PER CURIAM:
We consider eighteen consolidated petitions for review of two orders of the Federal Energy Regulatory Commission (FERC or the Commission). In the orders under review the Commission held that the four operating companies of the Middle South Utilities (MSU) system must share the costs of MSU’s investment in nuclear energy in proportion to their relative demand for energy generated by the system as a whole. The Commission implemented this scheme by reallocating responsibility for investment costs associated with the catastrophically uneconomical Grand Gulf I nuclear plant. The parties attack both the Commission’s jurisdiction and the rationality of its decision. Although the Commission’s allocation of nuclear investment costs is subject to reasonable dispute, we do not think such criticisms warrant reversal of FERC’s orders. We therefore affirm.
I. Background
The controversy facing the court today stems from the pattern of power generation investment cost sharing practiced by Middle South Utilities and its operating companies. In order to address fully the proper allocation of the costs of nuclear power generation among those companies, we review MSU’s structure, the history of its involvement in nuclear power generation, and the record of the proceedings below.
A. The Middle South System,
1. Corporate structure. Middle South Utilities, Inc. is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). 15 U.S.C. § 79 et seq. (1982). It owns outright four utility operating companies: Louisiana Power & Light Co. (LP & L), New Orleans Public Service, Inc. (NOPSI), Arkansas Power & Light Co. (AP & L), and Mississippi Power & Light Co. (MP & L). See Middle South Energy, Inc., 26 FERC ¶ 63,044, 65,098 (1984). The operating companies sell electricity, both wholesale and retail, in the states of Louisiana, Arkansas, Missouri, and Mississippi.
Although each operating company has a separate board of directors, the sole stockholder, MSU, selects each director. In addition, the various companies do have common or overlapping officers and directors. The Chairman and Chief Executive Officer (CEO) of MSU is a member of the board of each operating company and the CEOs of the operating companies are members of the board of MSU. Other MSU board members are also board members of individual operating companies. Middle South Services, Inc., 30 FERC ¶ 63,030, 65,142 (Docket No. ER82-463-000) (ALJ Head).
Transactions among the various operating companies are governed by a System Agreement. Over its history, MSU has filed three successive System Agreements — in 1951, 1973, and 1982. The Commission scrutinizes the System Agreement and modifies it when necessary. See, e.g., Middle South Services, Inc., 16 FERC ¶ 61,101 (1981) (modifying the 1973 System Agreement), aff'd, Louisiana Public Service Commission v. FERC, 688 F.2d 357 (5th Cir.1982), cert. denied, 460 U.S. 1082, 103 S.Ct. 1770, 76 L.Ed.2d 343 (1983). Section 3.01 of the Agreement states the system’s general goal of operating as a coherent unit:
The purpose of this Agreement is to provide the contractual basis for the continued planning, construction, and operation of the electric generation * * * facilities of the Companies in such a manner as to achieve economies consistent with the highest practicable reliability of service * * *. This agreement also provides a basis for equalizing among the Companies any imbalance of cost associated with the construction, ownership and operation of such facilities as are used for the mutual benefit of all the Companies.
483-R. 7117, VII Joint Appendix (JA) 1569. In light of this language, Administrative Law Judge (ALJ) Head found that the MSU system has sought to coordinate the addition of operating capacity by each individual operating company while achieving the greatest economies of scale. As he observed:
The System Agreements * * * clearly permit and encourage, for efficiency, reliability, and other economies of scale, that the individual companies from time to time build larger facilities than are necessary to meet their own native load, to benefit all the generating companies by having lower costs and greater reliabili- ^ ^ ^
30 FERC at 65,142.
All three System Agreements have assigned the task of coordinating the planning of new generating capacity to a systemwide Operating Committee. The CEO of each operating company designates one member of the committee, as does MSU. The members representing the operating companies control 80% of the votes on the committee, apportioned according to each individual company’s share of the system’s investment in generating capacity. The representative of MSU votes the remaining 20%. Under Section 5.04 of the System Agreement, the Operating Committee can now take action on the basis of a bare majority. 483-R. 7129, VII JA 1581.
2. Investment cost sharing. As ALJ Liebman noted, the MSU system planning approach to new generating capacity inevitably results in certain operating companies having less generating capacity than do others for varying periods of time. See 26 FERC at 65,098 (Docket No. ER82-616000. If a company does not have enough capacity to meet the needs of its consumers, the deficient operating company can always draw on the excess capacity of the other companies on the system. This system also benefits those companies that have built more capacity than necessary to meet current demand. Such companies generally find willing buyers of their surplus among the other companies on the system.
Under the system planning approach, it is inevitable that an operating company will, from time to time, provide a proportionate share of the system’s investment in generating capacity that is more or less than its proportionate demand for the system’s energy. If a company’s share of the system’s generating capacity is greater than its share of the energy actually generated and distributed by the system as a whole, the company is deemed to be “long.” If the company’s share of the system’s generating capacity is less than its percentage of the system’s energy, the company is deemed “short.” 26 FERC at 65,099.
Since 1951 the MSU system has sought to iron out the inequities that would otherwise result where some companies were long while other companies were short through a system of “equalization payments.” Prior to 1973 each “short” company made a payment to the “long” companies based on a fixed dollar amount per kilowatt of capacity that the company was short. In 1973 the System Agreement was amended to provide for capacity equalization payments calculated under the “participation unit” formula, a formula that based payments on the ownership costs of the latest unit constructed by the “long” company. See id.; see also 30 FERC at 65,122-23.
Importantly, this new system did not call for equalization payments based on the relative number of dollars each company had invested in generating capacity. Instead, the relative number of kilowatts of generating capacity owned by each company formed the basis for the payments. Because kilowatts can vary in cost, the system potentially perpetuated the operating companies’ relatively unequal investment in generating capacity.
For over twenty-five years, however, the system largely avoided this potential inequity. Notwithstanding its limitations, the equalization payment approach managed to produce the effect of roughly equalizing the cost of investing in new capacity from the 1950’s through the 1970’s. During the years in which the 1951 System Agreement was in force the cost of creating such capacity was relatively uniform and relatively constant. See 616-R. 1332-33, I JA 140-41; 30 FERC at 65,168. As a consequence, the System Agreement’s allocation of equalization payments based on a constant dollar per kilowatt of short capacity served to equalize investment costs. Although in the 1970’s the cost of new units began to exceed that of older facilities by a substantial margin, the 1973 System Agreement balanced this development by basing equalization payments on the costs of the newest (and more expensive) units of the “long” companies. 26 FERC at 65,-100.
3. The shift to nuclear energy and its consequences. In the 1950’s and 1960’s the MSU system tended to add new generating units in the southern part of the system to take advantage of cheap oil and gas reserves in Louisiana. See 26 FERC at 65,100; 30 FERC at 65,143. In the late 1960’s, however, the system began a program of adding coal and nuclear generating capacity, 30 FERC at 65,144, that eventually resulted in the collapse of the investment equalization program.
AP & L was the first operating company to make such an investment in nuclear power. AP & L had historically been both a short company and one with insufficient capacity to meet the requirements of its customers. 30 FERC at 65,143. Moreover, AP & L had been losing its long-term gas contracts while Louisiana and Mississippi continued to have an adequate supply of gas and oil. 26 FERC at 65,101. In December 1974 AP & L brought on line MSU’s first nuclear plant, Arkansas Nuclear One (ANO) Unit 1.
Although ANO l’s capacity was substantially more expensive than that of non-nuclear generating units built at the time, 26 FERC at 65,100-01, the lower fuel costs of a nuclear unit made the total generation costs of ANO 1 comparable to those of other plants brought on line in the 1970’s. Thus it is fair to say that the basic system of roughly equalizing the costs and benefits derived from the system’s investment in new capacity remained intact.
The picture changed radically with the development of two new nuclear units — the Waterford 3 unit (assigned to LP & L) and Grand Gulf 1 (initially assigned to MP & L). Grand Gulf was initially projected to cost $1.2 billion for two generating units. Regulatory delays, additional construction requirements, and severe inflation ran up Grand Gulf costs to in excess of $3 billion for one unit. Similar cost over-runs marred the construction of Waterford 3. See Middle South Energy, Inc. and Middle South Services, Inc., 31 FERC ¶ 61,305, 61,654 (1985). These units produce the most expensive energy on the MSU system. Measured in dollars per kilowatt of generating capacity, the new units were five times costlier than the ANO units installed by AP & L. Most important, although these two plants have been estimated to represent over 70% of the production costs of the MSU system, they apparently will produce only 13% of the electricity used on the system. 30 FERC at 65,121.
Under these conditions, continued application of a capacity equalization scheme that only sought to equalize kilowatts could no longer come close to equalizing investment dollars. Any operating company saddled with responsibility for Waterford 3 and/or Grand Gulf would likely find itself paying far more per kilowatt of capacity than would an operating company that was free of such a burden. 26 FERC at 65,100.
It is true that MSU filed a new System Agreement in 1982 altering its previous equalization scheme. Unlike the 1973 Agreement, which had pegged equalization payments to the cost of the long company’s most recent generating addition, the 1982 Agreement provided for equalization payments based on the long company’s “intermediate” (ie., oil and gas) units. 483-R. 7137-50, VII JA 1589-96. This change reduced the burden on any company that might be both short and have substantial responsibility for the new nuclear plants. But, as discussed below, this change did not eliminate the major inequities that nuclear power introduced to the MSU system.
4. The Grand Gulf plant. The Grand Gulf project was initiated by MSU to meet the then projected demand for electricity by the system as a whole. 26 FERC at 65,101-02. By the late 1970’s, however, it became clear that projected demand would fall well short of previous expectations. Nonetheless, MSU continued to build Grand Gulf 1 on the assumption that the overall cost per kilowatt hour would be less than that of alternative energy sources. 26 FERC at 65,102.
Initially the plant had been assigned to MP & L. It soon became apparent, however, that MP & L did not have the resources to finance the construction of the plant. As a consequence, MSU made a system decision to form Middle South Energy (MSE) in 1974 as a vehicle for financing Grand Gulf. MSE acquired full title to Grand Gulf. In June of 1974 all four Middle South operating companies entered into an “Availability Agreement” under which each operating company put its credit behind Grand Gulf.
Notwithstanding this initial agreement, at the time MSE was first formed no clear plan existed to allocate responsibility for Grand Gulf’s capacity to each of the companies. Over the years various allocation plans were put forward, ultimately resulting in the Unit Power Sales Agreement (UPSA) at issue in this case.
At first it was contemplated that MSE would become a party to the System Agreement. Under this plan all of Grand Gulf would be a “participation unit” and responsibility for the plant’s capacity would shift among the operating companies to the degree they were short. 616-R. 4122-23, II JA 505.
In 1979 MSU officials, having come to the conclusion that a fixed allocation of capacity was preferable to a scheme of shifting responsibilities, recommended a plan that would have allocated a share of Grand Gulf capacity to all of the operating companies. But by early 1980 the MSU officers were moving toward a scheme absolving AP & L of all responsibility for Grand Gulf. In July of 1980 the CEOs of the MSU operating companies signed a Memorandum of Understanding, freeing AP & 1/ of all responsibility for Grand Gulf. Although this Memorandum was never submitted to the Coordinating Committee, and therefore never became final, its basic terms were set forth in a “Reallocation Agreement” executed in July 1981. 616-R. 3275,1 JA 268. Under the Reallocation Agreement AP & L assigned its entitlement to purchase Grand Gulf power to the other companies. In addition, NOPSI, LP & L, and MP & L agreed to indemnify AP & L for any obligation it might incur to MSE’s creditors. The Reallocation Agreement thus relieved AP & L of any responsibility for Grand Gulf capacity costs and provided the basis for the Unit Power Sales Agreement. 26 FERC at 65,103.
The Unit Power Sales Agreement was executed on June 10,1982. Although all of the operating companies are signatories to the UPSA, it only provides for sale of Grand Gulf capacity and energy by MSE to three of the operating companies: LP & L, MP & L, and NOPSI, but not to AP & L. 26 FERC at 65,095.
B. The Proceedings Below
In April 1982 MSU filed with the Commission the 1982 System Agreement, which set the general rules governing transactions between the operating companies, including capacity equalization payments and the rates governing the exchange of energy between the operating companies. FERC set the proceeding for hearing before AU Head. In June 1982 MSU filed the Unit Power Sales Agreement with the Commission, governing the sales of Grand Gulf capacity and energy by MSE to the four operating companies. This proceeding was set for hearing before AU Liebman. AU Liebman issued his opinion on February 3, 1984, Middle South Energy, Inc., 26 FERC 1163,044 (1984), and AU Head issued his opinion a year later, on February 4, 1985. Middle South Services, Inc., 30 FERC ¶ 63,030 (1985). Both decisions touched on the allocation of Grand Gulf Power, and FERC reviewed both decisions in an opinion issued June 13,1985. Middle South Energy, Inc. and Middle South Services, Inc., 31 FERC ¶ 61,305 (1985). It revisited the issue following petitions for rehearing in an opinion issued September 28, 1985. Middle South Energy, Inc. and Middle South Services, Inc., 32 FERC ¶ 61,425 (1985).
1. ALJ Liebman’s decision in the UPSA case (ER82-616). The principal issue in ER82-616 was whether the UPSA’s proposed allocation of Grand Gulf investment costs was reasonable and, if not, how such costs should be allocated. As a threshold matter, however, AU Liebman rejected a series of arguments suggesting that FERC did not have jurisdiction or statutory authority to amend this aspect of the UPSA.
Having found jurisdiction, AU Liebman found that the UPSA was “unduly discriminatory” under Section 206(a) of the Federal Power Act, 16 U.S.C. § 824e(a) (1982), because it failed to allocate any portion of Grand Gulf’s capacity costs to AP & L. He based this decision on his view of the MSU system as a highly integrated operation that made critical decisions — such as the decision to move into nuclear power — as a unit. Under that view AU Liebman thought it only fair that AP & L pay its share of the company’s decision to build nuclear capacity. Having rejected the UPSA’s allocation of Grand Gulf costs, AU Liebman was faced with three alternatives:
(1) Making Grand Gulf a participation unit, with floating responsibility among the short(er) companies.
(2) Allocating responsibility for Grand Gulf capacity proportionate to each operating company’s relative share of system demand, as fixed in 1982.
