the disfavored subsidiary absent some threat to the public interest.

As for the seller’s market power, reliance on this factor threatens to erode the Mobile-Sierra doctrine so substantially that a fuller explanation from the Commission is required before proceeding down this route. After all, some measure of market power could be present in a large number of contracts. A case-by-case inquiry into the presence and extent of market power would inject a new and potentially time-consuming element into the Mobile-Sierra analysis, and it is not entirely clear in any event why the Commission should protect a buyer who voluntarily enters into an agreement with a dominant seller.

The most attractive case for affording additional protection, despite the presence of a contract, is where the protection is intended to safeguard the interests of third parties, notably the buyer’s customers. The Mobile-Sierra doctrine itself allows for intervention by FERC where it is shown that the interests of third parties are threatened. Mobile, 350 U.S. at 344-45, 76 S.Ct. at 380-81; Sierra, 350 U.S. at 355, 76 S.Ct. at 372. However, the standard to be applied, as formulated by the Supreme Court, is the protection of outside parties from “undu[e] discrimination]” or imposition of an “excessive burden.” Sierra, 350 U.S. at 355, 76 S.Ct. at 372. If there is some reason for departing from this public interest standard as framed by the Supreme Court, the Commission has not supplied it.

We assume, without deciding, that: (1) FERC is correct in its assertion that the State of New Hampshire did not adequately represent the interests of non-parties to the contract, and that, therefore, the SPC may have unduly discriminated against those non-parties; and (2) the alleged lack of arms’length bargaining among NU, PSNH and the State of New Hampshire gave the Commission the right to evaluate the SPC. We hold, however, that the Commission was bound to follow the Mobile-Sierra doctrine as explicated by Papago, and therefore should have evaluated the SPC under the public interest standard, not the just and reasonable standard.

We therefore remand this issue for reconsideration by FERC under the public interest standard. 24

IV. SUMMARY.

We affirm the Commission’s orders in all respects with the exception of its modifications of the Seabrook Power Contract filed with the merger proposal which we remand for consideration under the public interest standard.

1 . Joint petitioners and intervenors include: Central Maine Power Company; Boston Edison Company; Bangor Hydro-Electric Company; the Towns of Concord, Norwood and Wellesley, Massachusetts; Maine Public Utilities Commission; Massachusetts Department of Public Utilities; Vermont Department of Public Service; Vermont Public Service Board; Rhode Island Attorney General; Rhode Island Division of Public Utilities and Carriers; Massachusetts Municipal Wholesale Electric Company; and, City of Holyoke Gas & Electric Department.

2 . This group of petitioners and intervenors includes the joint petitioners and intervenors listed in n. 1, supra (with the exception of Central Maine Power Company), and: The American Paper Institute, Inc.; American Public Power Association; Canal Electric Company; Commonwealth Electric Company; Cambridge Electric Light Company; Massachusetts Attorney General; and, Montaup Electric Company.

3 . NU’s operating companies are Connecticut Light and Power Company (CL & P), Western Massachusetts Electric Company, Holyoke Water Power Company (HWP) and HWP’s wholly-owned subsidiary, Holyoke Power and Electric Company (HP & E). These companies are wholly-owned subsidiaries of NU and are public utilities supplying retail and wholesale electric service in Connecticut and Massachusetts.

4 . The Seabrook Power Contract is a Iife-of-the-unit power sales agreement between PSNH and North Atlantic entered into concurrently with NU’s acquisition of PSNH and the transfer of PSNH's share of Seabrook to North Atlantic. Under the contract, PSNH agreed to purchase North Atlantic's entire share of Seabrook capacity and energy, according to a cost-of-service formula rate. The contract was intended to ensure that North Atlantic would recover all of its costs from PSNH regardless of whether or not Sea-brook actually operated.

5 . The Sharing Agreement allocates the benefits and obligations from the integrated operation of PSNH and the current NU system, as well as the joint planning and operations of these systems. This agreement established a formula for sharing the expected post-merger benefits that would accrue to NU and PSNH operating companies as a result of operating efficiencies and the ability to take single participant status under the NEPOOL agreement.