(3) Allocating responsibility for Grand Gulf such that each operating company bore a share of the cost of all the nuclear units on the MSU system proportionate to that company’s relative share of system demand, as fixed in 1982.
26 FERC at 65,109.
AU Liebman chose the last proposal. As the Commission noted, this approach did not merely allocate the cost of Grand Gulf. By including the total system investment in nuclear power in his formula, AU Liebman effectively reallocated the costs of all nuclear capacity on the MSU system. 31 FERC at 61,633.
AU Liebman justified his exclusive focus on nuclear capacity costs — rather than on equalizing the costs of all capacity investment or, even more sweeping, equalizing all generating costs — by claiming that the differences among non-nuclear base load generation costs were minor eompared to the cost differences among the nuclear generating facilities. 26 FERC at 65,110. He suggested that even under his proposal AP & L would still have the low- total generation costs on the system, at 65,119. He justified his decision to reallocate costs of Grand Gulf primarily by reference to the fact that the UPSA perpetuated discrimination caused by the timing of nuclear units by forcing the Louisiana and Mississippi ratepayers to pay about four times more for nuclear capacity than the Arkansas ratepayers would pay for their nuclear kilowatts. Id. at 65,107.
2. ALJ Head’s decision in the System Agreement case (ER82-483). The principal issue in the System Agreement proceeding was whether FERC should approve that Agreement as filed or whether it should equalize all or part of the production costs on the system. 30 FERC at 65,120. AU Head also considered a series of arguments militating against FERC jurisdiction over the reallocation of Grand Gulf costs and rejected them.
Having found that FERC had the authority to reallocate production costs, AU Head faced the following alternatives:
(1) Adoption of the System Agreement as filed. This would entail allocating none of the Grand Gulf costs to AP & L and only equalizing the costs of capacity between “long” and “short” companies, with equalization payments pegged to the cost of the long companies’ oil and gas investment costs.
(2) Equalization of production costs. The basic concept, presented by the Louisiana Public Service Commission, was to allocate responsibility for a share of all production costs on the MSU system proportionate to each company’s share of the system’s total load.
(3) Making Grand Gulf a participation unit. This proposal would allocate responsibility for Grand Gulf capacity to each operating company to the degree that the company in question was “short.” Under this scheme responsibility for Grand Gulf capacity would shift over time.
AU Head rejected all of these proposals. He rejected the concept of making Grand Gulf 1 a participation unit primarily because it would allow long companies (e.g., MP & L) to avoid completely the high front-end costs associated with that plant. 30 FERC at 65,166-67. He rejected the equalization proposals on the ground that overall cost equalization would be inconsistent with the general “pattern of autonomy * * * particularly as to * * * specific plant site locations, fuel and financing” that he found characterized the operating companies in the MSU system. Id. at 65,168.
AU Head found support for his finding of a “pattern of autonomy” in two circumstances. First, he stressed that the historic practice in the MSU system was to equalize only excess capacity. Id. at 65,167. Second, he insisted that “generation additions in almost every instance (except for Grand Gulf) were made primarily to satisfy individual company needs.” Id. at 65,168.
AU Head, however, found that Grand Gulf constituted an “anomaly” in the MSU system:
Grand Gulf from its inception was planned, presented to the licensing authorities and constructed as a system plant not only to serve the needs of MP & L but to serve the needs of all the operating companies on the system.
30 FERC at 65,170.
He therefore deemed it appropriate to reject the System Agreement as filed and to allocate the costs of the Grand Gulf investment among all of the operating companies. Unlike AU Liebman, however, he held that this allocation should fluctuate from year to year to track each company’s relative demand for the system’s energy. 30 FERC at 65,172.
3. FERC’s initial decision. In Order No. 234 the Commission summarily affirmed both AUs on the threshold issue of its own jurisdiction to amend the Sales Agreement and the System Agreement. 31 FERC at 61,643-46. On the merits, the Commission affirmed both AUs’ findings that MSU constituted an “integrated electric system.” 31 FERC at 61,645. The Commission, however, specifically rejected AU Head’s finding that the MSU system displayed a “pattern of autonomy” with regard to the planning and construction of generating units. Id.
The Commission conceded that MSU’s system of overlapping officers and directors and the representation of the operating companies on the System Operating Committee gave the operating companies substantial influence in the development of the system’s plans. Id. at 61,646. FERC further observed that the individual companies used their influence to seek the addition of generating units that met their particular needs, and that Section 4.01 of the System Agreement made each operating company responsible for financing the ownership or purchase of the generating capacity necessary to service its customers. Id. at 61,649. The Commission nonetheless concluded that “major critical decisions, including decisions to build new generating units, are made by the Operating Committee for the benefit of the system as a whole.” Id. at 61,646. See also id. at 61,650.
The Commission buttressed its conclusion with the following evidentiary support: (1) Section 4.01 of the 1982 System Agreement provides that the Operating Committee shall “determine” the system generation addition plans; (2) at least five witnesses testified that new units were added to address the needs of the system as a whole, id. at 61,646-48; and (3) the Operating Committee minutes over a twenty-year period revealed that the Committee had the responsibility and the authority to make the “critical decisions” concerning the addition of generating capacity. Id. at 61,648-49.
The Commission’s review of the Operating Committee minutes revealed that the Operating Committee did not merely rubber-stamp the requests of the individual operating companies concerning the addition of generating capacity. Id. at 61,649. The Commission found that the Operating Committee consistently based its generation plans on the needs of the system as a whole. Id. at 61,649-50. It found that the Operating Committee had authority over the general timing, location, and size of plant additions, while the individual operating companies retained authority to fill in the details of such fundamental decisions. Id. Thus FERC stated that there was no evidence in the record that an operating company had ever built a new plant without a recommendation from the Operating Committee or that one had ever refused to carry out such a recommendation. Id. at 61,651.
In light of this finding, FERC rejected AU Head’s contention that Grand Gulf was an “anomaly.” Instead it agreed with AU Liebman that Grand Gulf, like every other generating station, was built to serve the needs of the system as a whole and to attain the system-wide goal of diversifying MSU’s fuel mix. Id. at 61,653. MSE was deemed a mere financing shell that the Commission hypothesized would have been made available to any other operating company that suffered the financial difficulties encountered by MP & L. Id. at 61,654.
The Commission viewed the decision to move into nuclear power as a system-wide decision calculated to meet system-wide needs. It found that MSU’s nuclear project had run afoul of unforeseen economic difficulties that had disrupted the system’s historic rough equalization of generation costs. FERC therefore adopted AU Liebman’s scheme of allocating Grand Gulf costs so that each operating company would contribute proportionately to the system’s investment in nuclear capacity. Id. at 61,655.
4. FERC’s opinion on rehearing. In Opinion No. 234-A FERC clarified its position on the various jurisdictional arguments it had addressed in its initial decision. 32 FERC at 61,943-52. The Commission also addressed — and rejected — the argument raised by various Arkansas parties that FERC lacked jurisdiction as there was no interstate sale of power. The Commission suggested that, whatever the merits of such an argument where a “monolithic” system is concerned, there was no question but that the transfer of power among the MSU operating companies constitutes a “sale for resale.” Id. at 61,957.
Indeed, a major portion of the Commission’s opinion on rehearing was dedicated to clarifying the Commission’s essential finding concerning the “integrated” character of the MSU system. The Commission rejected any attempt to mischaracterize its decision as based on a view that MSU is a “monolith.” Id. at 61,952. FERC simply insisted that, whatever the powers of the individual operating companies, the MSU Operating Committee makes the “major critical decisions on the System, primarily for the System as a whole.” Id. at 61,953 (emphasis in original). The Commission emphasized that its opinion hinged on “a variety of factors including the manner in which decisions are made by the commonly owned affiliates, and for whose primary benefit those decisions are made.” Id. at 61,956.
Turning to the merits, the Commission addressed three challenges to the rationality of its allocation of Grand Gulf costs. It disputed the contention of the Arkansas parties that the allocation violated the spirit and practice of the MSU system, the System Agreement, and the intent of the parties to that Agreement. FERC responded that the clear intent of the System Agreement was to correct major cost imbalances while moving toward a mixed fuel base including nuclear and coal-fired facilities. The Commission insisted that it need not measure the rationality of its allocation from the vantage point of the parties at the time the UPSA was first negotiated. Id. at 61,957-59.
The Commission also addressed the argument of MP & L that the Commission’s order had only exacerbated the discrimination it would have suffered under the original UPSA scheme. MP & L noted that under the UPSA it would have been responsible for 31.63% of Grand Gulf, but under the Commission’s scheme it would be responsible for a full 33%. 31 FERC at 61,-959. Under the new scheme Mississippi would receive only 9.5% of the system’s nuclear capacity while paying for 15% of the system’s nuclear investment. 32 FERC at 61,964 n. 26.
The Commission responded by asserting that the mere fact that FERC’s order increased MP & L’s burden did not make it more discriminatory. , It is completely rational, argued the Commission, that a smaller burden can be discriminatory and, with a change in the relative standing of the parties, a larger burden can be fair. The original allocation was discriminatory, in the Commission’s view, because AP & L had failed to share the burden of Grand Gulf. Although the Commission’s order would increase MP & L’s allocation somewhat, it would spread the overall burden of Grand Gulf more equitably by making AP & L carry a portion of the burden.
The Commission suggested that its refusal to reallocate the capacity of all nuclear units (as well as their costs) was justified by the MSU system’s historic aversion to equalizing all costs per kilowatt. Id. at 61,959. It stressed the same point in responding to the arguments of various Louisiana parties that it should have adopted full cost equalization. Id. at 61,961. Thus the Commission depicted its opinion as an attempt to balance
the need to provide an equitable sharing of the investment costs of units that have (or could have) become unforeseeably high due to the unique problems associated with nuclear construction, and the need to recognize the efforts of individual companies on the System and allow them to retain the benefits of units they own to the fullest extent possible.
Id.
Dissatisfied with this rationale, petitioners sought review in this court.
II. Jurisdiction
The petitioners from Arkansas, Missouri and Mississippi raise certain threshold challenges to the Commission’s decision. They contend that FERC lacks jurisdiction to modify the allocation of the capacity costs of Grand Gulf embodied in the Unit Power Sales Agreement (“UPSA”). We disagree, and hold that the Federal Power Act (“FPA” or “the Act”) provides FERC with authority to issue the orders in question. Initially, we will set forth the affirmative basis of FERC’s jurisdiction; thereafter, we will address (and reject) each individual counterargument raised by petitioners.
A. The Jurisdiction of the Commission
Section 201 of the Act contains the Commission’s basic jurisdictional grant. It provides that “[t]he provisions of this subchapter shall apply to the transmission of electric energy in interstate commerce and to the sale of electric energy at wholesale in interstate commerce” and that “[t]he Commission shall have jurisdiction over all facilities for such transmission or sale____” This section also defines “public utility” as “any person who owns or operates facilities subject to the jurisdiction of the Commission under this subchapter.” The facts here reveal that MSE sells Grand Gulfs energy to the affiliated operating companies of the MSU system at wholesale in interstate commerce. Thus, under section 201 of the Act, MSE is a “public utility” and FERC retains jurisdiction over its sales and facilities.
Sections 205 and 206 of the Act set forth the Commission’s remedial authority. Section 205(a) establishes a threshold requirement that all “rates and charges” made by a public utility, and “all rules and regulations affecting or pertaining to such rates and charges,” must be “just and reasonable,” or they will be deemed “unlawful.” Most significantly for our purposes, section 206 provides that when the Commission, after a hearing, determines that
any rate, charge, or classification, demanded, observed, charged, or collected by any public utility for any transmission or sale subject to the jurisdiction of the Commission, or that any rule, regulation, practice, or contract affecting such rate, charge, or classification is unjust, unreasonable, unduly discriminatory or preferential, the Commission shall determine the just and reasonable rate, charge, classification, rule, regulation, practice, or contract to be thereafter observed and in force, and shall fix the same by order.
The combined force of these provisions leads inexorably to the conclusion that, under the circumstances presented in the instant case, FERC had jurisdiction to modify the Grand Gulf allocation set forth in the UPSA.
The distribution of Grand Gulf costs and capacity in the UPSA inevitably affects each operating company’s generation costs and, by extension, their wholesale rates. When, as here, generation capacity has been built and planned on a profoundly integrated basis, the Commission properly may examine its allocation as a cost component affecting wholesale rates. For this purpose, the UPSA cannot be examined in isolation. As the Commission stated, the UPSA is “an agreement which ‘supplements or supersedes’ the coordination arrangements among the MSU utilities, and ... is a contract ‘affecting’ rates under the 1982 System Agreement.”
The UPSA serves to distribute the Grand Gulf capacity available to MSE — and its cost — among the MSU operating companies. When the Commission acted to modify the UPSA and reallocate the capacity of Grand Gulf, it altered the relative amount of system capacity ultimately paid for by each affiliate. Concurrently, the 1982 System Agreement (Service Schedule MSS-1) established the terms of reserve capacity cost-sharing among the same group. Any change in the allocation of the capacity costs of Grand Gulf in the UPSA will change the relative “longness” or “shortness” of each company under the System Agreement, thus altering the equalization payments made and received for capacity under Service Schedule MSS-1. In the instant case, the cost burden of system generating capacity has been shifted among the affiliates, by virtue of Commission action and system agreement, in order to insure an equitable distribution. This equitable distribution is mandated by the FPA because of the historical integration of the MSU system.
Capacity costs are a large component of wholesale rates. Thus, the capacity costs of the system carried by each affiliate will significantly affect the wholesale price it pays for energy on the MSU system. In the Commission’s view, the UPSA’s allocation of Grand Gulf, combined with the provisions of the 1982 System Agreement, created serious inequities in the division of costs of power resources among the operating companies in light of the integrated planning for generating capability on a system basis. Unreasonable disparities in the shares borne by affiliates of the total costs of the system’s generating capacity plainly “affect” the wholesale rates at which the operating companies exchange energy, and therefore require remedial action by the Commission pursuant to section 206.
A case involving the Northern States Power (“NSP”) Companies, State of Minnesota v. FERC, provides a helpful illustration of how agreements among affiliates can “affect” rates. The NSP Companies develop and operate both generation and transmission facilities on an integrated basis through participation in a Coordinating Agreement which, inter alia, establishes procedures for sharing costs on the system. In 1982, the Companies filed an amendment to that Agreement with FERC proposing a methodology for determining the rate of return on investment as a component of the fixed costs shared under that Agreement. The Minnesota Public Utilities Commission (“MPUC”) intervened and contended that FERC lacked jurisdiction to review the amendment because the Coordinating Agreement does not establish a wholesale rate. Specifically, MPUC argued that FERC “exceeded its authority under the Federal Power Act and intruded upon retail ratemaking functions by accepting a filing that sets a rate of return on capital as part of a cost allocation agreement between affiliated power companies.”
The Eighth Circuit observed that “MPUC’s challenge to the Commission’s jurisdiction rests on its contention that the Coordinating Agreement serves simply as a mechanism for allocating costs among the NSP Companies and does not establish a wholesale rate for the resale of electricity.” However, the court agreed with the Commission that the Coordinating Agreement “eontain[ed] numerous provisions authorizing the NSP Companies to exchange electric power among themselves in return for payment,” i.e., interstate wholesale transactions. Thus, the Eighth Circuit held that the Coordinating Agreement established a wholesale rate and that, “[bjecause a change in the rate of return on investment affects the wholesale rate under the Coordinating Agreement, the Commission possessed jurisdiction to review and approve the proposed amendment.”
We are in total accord with the Eighth Circuit’s view of FERC’s jurisdiction as enunciated in State of Minnesota. In the instant case, the petitioners concede that wholesale rates are established in the disputed contracts governing the MSU system; but petitioners nonetheless contend that the Commission does not have jurisdiction here because other portions of these same agreements allocate generation costs among the MSU companies and these particular provisions do not themselves establish a wholesale rate. However, the petitioners ignore the critical point here that, while these provisions do not fix wholesale rates, their terms do directly and significantly affect the wholesale rates at which the operating companies exchange energy, due to the highly integrated nature of the MSU system. We conclude that, because the allocation of Grand Gulf capacity and costs, like the rate of return on capital in State of Minnesota, significantly affects the wholesale rates at which the operating companies exchange energy due to the combined effect of the UPSA and the 1982 System Agreement, that allocation is plainly within Commission jurisdiction.
The Supreme Court quite recently confirmed the propriety of this analysis in Nantahala Power & Light Co. v. Thornburg. In that case, FERC examined an agreement between two affiliated power companies, which allocated certain low-cost entitlement power between them. FERC found that the agreement was unfair to one of the companies, Nantahala, and increased the percentage of low-cost entitlement power that it should receive. Although FERC did not specifically “reform” the agreement, Nantahala was required to file revised rates, reflecting its increased entitlement to low-cost power. The North Carolina Utilities Commission (“NCUC”) not only rejected the actual apportionment agreed to by the companies, but also “employed an allocation of entitlement power that nowhere [took] into account FERC’s allocation of that same power.”
The Supreme Court held that the NCUC orders were inconsistent with preemptive federal law. The Court observed that
[although the [companies’ agreements] do not purport explicitly to set a sales price for power, FERC’s decision on how Nantahala may treat these agreements in determining its wholesale rates obviously does affect Nantahala’s costs directly, and thus Nantahala’s wholesale rates.
FERC’s allocation of Grand Gulf’s costs and capacity, like the setting of entitlement percentages in Nantahala Power & Light, does not set a sales price, but does directly affect costs and, consequently, wholesale rates. We cannot disregard the Supreme Court’s clear and timely message that FERC’s jurisdiction under such circumstances is unquestionable.
Having determined that all MSU generating capacity, including Grand Gulf, had been built and planned on an integrated basis by the MSU system to meet its collective needs and that the allocation of Grand Gulf would affect wholesale rates within the system, the Commission decided that the affiliated operating companies’ arrangement for sharing of capacity costs— as set forth in the UPSA and the 1982 System Agreement — was unjust, unreasonable and unduly discriminatory. Under these circumstances, sections 205 and 206 of the FPA plainly provide FERC with authority to modify the Grand Gulf allocation agreed to by the operating companies.
B. Arguments Opposing Jurisdiction
The petitioners advance various theories to support their contention that FERC lacks jurisdiction to impose the remedy selected in this case. They maintain that: (1) FERC has unlawfully exercised jurisdiction over a generating facility; (2) FERC has unlawfully compelled a purchase of power and generating capacity; (3) FERC has impermissibly intruded on areas subject to state jurisdiction; (4) FERC has contravened the purposes of the Public Utility Holding Company Act (“PUHCA”) and infringed upon the authority of the Securities and Exchange Commission (“SEC”); and (5) FERC has violated the Mobile-Sierra doctrine. As set forth below, none of these attempts to displace FERC’s jurisdiction succeed.
1. Jurisdiction Over Generating Facilities
The Arkansas-Missouri petitioners contend that, in allocating the cost and capacity of Grand Gulf, the Commission has asserted jurisdiction over a generating facility in contravention of section 201(b) of the FPA. They maintain that the equalization of nuclear investment by reallocating generation costs falls outside of FERC’s rate making jurisdiction and instead falls solely within state authority over generation.
In pertinent part, the statute states: The Commission shall have jurisdiction over all facilities for such transmission or sale of electric energy, but shall not ■ have jurisdiction, except as specifically provided in this subchapter and sub-chapter III of this chapter, over facilities used for the generation of electric energy....
In the same section, the statute provides for
Federal regulation of matters relating to generation to the extent provided in this subchapter and subchapter III....
The Conference Report on the FPA instructs that the italicized phrases were “added to remove any doubt as to the Commission’s jurisdiction over facilities used for the generation ... of electric energy to the extent provided in other sections ...” The Commission concluded that, in the course of exercising its undisputed jurisdiction over interstate sales of electric energy at wholesale, it lawfully could reallocate the costs of Grand Gulf across the integrated system. Hence, the Commission reasoned that although allocating cost does, to some extent, result in the “regulation of matters relating to generation,” such regulation is valid under the FPA when it is the byproduct of a legitimate exercise of FERC’s power to regulate wholesale rates.
We agree that FERC has not exercised jurisdiction over generating facilities in any way that violates the FPA. Instead, the Commission is acting pursuant to its exclusive rate authority over wholesale transactions and its remedial authority as set forth in sections 205 and 206.
The Arkansas-Missouri petitioners concede that FERC has jurisdiction to modify the rates and rate-related terms of the UPSA, but deny that this authority encompasses the reallocation of generating capacity. Citing the congressional concern that states maintain control of generating facilities, they assert that the statutory prohibition of federal regulation of such facilities in section 201(b) becomes meaningless if FERC is permitted to allocate the costs of a plant.
This analysis is flawed. As FERC correctly reasoned:
We cannot interpret the “but” clause of Section 201(b)(1) as nullifying the authority granted to us in the first sentence of Section 201(b)(1), in situations where generation facilities are used for interstate wholesale sales. To interpret the statute otherwise would be inconsistent with the declaration in Section 201(a) that Federal regulation of the sale of energy at wholesale in interstate commerce is necessary in the public interest.
Nor could such an interpretation be reconciled with the Commission’s statutory authority to revise contracts affecting rates which are unjust, unreasonable or unduly discriminatory.
The petitioners’ general assertion that FERC has improperly infringed upon a state realm by reallocating the costs of Grand Gulf will be dealt with separately infra; for the present purpose, it suffices to note that FERC has not regulated a facility, but rather the wholesale rates of interstate sales within the MSU system. It is well-accepted that FERC must allow the recovery of the cost of generating facilities in setting wholesale rates. Here, FERC has simply exercised its undisputed authority over the wholesale rates of electric generating facilities in interstate commerce, which includes, under the facts presented, the authority to reallocate the costs of Grand Gulf across the system. As the statute quite plainly states, FERC’s control here is exclusive. The jurisdictional line drawn by Congress is bright, and FERC stands on the correct side of that line.
The cases cited by the Arkansas-Missouri petitioners are inapposite. In Connecticut Light & Power Co. v. FPC, the Supreme Court construed the “local distribution” exception to the Commission’s jurisdiction, rather than the “generating facilities” exception, in the context of determining whether to permit regulation of an electric utility located and serving customers exclusively in the state of Connecticut. In its decision, the Court cited the language of section 201(a) of the FPA, “but shall not have jurisdiction ... over facilities used in local distribution.” The lower court had decided that this exemption did not preclude Commission regulation if the Act otherwise provided for the facilities’ regulation, i.e., if they carried energy in interstate commerce. The Supreme Court rejected this interpretation of the “but” clause and held that, in order to be subject to FERC jurisdiction, a company must own facilities used in the transmission of interstate power and not be a local distribution facility. From this, the petitioners reason that Grand Gulf must be used for interstate wholesale sales and not be a generating facility to be subject to FERC jurisdiction.
This interpretation must fail. Initially, we note that the distribution facility at issue in Connecticut Light & Power sold energy exclusively within Connecticut; MSE’s sales are, without exception, at wholesale and in interstate commerce. Second, the holding in Connecticut Light & Power addresses only the “local distribution” exception to the FPA, not the “generating facilities” exception at issue here. Furthermore, the Court’s limited discussion of the “generating facilities” exception refutes petitioners’ contention. In this discussion, the Court accepts the proposition that FERC may lawfully assert jurisdiction over matters pertaining to generation where it is found that generation facilities are used as facilities for interstate wholesale sales. In the instant case, the MSE generating facilities are utilized solely for interstate wholesale sales, thus satisfying the Court’s test.
2. Compelled Purchases of Power and Capacity
The Arkansas-Missouri petitioners also argue that FERC has exceeded its jurisdiction by forcing independent companies — AP & L, for example — to purchase power from Grand Gulf in quantities beyond that agreed to in the UPSA. The Commission found that, as a factual matter, there would be no “forced purchase” due to the integrated nature of the Grand Gulf project and the MSU system and AP & L’s individual longstanding, in-depth commitment to Grand Gulf. We agree with the Commission that “the issue here is not whether a company should be forced to purchase or sell power, but rather is the appropriate allocation of costs among integrated companies owned by the same parent.” The Commission has made detailed findings on the highly integrated nature of the MSU system and on the coordinated planning of the Grand Gulf project. The depth of the operating companies’ historical involvement in both the system and the project allows the Commission to step in and reallocate costs under section 206(a) of the FPA so that each of the operating companies is treated fairly.
A consistent line of judicial precedent supports FERC’s authority to approve and/or modify the terms of the pooling and coordination agreements of closely integrated power systems when it deems those arrangements unlawful as filed. Over thirty years ago, in Pennsylvania Water & Power Co. v. FPC, the Supreme Court considered the Commission’s authority to order continued integrated operations by two utilities. For more than 20 years, the companies had been interconnected and had bought and sold power in a coordinated fashion. The FPC ordered a significant reduction in the rates charged by one utility to the other, and the selling utility refused to comply. As a result, the Commission itself prescribed rate schedules to comply with its rate order, requiring the utility to “continue to buy, sell, and transmit power in the same coordinated manner” as in the past, though at the decreased rates. The utility objected, but the Supreme Court sustained the order, observing that the integration of utilities is a “practice” within the meaning of section 206 and that the Commission could order its continuation and determine contract terms suitable to achieve that end:
The Act gives the Commission ample statutory power to order Penn Water and Consolidated to continue their long-existing operational “practice” of integrating their power output...,. In ordering such “practice” continued, the Commission was furthering the expressly declared policy of [section 206 of] the Act.
This case provides a solid foundation for the Commission’s authority to order a purchase or sale of power when, as here, such an order is consistent with the historical integration of a power pool or network.
This conclusion is further confirmed by the decision of this circuit in Central Iowa Power Cooperative v. FERC. In that case, FERC approved a voluntary pooling agreement among some 31 electric systems. The petitioners therein complained that the agreement failed to provide services offered by pooling arrangements established among other electric systems. Because of the voluntary nature of pooling arrangements under section 202(a) of the FPA, the court held that FERC could not order an expansion of pool services merely upon a showing “that a particular pool does not offer the same range of services as another pool.” The court, however, went on to determine that FERC did have “specific responsibility in this proceeding to decide whether a particular voluntary pool agreement was unjust, unreasonable, or unduly discriminatory,” and, in the event of such a finding, that FERC had authority to order expanded services:
The Commission had authority ... under section 206 of the Act ... to order changes in the limited scope of the Agreement, including the addition of pool services, if, in the absence of such modifications, the Agreement presented “any rule, regulation, practice or contract [that was] unjust, unreasonable, unduly discriminatory or preferential.”
Having found that the agency may exercise authority under section 206 to modify an unlawful voluntary power pool arrangement negotiated by nonaffiliates, a fortiori we must conclude that FERC may intervene to reform an unlawful agreement made by affiliates in a fully integrated, commonly owned system.
The cases relied upon by the Arkansas-Missouri petitioners are easily distinguishable. In Southern Co. Services, Inc., Southern Company filed a contract with the Commission to increase sales to Florida Power & Light (“FP & L”). Seminole Electric Cooperative intervened in the proceeding and argued that FP & L should be required to purchase energy from it. Seminole was a stranger to the UPSA at issue in Southern, was not affiliated with either Southern or FP & L, and did not contend Southern’s rates were unjust or unreasonable under the FPA. Given the entirely inapposite factual setting of Southern, FERC’s refusal to reject the Southern-FP & L contract or to order FP & L to purchase power from Seminole is irrelevant to the present case.
The Arkansas-Missouri petitioners also maintain that Otter Tail Power Co. v. FPC, establishes that compulsory purchases of power may be characterized as a compelled expansion of generating facilities, forbidden by section 202(b) of the Act. In that case, FERC ordered a utility to interconnect with a municipality and to assume the costs of the municipality’s generating plant in exchange for energy from the plant. The court determined that this transaction forced the utility to assume beneficial ownership of the plant, i.e., to enlarge its facilities. In the present case, FERC has ordered the operating companies to pay a certain percentage of the capacity costs of Grand Gulf — an entity constructed for system benefit and already within the beneficial ownership of the parent holding company, MSU. The Commission decision does not add any capacity to the MSU system. Nor does it modify the percentage of generating capability for which each company will ultimately 'bear responsibility under the 1982 System Agreement; it simply alters the composition of each individual company’s share.
In relying on Otter Tail Power, the parties once again seek to ignore AP & L’s role as an affiliated company in an historically integrated system and Grand Gulf’s status as a system project. In the factual context of the instant case, the reallocation of capacity costs among the parties cannot be described as a compelled purchase of either power or additional generating facilities.