6 .The two Capacity Interchange Agreements provide for the sale and purchase of energy between PSNH and Connecticut Light & Power Company (CL & P) over a ten-year term.

7 . This, and all other dollar amounts are net present values unless otherwise noted.

8 . The New Hampshire Corridor Transmission Proposal allows New England utilities to purchase long-term transmission rights from NU-PSNH in order to connect with power sources in northern New England and Canada. See 53 F.E.R.C. at 65,225.

9 ."Wheeling” is defined as the "transfer by direct transmission or displacement [of] electric power from one utility to another over the facilities of an intermediate utility.” Otter Tail Power Co. v. U.S., 410 U.S. 366, 368, 93 S.Ct. 1022, 1025, 35 L.Ed.2d 359 (1973).

10 . This issue is discussed in Part III(B), infra.

11 . This issue is discussed in Part 111(A)(3), infra.

12 . The Bankruptcy Code provides that:

(a) The court shall confirm a plan [of reorganization] only if all of the following requirements are met:

(11) confirmation of the plan is not likely to be followed by the liquidation, or the need for further financial reorganization, of the debtor or any successor to the debtor under the plan, unless such liquidation or reorganization is proposed in the plan.

11 U.S.C. § 1129(a)(l 1).

13 . Jurisdiction varies depending on whether the resulting entity is a national bank, a state member bank, a state nonmember bank, or a savings association.

14 . We note that, at oral argument, petitioners conceded that no one had as yet sought access to NU’s transmission facilities.

15 . For a definition of ''wheeling” see n. 9, supra.

16 . NU committed to cap cost responsibility to "(1) those specific facilities identified by NU at the time of the wheeling request as needing to be built or upgraded either at the time of the request or in the future; and (2) the maximum dollar amount contained in NU's initial estimate of a wheeling customer’s pro rata share of the costs of future upgrades needed to accommodate a request for wheeling service.” 56 F.E.R.C. at 62,031-32.

17 . Under "rolled in" pricing principles, the upgrade costs would be rolled in with other company costs and charged to all ratepayers as part of NU's general rate structure; while administratively simple, it ignores any concept of responsibility. Thus, incremental pricing principles look to hold parties responsible for their share of upgrade costs.

18 . The Commission generally has adhered to rolled in pricing, but has never precluded particularized cost allocations to specific customers where appropriate. See Utah Power & Light Co., 45 F.E.R.C. ¶ 61,095, at 61,291 n. 163 (1988); Public Service Co. of Indiana, 51 F.E.R.C. ¶61,367, at 62,203 (1990).

19 . As the Commission explained, opportunity costs are the revenues lost or costs incurred by a utility in providing third-party transmission service when transmission capacity is insufficient to satisfy both a third-party wheeling request and the utility’s own use. For exam-pie, opportunity costs might include the revenues lost or costs incurred because a utility must reduce its own off-system purchases or sales in order to overcome a constraint on the [transmission] grid.

58 F.E.R.C. at 61,200-201.

20 . HG & E does not challenge the validity of any of the applicable regulations cited above.

21 .Section 206(a) of the FPA, 16 U.S.C. § 824e(a) provides:

Whenever the Commission, after hearing had upon its own motion or upon complaint, shall find that any rate ... collected by any public utility ... is unjust, unreasonable, unduly discriminatory or preferential, the Commission shall determine the just and reasonable rate ... to be thereafter observed and in force, and shall fix the same by order.

22 . ÑUSCO did not appeal this modification.

23 . This doctrine is based on the companion cases of United Gas Pipe Line Co. v. Mobile Gas Service Co., 350 U.S. 332, 76 S.Ct. 373, 100 L.Ed. 373 (1956) and FPC v. Sierra Pacific Power Co., 350 U.S. 348, 76 S.Ct. 368, 100 L.Ed. 388 (1956).

24 . We have considered, but find unpersuasive, NU’s argument that FERC committed error when it disrupted the bankruptcy settlement by modifying the Capacity Interchange Agreements.