3. Intrusion on State Jurisdiction
The Arkansas-Missouri petitioners and the Mississippi Public Service Commission (“MPSC”) separately contend that FERC’s orders unlawfully interfere with the jurisdiction of the state regulatory authorities. We will treat the arguments individually.
a. The Arkansas-Missouri Argument
Section 201(a) of the FPA provides that FERC’s regulation of interstate wholesale sales of electricity extends “only to those matters which are not subject to regulation by the States.” The petitioners assert that the FERC orders interfere with local authority over matters intended to be within the province of state regulators. They reason that FERC’s cost allocation has such an extensive impact on the rate base in the state jurisdictions that it, in effect, removes regulation of retail rates and capacity construction from the hands of the state commissions. These assertions are unfounded. FERC has exercised its jurisdiction in order to regulate the sale of electricity at wholesale in interstate commerce in the context of exchanges within a multi-state power pool, an area exclusively subject to FERC control. The fact that FERC’s assertion of jurisdiction has some impact on state regulation does not make it unlawful.
As the Supreme Court made clear in Public Utilities Comm’n of Rhode Island v. Attleboro Steam & Electric Co., the states are constitutionally prohibited from exercising jurisdiction over wholesale rates for electricity transmitted and sold in interstate commerce. In the absence of federal action, this holding created a regulatory gap, and Congress enacted Title II of the FPA to fill that gap and provide for federal authority over interstate wholesale rates:
Congress meant to draw a bright line easily ascertained, between state and federal jurisdiction, making unnecessary ... case-by-case analysis. This was done in the Power Act by making FPC jurisdiction plenary and extending it to all wholesale sales in interstate commerce except those which Congress has made explicitly subject to regulation by the States.
This holding was confirmed in Pacific Gas & Electric Co. v. State Energy Resources Conservation & Development Comm’n, in which the Supreme Court observed that states have retained “their traditional responsibility in the field of regulating electrical utilities for determining questions of need, reliability, cost, and other related state concerns” “[w]ith the exception of the broad authority of the ... Federal Energy Regulatory Commission over the need for and pricing of electrical power transmitted in interstate commerce....”
As explained above, there is no clash between state and federal jurisdiction in the instant case. FERC’s allocation of Grand Gulf was simply an exercise of its authority to regulate wholesale rates in interstate commerce — an area within its exclusive jurisdiction.
The Arkansas-Missouri petitioners contend that the FERC orders deprive state commissions of their control over retail rates. The Supreme Court has recently confirmed that
[ojnce FERC sets ... a rate, a State may not conclude in setting retail rates that the FERC-approved wholesale rates are unreasonable. A state must rather give effect to Congress’s desire to give FERC plenary authority over interstate wholesale rates, and to ensure that the States do not interfere with this authority.
Thus, once FERC permits a utility to charge a rate reflecting investment in a particular plant, a state commission may be obliged to reflect such an investment in the retail rate base. Under these circumstances, the petitioners argue, state regulatory authorities confronted with a FERC cost allocation will virtually lose control over retail rates.
In Nantahala Power & Light, the Supreme Court made clear that, in setting wholesale rates, the NCUC was required to give binding effect to the interstate wholesale rate that had been fixed by FERC. The Court further determined that the realm of preemption was “not limited to ‘rates’ per se ” and stated:
Here FERC’s decision directly affects Nantahala’s wholesale rates by determining the amount of low-cost power that it may obtain, and FERC required Nantahala’s wholesale rate to be filed in accordance with that allocation. FERC’s allocation of entitlement power is therefore presumptively entitled to more than the negligible weight given it by NCUC.
Similarly, in the present case, the Commission’s allocation of Grand Gulf’s costs and capacity affects wholesale rates and, therefore, the state commissions may not “interfere” with FERC’s “plenary authority.”
Moreover, the petitioners’ argument would apply to the costs embodied in any wholesale rate approved by FERC and, therefore, proves too much. In any wholesale rate proceeding, the state commissions may protect their interests, as here, by intervening and presenting evidence before the Commission, a neutral body. The main point here is that FERC plainly had authority to approve or reject the cost allocation pursuant to its jurisdiction over wholesale interstate rates despite its inevitable impact on retail rates.
Moreover, when, as here, affiliated operating companies in an integrated regional system enter into agreements for wholesale power sales in interstate commerce which allocate costs, FERC jurisdiction has additional merits. As ALJ Head observed, “the Commission is perhaps in the best position to reach the most equitable result and to act in the public interest, rather than to be controlled by the necessarily parochial concerns of the States.” The basis of this conclusion has been discussed by FERC in another context:
If State Commission A orders a change to be made in a wholesale rate filing, presumably because it would benefit the ratepayers in State A, then State Commission B might well retaliate by ordering a counter rate filing that would benefit the ratepayers in State B____ It was to protect against such competing local state interests that a Federal Commission was given jurisdiction to protect the national interest in transmission and sales for resale in interstate commerce.
This same reasoning applies with equal force to a cost allocation among affiliates who exchange power at wholesale in interstate commerce.
b. The Mississippi Argument
The MPSC argues that the Commission’s orders unlawfully disregard the considerations upon which that state agency relied in certificating construction of Grand Gulf in Mississippi. We find the Commission’s analysis and rejection of this argument entirely correct.
MPSC asserts that the utilization of any allocation procedure other than that accepted by it in the Grand Gulf certification proceedings would impermissibly usurp its certification authority. As the Commission found, this assertion is incorrect for several reasons. First, as has been detailed above, state regulatory authorities, including the MPSC, do not have authority, as a threshold matter, to approve any allocation of Grand Gulf’s cost or capacity among the system operating companies. Such decisions were subject to review and approval by the Commission.
Moreover, the MPSC argument, which it quite properly characterizes as one of equitable estoppel, is untenable under the circumstances. As FERC correctly observed, the Commission itself made no representations to the MPSC; its hands could not be tied by the doctrine, particularly here where its application would lead to “an inequitable result.”
Finally, it is noteworthy that the MPSC “did not specifically approve any particular allocation or allocation methodology for Grand Gulf or establish any particular allocation or allocation methodology as a condition of the certificate.” This factual prerequisite to the application of the doctrine of equitable estoppel, too, is absent.
For all of these reasons, the MPSC’s arguments were properly rejected by FERC.
4. Intrusion on the SEC’s Jurisdiction
The Arkansas-Missouri petitioners contend that FERC has impermissibly infringed upon the authority of the SEC to regulate the MSU system as a registered holding company under the PUHCA. They further maintain that, by statutory mandate, any conflict between the SEC’s authority under the PUHCA and FERC’s authority under the FPA must be resolved in favor of the former. We find no inconsistency in the actions taken by FERC and the jurisdiction of the SEC.
The SEC has correctly explained the division of responsibility between itself and FERC:
The jurisdiction of this Commission [the SEC] with respect to the availability agreement existed under Section 12(b) of the Act as to the indemnity obligations of the four operating companies to MSE and as to the indemnity that three of the companies gave to APL. The contracts for the sale of electric energy among the subsidiaries of MSE [sic] are subject to the exclusive jurisdiction of FERC. Generally a contract for sale of goods and services to an associate company is governed by Section 13(b) of the Act, but Section 2(a)(20), which defines “Sales contract,” expressly excludes sale of “electric energy or natural or manufactured gas.”
The SEC thus explicitly acknowledged FERC’s control over wholesale rates and sales among the operating companies and its statutory authority over the rates and rate-related terms of the UPSA. Moreover, when the SEC approved the Reallocation Agreement among the system operating companies, it recognized that a rate schedule for the sale of energy would be filed with FERC — a schedule plainly subject to modification pursuant to FERC’s authority under the FPA. The SEC itself perceives no conflict between its jurisdiction and that of FERC. Similarly, having determined that the allocation of Grand Gulf is well within FERC’s authority over wholesale rates for electric energy in interstate commerce, we, too, have little trouble concluding that there is no conflict with SEC jurisdiction.
Nor do we find merit in the claim that FERC’s action is at odds with the goals of the PUHCA. We agree that an important aim of the PUHCA was the elimination of control of some holding companies so that local utilities might be regulated by local authorities. However, the PUHCA itself permits holding companies to own subsidiary utilities when its purposes are best served by focusing on regional rather than state interests, so long as the effectiveness of regulation is not impeded. The PUH-CA permits the continued existence of a holding company if its operations are limited “to a single integrated public-utility system,” which is defined as follows: The SEC has determined that the MSU system constitutes an “integrated public-utility system.” Thus, the regional integration embodied in the structure of the MSU system was clearly contemplated by Congress when it enacted the PUHCA.
a system consisting of one or more units of generating plants and/or transmission lines and/or distributing facilities, whose utility assets, whether owned by one or more electric utility companies, are physically interconnected or capable of physical interconnection and which under normal conditions may be economically operated as a single interconnected and coordinated system confined in its operations to a single area or region, in one or more States, not so large as to impair (considering the state of the art and the area or region affected) the advantages of localized management, efficient operation, and the effectiveness of regulation____
Moreover, in the PUHCA itself, Congress recognized “that affiliate power transactions 'are not susceptible of effective control by any State.’ ” “Transactions, such as this one, between affiliated power companies appear to be precisely the type of transactions that Congress sought to regulate by enactment of the Federal Power Act and the Public Utility Holding Company Act of 1935.”
5. The Mobile-Sierra Doctrine
The APSC maintains that FERC’s orders disregard the Mobile-Sierra doctrine, which requires the Commission to respect certain private contract rights in exercising its regulatory powers. We find that, in the instant case, this doctrine does not bar the exercise of FERC’s power under section 206 of the FPA to reform a practice or contract affecting a rate charged by a public utility for wholesale service in interstate commerce.
In the Mobile case, the Mobile Gas Service Corporation (“Mobile”), a natural gas distributor, had entered into a long-term contract with the United Gas Pipe Line Company (“United”) to purchase gas for resale to an industrial customer, Ideal Cement Company (“Ideal”) Ideal had a reciprocal contract to buy the gas from Mobile. The Mobile-United agreement had been filed with the Commission and was part of United’s filed schedule of rates. Subsequently, United, acting without the consent of Mobile, altered the rates specified in its contract with Mobile by filing with the Commission a new rate schedule purporting to increase the rate on gas sold to Mobile for resale to Ideal. Mobile challenged United’s action, and the Supreme Court held that the Natural Gas Act does not permit natural gas companies to change their rate contracts by unilateral action.
Thereafter, in Sierra, the Court applied its holding in Mobile to cases arising under the FPA. Thus, neither the filing of a new rate nor a finding that it is reasonable may abrogate a utility’s contract with a distributor. “Together, the two cases make it crystal clear that a heavy burden must be met before a customer who has negotiated a fixed-price contract can be deprived against his will of the benefits of his bargain.”
APSC suggests that, in reforming the UPSA, FERC has snatched from AP & L the favorable result of its contractual escape from responsibility for Grand'Gulf in contravention of the Mobile-Sierra holdings. We disagree. Initially, we note that the UPSA itself expressly permits unilateral changes in the contract by MSE:
Nothing contained herein shall be construed as affecting in any way the right of MSE to unilaterally make application to FERC for a change in the rates contained herein or any other term or condition of this Agreement under Section 205 of the Federal Power Act and pursuant to FERC Rules and Regulations promulgated thereunder.
Moreover, the UPSA makes no mention of any restriction on the Commission’s authority to reform agreements under section 205 or section 206 of the FPA. This circuit has made it clear that parties may agree to unilateral rate filings and that parties may agree to “leave unaffected” the Commission’s power to replace rates, and terms affecting rates, that are either contrary to the public interest or unjust, unreasonable, unduly discriminatory or preferential to the detriment of the contracting parties. The signatories to the UPSA elected to permit unilateral rate filings and not to restrict the Commission’s power. The parties’ bargain itself contemplates the Commission’s review, and potential reform of their agreement; the Mobile-Sierra doctrine requires no more.
Finally, even if the contracts fall within the scope of the Mobile-Sierra decisions, the Supreme Court has emphasized that the relevant agency, here FERC, may always reform a contract found to be “unlawful” or “contrary to the public interest,” i.e., that “contracts remain fully subject'to the paramount power of the Commission to modify them when necessary in the public interest.” The Court stated in Sierra that the Commission “has undoubted power under § 206(a) to prescribe a change in contract rates whenever it determines such rates to be unlawful” and indicated three circumstances under which the Commission might conclude that a rate or a contract term affecting a rate could be found contrary to the public interest and therefore subject to revision: “where it might impair the financial ability of the public utility to continue its service, cast upon other consumers an excessive burden, or be unduly discriminatory.” Here FERC expressly adopted the findings of AU Liebman who found the level of discrimination in the UPSA “profound” and agreed that its impact on customers in Louisiana and Mississippi would be “dramatic[ ].” The Commission’s specific determination of unlawfulness provides the “unequivocal public necessity” for reformation of the UPSA under section 206 of the FPA.
For each of the foregoing reasons, the Mobile-Sierra doctrine does not preclude FERC’s actions in the instant case.
C. Conclusion
For all of the foregoing reasons, we reject petitioners’ principal contentions with respect to FERC’s jurisdiction. We have also considered all other arguments suggesting that the Commission is without jurisdiction in this case, and we find them to be without merit. The Federal Power Act clearly provides FERC with authority to issue the orders here in question. We now turn to the merits of this case.
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III. Merits
Petitioners challenge FERC’s decision to reject the Unit Power Sales Agreement and to equalize nuclear capacity among the MSU operating companies. In the process, many advocate adoption of a particular, alternate allocation. We reject these challenges because we conclude that FERC’s action was both rational and within the Commission’s range of discretion to remedy unduly discriminatory rates. We first examine the workings of the UPSA and the 1982 System Agreement and then review the evidentiary basis for FERC’s determination that the Agreements as filed were unduly discriminatory. We then address petitioners’ claims that FERC was required to adopt a remedy other than the one it chose. Finally, we consider several remaining issues such as Commissioner Richard’s refusal to recuse himself and FERC’s refusal to reopen and update the record.
A.
Under section 206 of the Federal Power Act (“FPA”), FERC must determine whether an agreement as filed is “unjust, unreasonable, unduly discriminatory or preferential.” 16 U.S.C. § 824e(a) (1982). If the agreement is just and reasonable, then it is approved as filed. If, on the other hand, the agreement is unduly discriminatory, then FERC is required to “determine the just and reasonable ... contract to be thereafter observed and in force, and shall fix the same by order.” Id.
In this case, FERC reviewed “two initial decisions in dockets which are not consolidated but which have overlapping issues concerning the appropriate allocation of capacity costs incurred on the ... (MSU) system.” 31 F.E.R.C. (CCH) at 61,631. Thus, FERC considered whether the UPSA and the 1982 System Agreement, taken together, were just and reasonable.
To understand the Commission’s decision, it is necessary to examine the workings of the UPSA and the System Agreement in detail. The UPSA resulted from negotiations among the four operating companies and MSE in 1979. These negotiations produced the 1981 Reallocation Agreement in which the companies agreed that all Grand Gulf power would be purchased by LP & L, MP & L and NOPSI in definite percentage shares. AP & L relinquished all interest in Grand Gulf, and the other operating companies agreed to indemnify and hold AP & L harmless for its obligations to lenders under the 1974 Availability Agreement.
Pursuant to the Reallocation Agreement, the parties executed the UPSA in June 1982 to be filed with FERC. The UPSA provides in pertinent part:
1.2 The Purchasers shall, subject to the terms and conditions of this Agreement, be entitled to receive all of the Power which shall be available to MSE at the Project in accordance with their respective Entitlement Percentages. The Entitlement Percentages are as follows:
Entitlement Percentages Unit No. 1
LP&L 38.57%
MP&L 31.63%
NOPSI 29.80%
100.00%
26 F.E.R.C. (CCH) at 65,097. The UPSA further provides that LP & L, MP & L and NOPSI shall pay MSE the same proportionate shares of the total capital and operating costs of the Grand Gulf unit. Id. Thus, the UPSA allocates Grand Gulf capacity and energy in identical shares.
Meanwhile, in April 1982, MSU filed the 1982 System Agreement with FERC to create a new rate schedule for the generation and consumption of the System’s energy. A critical aspect of the 1982 System Agreement, for our purposes, is that it does not apply to Grand Gulf. That is, it assumes the existence of the UPSA and its allocation of Grand Gulf capacity and energy. Thus, the 1982 System Agreement may be read and applied properly only by recalling the Grand Gulf allocations fixed by the UPSA.
Under the 1982 System Agreement, capacity and energy costs are allocated separately. As for energy, each company is entitled to first call on the lowest cost energy generated by the plants located within its service area (and by Grand Gulf up to its UPSA percentage entitlement). The energy generated by a company’s plants in excess of that company’s demand goes into a pool of energy available to companies whose plants produce less energy than they demand. Such companies may purchase the lowest cost energy available in the pool.
The 1982 System Agreement also establishes a formula to equalize roughly the costs of capacity to generate energy. This is achieved by equalizing capacity among the operating companies with corresponding capacity equalization payments. Companies that are “long” on capacity — i.e., those whose percentage of total System demand — contribute their excess capacity to “short” companies — ie., companies whose percentage of total System capacity is less than their percentage of total System demand. In return, the “short” companies make capacity equalization payments to the “long” companies. Under the 1982 System Agreement, these payments are based on the investment costs of “intermediate” oil and gas fired generation facilities, which are much lower than the investment costs of newer coal and nuclear units. In determining whether, and to what extent, a company is long or short, the System considers not only the capacity of units located in that company’s service area, but also the share of Grand Gulf capacity to which that company is entitled under the UPSA.
The operating companies intended to roughly equalize the System’s capacity costs among themselves by executing the UPSA and the 1982 System Agreement. And, indeed, at the time they were negotiated, these agreements appeared to achieve that objective. When the UPSA was negotiated in 1979, Grand Gulf capacity appeared to be a good buy. The initial cost estimate for building both Grand Gulf units was $1.3 billion; by the time the first unit began operations in 1985, however, the final cost for that unit alone was $2.7 billion. It seems unlikely that, in 1979, the companies could have foreseen that the cost of completing Grand Gulf would quadruple because of the lengthy regulatory delays that would occur in the aftermath of the Three Mile Island accident. The System Agreement’s formula for roughly equalizing capacity costs among the companies also appeared reasonable when negotiated. Capacity equalization payments were based on the costs of oil and gas fired units, rather than the more costly nuclear and coal fired units. Historically, a company’s ability to construct oil and gas fired units depended on the existence of sufficient natural resources within its service area. By contrast, the ability to build coal and particularly nuclear units was less restricted. Thus, when the System decided to shift to coal and nuclear capacity, each of the operating companies was assigned to build nuclear capacity: AP & L was assigned ANO I & II; LP & L was assigned Waterford III; MP & L was assigned to Grand Gulf I; and NOPSI was assigned Grand Gulf II. The cost of nuclear capacity was assumed to be roughly equivalent. Thus, each company would share in the cost of the older oil and gas capacity — either by having constructed it or by making capacity equalization payments — and each company would share in the cost of the System’s newer capacity — by constructing nuclear and/or coal fired units.
By the time the Commission reviewed the UPSA and the System Agreement, however, conditions had changed radically. Though AP & L had successfully completed the ANO units without substantial cost overruns, see 31 F.E.R.C. (CCH) at 61,669 n. 17, the cost of constructing Grand Gulf I and Waterford III approached three to four times original estimates. As AU Liebman recognized, “[djisparate rates are legitimate under section 205(b) of the FPA if sufficient factual bases exist to justify the difference.” 26 F.E.R.C. (CCH) at 65,106 (citing Metropolitan Edison Co. v. FERC, 595 F.2d 851, 857, 858 (D.C.Cir.1979)). Upon reviewing the nature and operation of the MSU System, Judge Liebman concluded that the facts were insufficient to outweigh “the profound undue discrimination caused by [the UPSA] allocation.” Id. at 65,108. The Commission affirmed, concluding that “the 1982 System Agreement and the UPSA, as filed, together will [not] achieve proper cost allocation," and that “the 1982 System Agreement in conjunction with Judge Liebman’s allocation of nuclear capacity will achieve just and reasonable results.” 31 F.E.R.C. (CCH) at 61,655.
B.
The Commission based its decision primarily upon two findings: (1) “the fact that all Middle South System nuclear units have been planned to meet overall System needs and objectives,” and (2) “the unforeseen problems unique to constructing nuclear units.” 31 F.E.R.C. (CCH) at 61,655 (footnote omitted). The Commission’s first finding is more than adequately supported by the record. The Commission began by discussing the composition of, and key role performed by, the System Operating Committee. The Operating Committee is composed of five members: one representative from each of the four operating companies and one from the System’s wholly-owned service company, Middle South Services, Inc. (“MSS”). See 31 F.E.R.C. (CCH) at 61,646; 30 F.E.R.C. (CCH) at 65,143. The Commission undertook a thorough review of the record testimony of current and former System executives, see 31 F.E.R.C. (CCH) at 61,646-48, as well as various sets of minutes of the System Operating Committee from 1961 to 1980, see id. at 61,648-50. This evidence amply supports the Commission’s conclusion that although individual operating companies were intimately involved in the planning stages of new generation units and sought to promote their own interests, “the Operating Committee nevertheless made the major decisions concerning general timing, location and size of plant additions, in view of the overall needs of the system, while accommodating individual company needs wherever possible.” Id. at 61,650. For example, Mr. Trumps, an MSS official, testified that “generation planning has been done on a systemwide basis, but with due consideration’ of the needs of the individual companies as to the location of new facilities.” Id. at 61,647. Mr. Trumps also testified that under the 1973 System Agreement, an individual operating company could not block an Operating Committee decision since that body acted by two-thirds vote, and that the 1982 System Agreement further strengthened the Committee’s position by authorizing decisions to be made by majority vote. See id. at 61,651.
In making its findings about the System’s planning and operations, FERC expressly rejected ALJ Head’s contrary findings as unsupported by the evidence. First, the Commission., rejected Judge Head’s conclusion that there is “a pattern of autonomy on the part of the individual operating companies, particularly as to specific plant site locations, fuel and financing.” 30 F.E.R.C. (CCH) at 65,168. The Commission acknowledged that the operating companies “exercise[] their authority to decide details such as specific location, timing, and sizing of [an assigned] unit,” 31 F.E.R.C. (CCH) at 61,650, but rightly concluded that this fact does not affect the finding that “decisions on the MSU System are made based on an overall System plan and primarily for the System as a whole,” id. (emphasis in original).
Second, and more important for our purposes, the Commission rejected ALJ Head’s determination that Grand Gulf is “an anomaly to the regular planning and construction of generating facilities by the operating companies of the Middle South system.” 30 F.E.R.C. (CCH) at 65,172. Again, the Commission’s conclusion is supported by the record. Relying on the testimony of Mr. Lupberger, an officer of MSU, MSE and MSS, the Commission began by recalling that in the late 1960’s and early 1970’s, the System decided to change its fuel mix by shifting away from oil and gas generation in favor of nuclear and coal capacity. See 31 F.E.R.C. (CCH) at 61,651. Pursuant to that decision, AP & L was assigned to build the ANO units and MP & L was assigned to construct Grand Gulf I. After reviewing the relevant testimony, FERC concluded that “[t]he evidence supports a finding that the Grand Gulf units were originally planned in the same manner as the other nuclear units, i.e., to meet MP & L’s needs, to meet System needs, and to meet the System goal of diversifying fuel mix.” 31 F.E.R.C. (CCH) at 61,653. The Commission recognized that the way in which Grand Gulf had to be financed, see supra pp. 17-18, resulted in differences between Grand Gulf and other system units, all related to the fact that MSE, rather than an individual operating company, owns and operates the plant. See id. But, as FERC correctly observed, these differences “arose solely from the fact that MP & L became unable to finance the Grand Gulf units on its own. They do not contradict the fact that Grand Gulf 1 and 2 were planned in the same manner as the other nuclear units on the system.” Id. at 61,653-54. Indeed, Mr. Lupberger’s testimony was that the system employed the same general process in deciding to build Grand Gulf as it did in deciding to build the ANO units. See id. at 61,654.
Having determined that “all Middle South System nuclear units have been planned to meet overall System needs and objectives,” 31 F.E.R.C. (CCH) at 61,655, the Commission’s conclusion that the UPS A and the 1982 System Agreement, as filed, were unduly discriminatory follows almost as a matter of course. Under the Agreements as filed, the cost of nuclear capacity varied widely from company to company. For example, the cost to AP & L for its 1694 megawatts of nuclear capacity was $900 million, while the cost to LP & L for 1538 megawatts was $3.4 billion, approximately four times as much. See 26 F.E.R.C. (CCH) at 65,107. Similarly, the cost to MP & L for 356 megawatts and to NOPSI for 335 megawatts was $800 million and $700 million, respectively, while AP & L received 1694 megawatts, approximately five times the capacity of either, for just $900 million. See id. As already discussed, the 1982 System Agreement’s provision for capacity equalization payments does little, if anything, to reduce these vast nuclear capacity cost disparities. That is because AP & L is currently a “long” company, see 30 F.E.R.C. (CCH) at 65,166, and, in any event, capacity equalization payments are based on the costs of oil and gas fired units rather than more costly nuclear units such as Grand Gulf and Waterford III. Given the degree of integration on the MSU System, FERC could properly conclude that the tremendous disparities in nuclear capacity costs among the operating companies disrupt the System’s historical pattern of roughly equalizing capacity costs and thus constitute undue discrimination under section 206 of the Federal Power Act.
The second finding upon which the Commission’s decision rests — the existence of “unforeseen problems unique to constructing nuclear units,” 31 F.E.R.C. (CCH) at 61,655 — relates primarily to FERC’s choice of means to remedy the undue discrimination on the system. Petitioners do not seriously dispute the existence of this finding; rather, they challenge the use to which it was put by the Commission. For example, the Arkansas-Missouri parties argue that FERC erred by considering facts and circumstances that arose after the execution of the UPSA in evaluating the reasonableness of that agreement. Rather, they assert that the Commission could do no more than “examin[e] the factual circumstances that prevailed at the time the UPSA was formulated in 1979-80.” Brief of Petitioners Arkansas Public Service Commission, Missouri Public Service Commission, Arkansas-Missouri Congressional Delegation and State of Arkansas (“Arkansas-Missouri Pet. Br.”) at 66; accord Brief for Petitioner Arkansas Power & Light Company (“AP & L Pet. Br.”) at 45. We find this contention to be completely without merit.
Under the FPA, the Commission has a statutory duty to reform unlawful rates and establish just and reasonable ones, see 16 U.S.C. § 824e(a) (1982), and a statutory right to order production of, and to examine, “all accounts, records, and memoranda of licensees and public utilities,” id. § 825(b), in performing that duty. This, in effect, was the Commission’s response on rehearing: “The salient issue here is not whether the agreement was reasonable when made, or whether it met the System objectives at the time it was made. Rather, the principal inquiry is whether the allocation is appropriate based on the evidentiary record that was subsequently developed.” 32 F.E.R.C. (CCH) at 61,957.
The Arkansas-Missouri parties appear to ignore this rationale and argue simply that FERC’s evaluation of the UPSA in light of subsequent events conflicts with prior Commission precedent. See Arkansas-Missouri Pet. Br. at 67-68; AP & L Pet. Br. at 46-48. The cited cases are inapposite to the Commission’s review of the UPSA. They establish only that the prudence of power supply arrangements and generation construction activities must be evaluated on the basis of circumstances prevailing at the time the activity was undertaken, and are thus limited to “prudence review” — examinations of utilities’ decisions to incur costs. The Commission’s inquiry is quite distinct. A system’s allocation of nuclear capacity costs may not be imprudent on the part of the parties at the time they agree to incur them, but might nevertheless result in present undue discrimination. Accordingly, the cases present no bar to the Commission’s reliance on the record to perform its statutory duty under section 206 of the FPA.
AP & L advances an additional argument against the Commission’s second finding: “there is no substantial evidence of record put forth by the agency to support its conclusion that the alleged problems were ‘unforeseen.’ ” AP & L Pet. Br. at 45-46. Besides erroneously placing the burden of proof on the Commission, see San Luis Obispo Mothers for Peace v. NRC, 789 F.2d 26, 37 (D.C.Cir.) (en banc) (Commission’s failure to “include citations to specific pages of the record ... provides no basis for overturning the Commission’s decision”), cert. denied, — U.S. —, 107 S.Ct. 330, 93 L.Ed.2d 302 (1986), this objection is simply irrelevant. Even if we assume that the problems were foreseen when the UPSA was negotiated and that the parties intentionally entered into an unduly discriminatory agreement, the Commission’s duty to reject the agreement as filed would not be diminished.
The Commission’s second finding supports the Commission’s choice of means to remedy the undue discrimination created by the UPSA and the 1982 System Agreement. That choice was to adopt ALJ Liebman’s allocation of Grand Gulf and approve the 1982 System Agreement as filed. We hold that this choice was within the Commission’s discretion to remedy the undue discrimination it identified on the System. We first examine the Commission’s remedy in more detail and then consider the various petitioners’ objections and alternate proposals.
The Commission allocated Grand Gulf responsibility as follows:
AP & L ........................ 36%
LP&L ........................ 14%
MP & L........................ 33%
NOPSI ........................ 17%
See 31 F.E.R.C. (CCH) at 61,633. The effect of this allocation is “not just to allocate Grand Gulf costs, but to allocate the costs of all nuclear capacity on the MSU system.” Id. This can be seen by following the steps necessary to arrive at this allocation. The System’s total nuclear capacity costs are determined by summing the investment costs of all nuclear units on the System, ANO I & II, Waterford III and Grand Gulf. Multiplying this figure by each company’s relative share of total system demand yields each company’s total cost responsibility in dollars. The amount of each company’s prior nuclear investment costs is then subtracted to yield each company’s Grand Gulf cost responsibility. Finally, these figures are divided by Grand Gulf’s total investment cost to yield the percentage of Grand Gulf capacity for which each company is responsible. See 31 F.E.R.C. (CCH) at 61,655. “The result of this allocation of Grand Gulf is to give each operating company a share of the cost of nuclear capacity roughly proportionate to that company’s relative share of system demand....” 26 F.E.R.C. (CCH) at 65,109. The Commission’s rationale for adopting this allocation is considered in the context of the various objections and alternate allocations advanced by the petitioners.
C.
Petitioners advance numerous arguments in opposition to the Commission’s decision and propose various alternate allocations. We address these arguments in the context of reviewing each proposed alternate allocation.
1. The UPSA and the 1982 System Agreement
AP & L and the Arkansas-Missouri parties advocate approval of the UPSA and the 1982 System Agreement as filed. In so doing, they attack the Commission’s decision on several grounds. We have already considered and rejected two of these grounds in the preceding section. See supra pp. 1557-1558. The remaining grounds are considered here.
First, AP & L argues that in reforming the UPSA, “the FERC failed to give weight to the Congressional policy favoring voluntary power pooling agreements by ‘cavalierly disregarding’ the reasonableness of the specific agreements that were filed with the agency.” AP & L Pet. Br. at 41 (quoting ANR Pipeline Co. v. FERC, 771 F.2d 507, 519 (D.C.Cir.1985)). While it is true that section 202(a) of the FPA seeks to encourage voluntary power pooling transactions, see 16 U.S.C. § 824a(a) (1982), AP & L’s argument is no more than an attack on the Commission’s finding that the agreements as filed are unduly discriminatory. But we have already held that that finding is virtually inescapable, given the record in this case, see supra pp. 1556-1557, and we reject any suggestion that the FPA’s policy to encourage voluntary power pooling agreements could override the Commission’s specific obligation in section 205 of that Act to reject such agreements if found to be “unjust, unreasonable, unduly discriminatory or preferential.” 16 U.S.C. § 824e(a) (1982).
Second, the Arkansas-Missouri parties assert that the Commission’s decision is “inconsistent with the Commission’s own established precedent in Nantahala Power & Light Company, Opinions Nos. 139 and 139-A, 19 FERC (CCH) ¶ 61,152 (1982) and 20 FERC (CCH) ¶ 61,430 (1982), aff'd, 727 F.2d 1342 (4th Cir.1984), and Georgia Power Company, Opinion No. 711, 52 FPC 1343 (1974), aff'd, Opinion No. 711-A, 53 FPC 1103 (1975).” Arkansas-Missouri Pet. Br. at 54. Though these eases involve Commission refusals to equalize costs, they provide no support for petitioners in this case.
Georgia Power involved a challenge to Georgia Power’s reliance on its own generation and transmission costs to establish its cost of service. The challenger argued that Georgia Power was part of an integrated electric utility system whose production costs should be allocated to its members on a system, rather than individual company, basis. Finding that the existing allocation was not unjust and unreasonable, the Commission declined to order a “rolled-in” or equalized cost allocation. Petitioners’ argument ignores the fact that the FPC found no undue discrimination. The case is distinguishable on that basis alone. Moreover, the Georgia Power Commission suggested that a case involving companies’ reliance on “large multi-company generating units which are remote from their service areas” might necessitate some form of cost equalization. See 52 F.P.C. at 1349. Grand Gulf is such a unit. Thus, we hold that Georgia Power’s refusal to equalize costs in the absence of undue discrimination does not apply where, as here, the Commission found such discrimination in the presence of a multistage generating unit.
Nantahala involved an agreement between Nantahala Power & Light Co. and Tapoco, both wholly-owned subsidiaries of Alcoa, apportioning the capacity and energy which both companies were jointly entitled to receive from the Tennessee Valley Authority. That entitlement arose from a series of agreements among TV A, Alcoa, Nantahala and Tapoco under which Nantahala and Tapoco turned over land and generating facilities to TVA for development of the Fontana Dam in exchange for capacity and energy entitlements. The Commission found the apportionment agreement between Nantahala and Tapoco to be unfair. Though the Commission declined to order full cost equalization, it increased Nantahala’s entitlement to remedy the unfairness. The Commission’s decision was based, in part, upon its conclusion that the two companies do not operate as an integrated system. See 19 F.E.R.C. (CCH) at 61,277. This conclusion was affirmed by the Fourth Circuit as based on substantial evidence. See Nantahala Power & Light Co. v. FERC, 727 F.2d 1342, 1348 (4th Cir.1984).
In the case at bar, the Commission’s review of the evidence led it to reach precisely the opposite conclusion — that the MSU system is highly integrated. That determination is supported by substantial evidence. See supra pp. 1555-1556. Moreover, the Commission has not ordered full production costs, or even nuclear production cost equalization in this case. Rather, as in Nantahala, it has ordered a more limited remedy designed only to cure the undue discrimination found. Thus, petitioners’ argument that the Commission went too far in this case is without merit.
Third, AP & L argues that the energy from its “less costly base load generation is displaced from AP & L’s usage, to become ‘exchange energy’ and be sold into the pool for the benefit of the other operating companies.” AP & L Pet. Br. at 50. This argument is simply wrong. Under the 1982 System Agreement, AP & L is entitled to first call on its own lowest cost energy, whatever the source. Thus, if ANO I & II produce AP & L’s lowest cost energy and AP & L’s demand exceeds the amount produced, then AP & L will retain all of the benefits of the ANO units regardless of its Grand Gulf allocation. If anything, more expensive, not less expensive, energy will be displaced. AP & L’s real complaint is that it must pay its equitable share of Grand Gulf’s capacity costs.
Fourth, AP & L argues that the Commission’s decision compels it “to pay more for nuclear capacity than is justified by [its] actual ownership costs, and at the same time allows the other operating companies to pay less for nuclear capacity than their actual ownership costs.” AP & L Pet. Br. at 55-56 (footnote omitted). This argument is difficult to understand. The premise seems to be that AP & L’s “actual ownership costs” are only those associated with ANO I & II, while the other companies’ include the costs of Grand Gulf. The premise is incorrect. Under the Commission’s allocation, each company is responsible for the costs of its own nuclear units as well as its share of Grand Gulf. AP & L’s argument is really that it should pay for none of the costs associated with Grand Gulf — the situation under the UPSA as filed. But, as we have already held, FERC correctly found that the UPSA allocation results in unlawful discrimination.
In short, AP & L and the Arkansas-Missouri parties have advanced no persuasive argument against the Commission’s decision to reject the UPSA as filed.
2. ALJ Head’s Allocation
Petitioners City of New Orleans, Mississippi Industries, MP & L, and Representative Webb Franklin, and intervenor Representative Wayne Dowdy support the Commission’s finding of undue discrimination, but argue that the Commission erred in deciding to equalize all nuclear capacity costs. Rather, they assert that the Commission should have adopted ALJ Head’s solution of equalizing only the investment costs associated with Grand Gulf. See Consolidated Brief of Petitioners Mississippi Industries, Mississippi Power & Light Company, and Representative Webb Franklin, and Intervenor Representative Wayne Dowdy (“Consolidated Pet. Br.”) at 60-61; Brief of Petitioner City of New Orleans, Louisiana (“New Orleans Pet. Br.”) at 48-50.
Putting aside for the moment these petitioners’ arguments against the allocation ordered by FERC, we have little difficulty affirming FERC’s rejection of Judge Head’s solution. That solution rests on Judge Head’s finding that Grand Gulf is an anomaly on the MSU System — the only facility planned and constructed for the benefit of the system as a whole. See 30 F.E. R.C. (CCH) at 65,170-72. FERC expressly rejected this finding, concluding instead that Grand Gulf was “planned in the same manner as the other nuclear units on the System.” 31 F.E.R.C. (CCH) at 61,654. Thus, Judge Head’s solution is viable only if we conclude that the Commission’s findings concerning the integration of the MSU System and the status of the Grand Gulf unit are not based on substantial evidence. We have already concluded that they are. See supra pp. 1555-56.
In advocating adoption of Judge Head’s solution, petitioners rely primarily on three arguments against FERC’s chosen allocation. First, they assert that the Commission’s decision irrationally allocates 33% of Grand Gulf to MP & L, an increase over the 31.63% allocated to MP & L under the unduly discriminatory UPSA. Second, they argue that FERC did not adequately explain why it focused on nuclear but not coal facilities in equalizing capacity costs. Third, they assert that MP & L and NOPSI receive less nuclear capacity per nuclear investment dollar than does AP & L. As explained below, we find that none of the arguments advanced by these petitioners requires reversal of the Commission’s decision.
Petitioners’ first objection is that “[t]he Commission failed to reconcile its allocation scheme imposing 33 percent of Grand Gulf costs on Mississippi with the finding that a 31.63 percent allocation was detrimental and unjustified.” Consolidated Pet. Br. at 39. The argument is that because the UPSA was found to be unduly discriminatory, an allocation to MP & L greater than that found in the UPSA necessarily must be unlawful. The argument misconstrues the nature of the statutory inquiry. The question is whether the agreement is unduly discriminatory or preferential. Thus, there is no inconsistency in the Commission’s determination that the UPSA’s allocation of 31.63% of Grand Gulf to MP & L and 0% to AP & L is unduly discriminatory but that a 33% allocation to MP & L and a 36% allocation to AP & L is not. That is because a party claiming discrimination, by definition, objects only to his treatment as compared to that of other similarly situated parties. Thus, the reasonableness of the Commission’s allocation may be judged only by examining the relative impact on the four operating companies and the degree to which they are similarly situated.
Petitioners’ second argument is no more availing. They assert that “the system’s planned shift to primary reliance on coal and nuclear generation ... plainly does not support focusing exclusively on nuclear generation and excluding coal-fired base-load units from that formula.” Consolidated Pet. Br. at 45-46; accord New Orleans Pet. Br. at 43. This argument is misleading. While the System’s move toward coal and nuclear facilities might support equalization of the capacity costs of both coal and nuclear units, it does not preclude FERC’s decision to equalize only the investment costs of the nuclear units. Petitioners’ argument ignores the Commission’s explicit finding that the unforeseen problems that led to dramatic cost overruns were “unique to constructing nuclear units.” 31 F.E.R.C. (CCH) at 61,655 (footnote omitted). In this circumstance, we find that the Commission’s focus on nuclear but not coal units was rational.
Petitioners argue further that “[t]o the extent that unexpectedly high costs of [nuclear] facilities support special allocation treatment, the stated reason supports only a grouping of Grand Gulf 1 and Waterford 3.” New Orleans Pet. Br. at 44; see Consolidated Pet. Br. at 46-47. They argue that to include the ANO units but not the coal units was arbitrary and capricious since the investment costs of the former are comparable to those of the latter. To be sure, this fact would have justified a Commission decision to equalize only the investment costs of Grand Gulf and Waterford III. (Interestingly, neither these petitioners nor any others have advanced this option here or below.) But, we conclude that the Commission also rationally could include the ANO units. Indeed, FERC decided to include them precisely because their investment costs were not comparable to those of the more recent nuclear units. The Commission decided to equalize the investments cost of all nuclear units because their widely divergent costs were due solely to the timing of their construction, see 32 F.E.R.C. (CCH) at 61,960-61, a reason insufficient to justify the differences.
Petitioners’ third argument is that the Commission’s allocation is itself unduly discriminatory because it allocates only the investment costs of nuclear capacity but not the benefits produced by that capacity. Thus, “MP & L must pay approximately 15 percent of the aggregate cost of nuclear capacity on the MSU system, but receives the benefit of only 9.5 percent [(or 371 megawatts)] of that capacity.” Consolidated Pet. Br. at 63. AP & L, on the other hand, is responsible for only 33% of the System’s nuclear investment costs, but is entitled to first call on the energy produced by 2099 megawatts, or 53.5%, of that capacity. See 26 F.E.R.C. (CCH) at 65,109. In addition, LP & L pays for 44%, and NOPSI pays for 8%, of the System’s nuclear capacity costs, but receive only 1262 megawatts (or 32%), and 191 megawatts (or 5%), of nuclear capacity, respectively. See id. The reason for these differences is that AP & L’s nuclear capacity is made up of inexpensive ANO capacity as well as capacity from Grand Gulf; all other operating companies’ nuclear capacity is composed entirely of expensive Grand Gulf and Waterford III capacity.
In our opinion, the Commission acted within its discretion in ordering equalization of nuclear investment costs without equalization of nuclear capacity. The Commission’s allocation serves to restore a rough equalization of all System capacity costs among the operating companies. In view of the fact that such costs have never been precisely equalized on the System, FERC was required to do no more to remedy the undue discrimination it found. As the Commission emphasized on rehearing:
What our decision purports to do is to eliminate drastic rate disparities at the wholesale rate level which are associated with units used for the mutual benefit of all companies, and to do so in a manner which disturbs the historical operation of the System as little as possible, and which allows the individual companies to retain as fully as possible the benefits of units they have financed and constructed. In other words, we have sought to achieve an equitable balance between the interests of the individual companies and the System as a whole, consistent with the System Agreement.
32 F.E.R.C. (CCH) at 61,959 (emphasis added).
Petitioners’ argument is even less persuasive when it is recalled that these petitioners advocate adoption of Judge Head’s solution as just and reasonable. Judge Head’s solution was to allocate only the costs and capacity of Grand Gulf in proportion to each company's relative share of System demand, without regard to prior nuclear investment. But under this scheme, MP & L’s nuclear cost responsibility as a proportion of total System nuclear costs would still exceed its proportion of total System nuclear capacity. This is so because although AP & L would be allocated a greater share of Grand Gulf responsibility, it would still be able to reduce its average nuclear capacity costs, with capacity from its less expensive ANO units; MP & L’s nuclear capacity, though smaller, would still consist entirely of expensive Grand Gulf capacity. Petitioners’ simultaneous claims that FERC’s allocation must be rejected as unduly discriminatory because it mismatches nuclear costs and capacity and that an alternate allocation that also fails to match nuclear costs and capacity is just and reasonable reveals the real reason for their support of Judge Head’s solution. It is not that it resolves the flaws they see in the FERC allocation, but simply that it allocates them less Grand Gulf responsibility. Under these circumstances, the objection that the Commission mismatched costs and benefits rings rather hollow.
The City of New Orleans advances an additional reason why the Commission’s allocation should be considered unduly discriminatory: AP & L’s average cost for the nuclear energy produced by its capacity is 5.7 cents per kWh while the average cost of the nuclear energy produced by the other companies’ nuclear capacity is 15 cents per kWh. See New Orleans Pet.Br. at 35. The objection is apparently that the Commission failed to equalize the companies’ nuclear production costs and that this failure results in unduly discriminatory rates. Again, it is curious that this objection comes from a party that advocates adoption of Judge Head’s solution since that solution seeks only to equalize Grand Gulf capacity costs, not nuclear production costs. Nevertheless, the objection does not undermine FERC’s allocation.
The Commission’s decision sought only to remedy the drastic disparities in the costs of building the System’s nuclear capacity by roughly equalizing the investment cost of that capacity among the companies. That step was considered sufficient to restore rough equality among the companies’ overall capacity costs. Petitioner’s objection is that the Commission failed to equalize nuclear production costs — i.e., the costs of producing nuclear energy. There is no reason for the Commission to have focused on nuclear production costs rather than overall production costs. As previously discussed, only Grand Gulf energy is allocated with capacity. All other energy — whatever its source — is allocated pursuant to the 1982 System Agreement, with each company entitled to first call on its own lowest cost energy. Historically, and under the 1982 System Agreement, production costs have never been precisely equalized. These costs varied from company to company depending on each company’s fuel mix at any given time. AU Head reviewed the companies’ relative projected average annual production costs over a nine-year period under several alternative allocations. See 30 F.E.R.C. (CCH) at 65,156-57. For example, the nine-year average of production costs under the 1982 System Agreement as filed would be as follows:
AP & L — 7.47 cents/kWh
LP & L — 8.59 cents/kWh
MP & L — 11.00 cents/kWh
NOPSI — 11.65 cents/kWh
See id. at 65,157. The nine-year average under one of the production cost equalization proposals would be as follows:
AP & L — 8.82 cents/kWh
LP & L — 7.61 cents/kWh
MP & L — 9.46 cents/kWh
NOPSI — 8.96 cents/kWh
See id. Despite the production cost disparities under the 1982 System Agreement, Judge Head found no undue discrimination: “none of the differences brought out on the record are so compelling that they require the adoption of one form of production cost allocation.” Id. at 65,169. Accordingly, he approved the 1982 System Agreement as filed.
Like ALT Liebman, however, Judge Head found undue discrimination in the System’s allocation of capacity costs. Unlike Judge Liebman, however, Judge Head believed this discrimination could be remedied by equalizing the investment costs of Grand Gulf alone rather than all nuclear capacity on the System. See id. at 65,172. Moreover, Judge Head pointed out that allocating AP & L a share of Grand Gulf capacity and energy would also serve to reduce the production cost disparities identified under the 1982 System Agreement. See id. at 65,169.
In view of Judge Head’s above findings, affirmed and adopted by the Commission, see 31 F.E.R.C. (CCH) at 65,656, petitioner City of New Orleans’ suggestion that production cost disparities among the companies require reversal of FERC’s decision must be rejected. We affirm the finding by Judge Head and the Commission that production cost disparities under the 1982 System Agreement do not amount to undue discrimination. In deciding what discrimination is “undue,” the Commission necessarily possesses discretion and exercises judgment in light of the facts established by the record. In this case, Judge Head identified “a strong factual reason for not restructuring the system to meet the current [production] cost disparity problems”: “production cost equalization would be inconsistent with the history of intercompany transaction on the Middle South system.” 30 F.E.R.C. (CCH) at 65,170. Like Judge Head’s solution, the Commission’s decision alters the UPSA by allocating AP & L a share of Grand Gulf responsibility. Indeed, since the Commission’s decision allocates AP & L more Grand Gulf responsibility (36%), the former does even more than the latter to reduce the production cost disparities among AP & L and the other companies.
3. Participation Unit Concept
The remaining Mississippi petitioners— the Mississippi Public Service Commission, the Mississippi Attorney General, and the Mississippi Legal Services Coalition — raise many of the arguments relied on by the petitioners who support Judge Head’s solution. These petitioners, however, urge a return to the participation unit method of allocating the System’s excess capacity.
Like the other Mississippi parties, these petitioners argue that the Commission’s decision mismatches nuclear investment costs and benefits and irrationally increases MP & L’s Grand Gulf responsibility from 31.63% to 33%. We have already considered and rejected these arguments, see supra pp. 1560-62, and these petitioners’ contentions require only minimal additional discussion.
In objecting to the Commission’s decision to increase MP & L’s Grand Gulf responsibility, petitioners take issue with the Commission’s observation that the result of its decision “is that all three major geographical areas served by the MSU System will share similar Grand Gulf cost burdens: AP & L — 36%; MP & L — 33%; and LP & L/NOPSI — 33%.” 32 F.E.R.C. (CCH) at' 61,960. They claim that this “response” is “grossly inadequate” to explain why the Commission’s allocation to MP & L is just and reasonable while the UPSA’s slightly smaller allocation is not. See Brief of Petitioners, The Mississippi Public Service Commission, Edwin Lloyd Pittman, Attorney General for the State of Mississippi, and Mississippi Legal Services Coalition (“Mississippi Pet.Br.”) at 56. Rather than focusing on geographical areas, they assert, “one must look at the actual size of each company in order to assess the impact of the Grand Gulf allocation or cost burden on that company’s individual ratepayers.” Mississippi Pet.Br. at 60. This argument misunderstands the significance of the Commission’s observation. Contrary to petitioners’ suggestion, the Commission has not stated that any allocation that spreads costs proportionately over geographic regions is just and reasonable. By allocating nuclear investment costs according to relative demand, the Commission expressly recognized that Arkansas, Mississippi and Louisiana do not have equal loads. The Commission’s point is simply that its allocation, unlike the UPSA’s, requires Arkansas to bear a proportionate share of nuclear investment costs. It was the relative impact of the UPSA that FERC found unduly discriminatory. By requiring AP & L to share in the costs of Grand Gulf, the Commission could reasonably adopt an allocation that also slightly increased MP & L’s responsibility.
We also have little difficulty rejecting petitioners’ submission that “the participation unit concept utilized under the 1973 System Agreement is a concept for equalizing excess capacity which is ... just, reasonable, and not unduly discriminatory.” Mississippi Pet.Br. at 73. Under this proposal, the System would return to the 1973 System Agreement with MSE, the MSU subsidiary that owns Grand Gulf, as a party. Since MSE is not an operating company and has no demand, it will always be “long” on capacity, making Grand Gulf a participation unit. This means that the responsibility for Grand Gulf would be borne entirely by the “short” companies, shifting somewhat over time as the operating companies became more or less long or short.
Both Judge Liebman and Judge Head concluded that this proposal would be unduly discriminatory. See 30 F.E.R.C. (CCH) at 65,167; 26 F.E.R.C. (CCH) at 65,112. The Commission adopted and affirmed the findings of both judges on this point. See 31 F.E.R.C. (CCH) at 61,655-56. These findings are conclusively established by the record. Petitioners acknowledge that MP & L is currently a “long” company and expected to remain so for approximately ten years. This means that LP & L and NOPSI, the “short” companies, would bear almost all of the responsibility for Grand Gulf during this period. That the proposal would result in profound discrimination is most readily seen by observing its impact on LP & L. As discussed, Grand Gulf and Waterford III are unique on the System in that it is the dramatic cost escalations of these units that disrupted the System’s rough equalization of capacity costs among the operating companies. See 31 F.E.R.C. (CCH) at 61,654; supra pp. 1557-58. Already saddled with 100% of the costs of Waterford III, LP & L would be required under petitioners’ proposal to pay 90 to 100% of the costs of Grand Gulf over the next ten years. See 26 F.E.R.C. (CCH) at 65,112. As Judge Head recognized, the astronomical costs of Grand Gulf and Waterford III mean that these two units alone “will account for over 70% of the total system investment in production plant.” 30 F.E.R.C. (CCH) at 65,145. Requiring one company to bear virtually all of the costs of both units exaggerates rather than alleviates the undue discrimination found under the UPSA and 1982 System Agreement. The Commission properly rejected this proposal.
4. Production Cost Equalization
The Louisiana petitioners — the Louisiana Public Service Commission, the State of Louisiana, Occidental Chemical Corporation, Georgia Gulf Corporation, and Jefferson Parish, Louisiana — support the Commission’s finding of undue discrimination, but argue that some form of production cost equalization would be a more equitable and efficient remedy than the one ordered by the Commission. Petitioners’ main contention is that the Commission failed adequately to explain its decision not to order full production cost equalization. We find this contention without merit and hold that the Commission acted within its discretion in ordering a less intrusive means of remedying the undue discrimination found on the System.
Petitioners argue at length that, like the Commission’s remedy, “production cost equalization is also fully supported by the Commission’s conclusions of law and findings of fact, and that [the] latter alternative would more directly and more expeditiously achieve the objectives identified by the Commission as the basis for adopting nuclear investment equalization.” Initial Brief of Petitioners Occidental Chemical Corporation, Georgia Gulf Corporation, and Jefferson Parish, Louisiana (“Louisiana Parties’ Pet.Br.”) at 33; see Brief of the Louisiana Public Service Commission and the State of Louisiana, Petitioner and Intervenor (“Louisiana Pet.Br.”) at 44-47. Petitioners are surely correct in their assertion that production cost equalization would “virtually eliminate[ ] the possibility of serious future imbalances in generation cost responsibility among the operating companies.” Louisiana Parties’ Pet.Br. at 36. That, of course, is the nature of the remedy. But we have also concluded that the Commission’s chosen remedy is sufficient to remedy the undue discrimination on the System; that is, the Commission could properly conclude that the remaining cost disparities do not constitute unlawful discrimination. See supra pp. 79-83. The Louisiana parties do not seriously dispute this conclusion. See Louisiana Pet.Br. at 39. Rather, their argument is that production cost equalization would remedy System cost disparities even more effectively than nuclear investment cost equalization and that the Commission did not adequately justify its decision to reject the former and adopt the latter. See Louisiana Parties’ Pet.Br. at 42, 49.
In deciding whether to order production cost equalization or nuclear investment equalization, the Commission confronted a major policy choice. Though both alternatives would remedy undue discrimination, the former would represent a dramatic disruption of the System’s historical operations and of the states’ settled interests and expectations. Accordingly, FERC chose the latter alternative. We hold that the Commission’s decision was both rational and within its discretion.
Under the Louisiana Public Service Commission’s production cost equalization proposal, the investment costs of all System capacity would be combined and allocated among the operating companies according to each company’s capability responsibility — that proportion of System capacity equal to each company’s proportion of System demand. See 30 F.E.R.C. (CCH) at 65,141. In addition, a rate would be established to equalize cost per kWh of all energy produced by that capacity. Id. After reviewing the historical operation of the System, Judge Head concluded that “production cost pooling and equalization constitutes a drastic deviation from past practices on the system relating to intercompany transactions and would change the underlying nature of such transactions.” Id. at 65,168.
Never during the modern history of the system (1949 on) has there been any arrangement governing intercompany transactions where all the costs of the production plants of the operating companies have been combined and then allocated to the respective operating companies based on some capability responsibility formula.
Id. at 65,167. Rather, the operating companies have always been responsible for the costs associated with the plants they build and finance, costs that necessarily vary somewhat from company to company. In addition, the companies have always had first call on their own lowest cost energy in meeting their demand. The System agreements have sought simply to equalize the System’s excess energy and capacity among the companies. The result has been rough equalization of capacity and production costs.
Having found that “it is the large cost escalations of Grand Gulf and Waterford that have disrupted this pattern [of rough equalization],” 31 F.E.R.C. (CCH) at 61,654, the Commission properly decided to take only those steps that were necessary to compensate for this disruption. Those steps were to approve the 1982 System Agreement as filed and order nuclear capacity cost equalization. Production cost equalization would go much further and eliminate virtually all production and capacity cost disparities among the companies. Though we do not say that the Commission could not have ordered production cost equalization on this record, we think that the Commission correctly concluded that it was not necessary to remedy the undue discrimination found on the System. Recognizing that “[f]ull production cost equalization would be a substantial change from the allocation methodologies historically used on the MSU System,” 32 F.E. R.C. (CCH) at 61,961, the Commission explained that “the adopted allocation is an attempt to equalize the imbalance of cost on the System with the least disruption possible to the historical operation of the System.” Id.
Judge Head identified an additional “compelling” policy consideration against production cost equalization: “Federal regulation is meant to be supplemental to, not to supplant, State regulation.” 30 F.E.R.C. (CCH) at 65,170. Observing that “the practical effect of ordering production cost equalization would be to bind the local State commissions in many of their rate base determinations,” id., Judge Head concluded that the reasons favoring equalization “are not so compelling that they justify the extensive intrusion into an area normally subject to regulation by the State commissions.” Id. The Commission affirmed this conclusion, see 31 F.E.R.C. (CCH) at 61,656, and stated that its decision seeks “to alter in as limited a means as possible the agreed-upon cost scheme, in order to achieve just, reasonable, non-discriminatory and nonpreferential rates.” 32 F.E.R.C. (CCH) at 61,961. Having determined that production cost equalization was not necessary to achieve lawful rates, the Commission properly considered the historical operation of the System as well as the regulatory interests of the states in exercising its discretion not to order such equalization. Cf. Nantahala Power & Light Co. v. FERC, 727 F.2d at 1348 (“A decision to order roll-in is essentially a matter of Commission discretion....”).
* * * * * *
We have now considered petitioners’ numerous arguments against the Commission’s decision and in favor of various alternate allocations. We find these arguments unpersuasive and hold that the Commission acted within its authority to remedy undue discrimination and that its decision was rational. We also have considered all other arguments suggesting that the Commission acted improperly and find them to be without merit.
D.
In this section, we consider two remaining claims: that Commissioner Richard improperly failed to recuse himself and that the Commission abused its discretion in failing to reopen and update the record.
1. Recusal
Several of the Mississippi parties assert that “[t]he failure of Commissioner Oliver G. Richard, III to recuse himself in this case was error.” Mississippi Pet.Br. at 71. Their claim is that Commissioner Richard’s past association with Senator J. Bennett Johnston of Louisiana — an intervenor below as a member of the full Louisiana congressional delegation — “created the appearance of bias and impropriety sufficient to compel the Commissioner’s recusal.” Mississippi Pet.Br. at 72. Like Commissioner Richard and the Commission, we find petitioners’ claim to be without merit.
Recusal is required only when the actions of a decisionmaker lead one to conclude that he has prejudged the case. See Cinderella Career & Finishing Schools, Inc. v. FTC, 425 F.2d 583, 591 (D.C.Cir.1970). Petitioners themselves acknowledge that recusal decisions are subject to a very deferential, abuse of discretion standard of review. See Mississippi Pet.Br. at 72 (citing Davis v. Board of School Comm’rs of Mobile County, 517 F.2d 1044 (5th Cir.1975)). Under this standard, it is clear that Commissioner Richard acted properly.
Commissioner Richard worked for Senator Johnston from 1977 to 1981 as a legislative assistant dealing with energy issues. This fact alone does not suggest bias. As Commissioner Richard observed, “my employment with the Senator ended ... almost one year before the Middle South proceedings began. I had no prior contact with the facts or legal issues involved in Middle South before joining the Commission in 1982.” 31 F.E.R.C. (CCH) at 61,671. Petitioners do not dispute these facts. Rather, they claim that Commissioner Richard abused his discretion by “neglectpng] to follow FERC’s own Administrative Rules.” Mississippi Pet.Br. at 72 (citing 18 C.F.R. § 385.504(c)(1), (2)). We disagree.
First, these rules do not apply to the Commissioners; they are directed only to presiding officers at hearings ordered by the Commission. Second, even if applicable, the rules would not support petitioners’ claims. They provide simply that a presiding officer who believes himself to be “disqualified” may withdraw from a hearing, see 18 C.F.R. § 385.504(c)(1), and that the Commission may order recusal “upon good cause,” see id. § 385.504(c)(2).
2. Reopening the Record
The Louisiana petitioners assert that the Commission arbitrarily and capriciously refused to reopen the record to update the cost estimates of Grand Gulf and Waterford III. We find petitioners’ arguments unavailing and hold that the Commission acted within its discretion in deciding not to reopen the record.
In ICC v. Jersey City, 322 U.S. 503, 64 S.Ct. 1129, 88 L.Ed. 1420 (1944), the Supreme Court established the general rule that federal courts should be extremely reluctant to require an agency to reopen a record on the ground that the evidence has become stale. Id. at 514, 64 S.Ct. at 1134. Indeed, the question is often “entrusted to agency discretion.” See Delta Air Lines v. CAB, 561 F.2d 293, 307 (D.C.Cir.1977), cert. denied, 434 U.S. 1045, 98 S.Ct. 889, 54 L.Ed.2d 796 (1978); accord Bowman Transp. v. Arkansas-Best Freight Sys., 419 U.S. 281, 95 S.Ct. 438, 42 L.Ed.2d 447 (1974). As a general rule, this court has found that a remand may be necessary “where there has been a change in circumstances ... that is not merely ‘material’ but rises to the level of a change in ‘core’ circumstances, the kind of change that goes to the very heart of the case.” Greater Boston Television Corp. v. FCC, 463 F.2d 268, 283 (D.C.Cir.1971), cert. denied, 406 U.S. 950, 92 S.Ct. 2042, 32 L.Ed.2d 338 (1972). We cannot conclude that the circumstances cited by petitioners evidence a change which goes “to the heart of the case” or that they represent a change in the “core circumstances.”
In this case, the Commission adopted Judge Liebman’s remedy, which relied on the cost data in the record developed before him. In rejecting the Louisiana parties’ request to reopen the record, the Commission stated: “Because cost estimates for these units have been continually changing and because the costs as well as demand projections in ER82-616 were reasonable when made and were subject to cross-examination, we find it appropriate to adopt Judge Liebman’s recommendation without modification at this time.” 31 F.E. R.C. (CCH) at 61,657. The Commission took the same position on rehearing, stating that “it is necessary to use some fixed point in time in order to provide finality to a proceeding, rather than continuously updating or using spot adjustments.” 32 F.E.R.C. (CCH) at 61,961.
Petitioners argue that the Commission should have reopened the record on rehearing because by that time final cost figures were available for both Grand Gulf and Waterford III. Use of these costs, they argue, would have better served the interests of finality. But, updating the record would not have been as effortless as petitioners suggest. First, the intervening increase in costs cited by petitioners has never been subject to cross-examination, and AP & L, at least, suggests that the amount is subject to dispute. See Brief of Arkansas Power & Light Company as Intervenor at 28 n. 23. Moreover, AP & L claims that the intervening improvements it has made to ANO I and II by order of the NRC would also have to be considered in any recalculation based on updated costs. Second, the Commission could not merely update cost figures; demand projections would have to be revised as well since both are necessary to properly equalize nuclear capacity costs. Thus, we cannot agree with petitioners that finality could have been better served by reopening the record. The potential delay involved might have been seriously detrimental since Grand Gulf was about to become operational and the matter had to be resolved.
Petitioners make much of the fact that the Commission considered extra-record evidence to increase the rate of return on equity it allowed MSU. “Given its willingness to consider post-record evidence in adjusting the rate of return, to benefit the utility, the FERC should have taken similar action to avoid discrimination among consumers.” Louisiana Pet.Br. at 44. Petitioners’ claim is unpersuasive. Setting rates of return is a completely different undertaking from allocating costs. See Illinois Power Co., 15 F.E.R.C. (CCH) ¶ 61,650 (1981). In the case of the former, the Commission frequently adjusts the return upward when warranted by changing circumstances in the financial markets after the close of the record since such information is not typically subject to dispute. As discussed, cost allocation involves information of a quite different character. Thus, we must conclude that petitioners have fallen “far short of demonstrating ‘the most extraordinary circumstances’ necessary to justify compelling the agency to reopen the record.” Nantahala Power & Light Co. v. FERC, 727 F.2d at 1352 (quoting Bowman, 419 U.S. at 296, 95 S.Ct. at 447).
For all of the foregoing reasons, the Commission’s decision is
Affirmed.
. Middle South Energy, Inc. and Middle South Services, Inc., 31 FERC ¶ 61,305 (1985), and Middle South Energy, Inc. and Middle South Services, Inc., 32 FERC ¶ 61,425 (1985) (opinion on rehearing).
. MSU also owns a corporate services company, Middle South Services, Inc., and a fuel purchasing company, System Fuel, Inc. See Middle South Services, Inc., ER82-483-000, 30 FERC ¶ 63,030, 65,141-42 (1985).
One useful way of viewing the relative size of the companies is to compare their relative shares of the system’s average demand:
Share of Total System Load
LP&L 44%
AP&L 33%
MP&L 15%
NOPSI 8%
See Middle South Energy, Inc., ER82-616-000, 26 FERC ¶ 63,044, 65,109 (1984). These figures are based on average load demand in 1982.
. Citations to the record in Middle South Services, Inc., ER82-483-000, 30 FERC ¶ 63,030 (1985), are noted as “483-R." Citations to the record in Middle South Energy, Inc., ER82-616000, 26 FERC ¶ 63,044 (1984), are noted as "616-R.”
. Specifically, ALJ Head found:
Article III of the Agreement provides, inter alia, for planning, construction and operation of both power supply and related facilities on a coordinated basis (Section 3.02); for moving toward a new fuel base of coal and nuclear to minimize costs and reduce dependence on gas and oil (Section 3.03); for a long-term goal of each company having a proportionate share of coal and nuclear units available to serve its customers * * *; and for joint planning on a system-wide basis for construction and operation of major facilities to achieve economies of scale associated with construction and operation of larger generating units * * * (Section 3.08).
30 FERC at 65,122.
. Thus under § 5.06(c) of the 1982 System Agreement the Operating Committee is responsible for, inter alia, determining the amount of reserve capacity on the system and requiring the installation of that capacity. See 483-R. 7130, VII JA 1582.
. For example, in the 1960’s and 1970’s AP & L almost never had enough capacity to service its native load, and frequently drew on LP & L's capacity to make up the deficiency. 26 FERC at 65,098-99.
. All energy on the system is dispatched from a central office in Pine Bluff, Arkansas. 30 FERC at 65,142. The System Agreement establishes a schedule called MSS-3 setting rates for the purchase of energy from the system pool. When a company needs energy it is billed for the lowest cost energy available in the pool. Companies owning the capacity that generates such low cost energy have first claim to that energy. 483-R. 7151, VII JA 1603. When a company needs more energy than its native capacity can produce it therefore must stand in line behind the other companies for access to the relatively cheapest kilowatts.
. The terms "long" and “short” do not refer to a company’s ability to provide enough energy to meet its customers' requirements. Instead, they reflect a comparison of the share of system capacity contributed by a particular company with the share of the system’s energy utilized by that company. It is entirely possible that a company could be “short" and still have more than enough capacity to meet its own needs. 26 FERC at 65,099.
. Specifically, the 1951 System Agreement provided for a monthly payment of $1.10 per kilowatt by which a company was “short.” See 483-R. 7398, VII JA 1786.
. This approach also provided for the “short" company receiving an entitlement to a proportionate share of the energy generated by the "participation unit." 26 FERC at 65,099.
. See also 30 FERC at 65,143-44 (indicating that the units added in the 1960’s and early 1970’s were priced between $58 and $97 per kilowatt).
. AU Liebman also credited testimony indicating that two other factors promoted equalization of overall generation costs. First, responsibility for adding new capacity generally rotated among the operating companies, evening out investment costs over time. Second, the burden borne by companies adding relatively more expensive new capacity was often offset by the lower fuel costs associated with such units. See 26 FERC at 65,100.
. Capacity cost of ANO 1 was $276 per kilowatt, nearly double that of the oil-fired units introduced by MP & L and LP & L during the same period. 26 FERC at 65,101; 30 FERC at 65,144.
. 30 FERC at 65,144. The initial cost was about 3 cents per kilowatt hour. 26 FERC at 65,101.
. Nor did this basic pattern change substantially with the introduction of ANO 2 in 1980. Although ANO 2 had cost substantially more per kilowatt than did ANO 1, AP & L’s total nuclear capacity is still quite reasonably priced at $500 per kilowatt or 3-4 cents per kilowatt hour. See 30 FERC at 65,145.
. Grand Gulf, for example, was originally projected to come on line at a cost of approximately $500 per kilowatt, a price comparable to that of the average price per kilowatt of the two ANO units. 26 FERC at 65,103.
. This figure was presented in the Commission’s initial opinion. 31 FERC at 61,632. In determining the allocation of Grand Gulf capacity the Commission adopted the figures used by AU Liebman in his initial decision. Id. at 61,-657. ALJ Liebman relied on the following cost estimates: $2.5 billion for Grand Gulf 1 and $2.4 billion for Waterford 3. See 26 FERC at 65,107. These figures represent the cost of these units as of December 31, 1981, rather than on the date of commercial operation (which was several years later). Thus AU Liebman conceded that the projected cost of Grand Gulf 1, as of 1984, was $2.8 billion. See id.
AU Head relied on a different, higher, and presumably more recent, set of figures. His conclusion that the new nuclear units would cost approximately $2,500 per kilowatt, 30 FERC at 65,121, was based on the testimony offered by Mr. Louiselle, a witness for LPSC, who, in the portion of the transcript cited by the AU, assumed that MSE’s 90% share of Grand Gulf 1 would cost $2.92 billion and Waterford 3 would cost about $2.76 billion. See 483-R. 4124-26, VI JA 1452.
. AU Head estimated that Grand Gulf 1 and Waterford 3 would come on line at a cost of $2,500 per kilowatt. By contrast, he found that the two ANO units came on line at a cost of about $500 per kilowatt. 30 FERC at 65,121. AU Liebman estimated that Grand Gulf 1 would come on line at a cost three to four times greater than that of any unit already on the MSU system. Id. at 65,103.
. On the other hand, the new agreement did not provide for an entitlement to the "intermediate" kilowatts of energy produced by the long company. Thus the short company might still have to purchase expensive nuclear energy whenever it lacked the capacity to meet its native load. 30 FERC at 65,140.
. Moreover, the new equalization scheme actually made matters worse for any company that was both long and retained substantial responsibility for one of the new plants.
. Indeed, as AU Head observed, the entire MSU system now has much more capacity than it needs. 30 FERC at 65,169.
. MSU, however, did halt construction of the second unit in the project, Grand Gulf 2. 31 FERC at 61,668 n. 2. The Commission therefore did not decide on the allocation of Grand Gulf 2 costs, finding that issue to be purely speculative at this time. Id. at 61,669 n. 20.
. This assumption is now questionable. Through the 1990’s Grand Gulf will not produce energy that is cheaper than energy produced from alternative sources. Indeed, AU Liebman estimated that by 1993 ratepayers will pay $3 billion more for Grand Gulf energy than they would for energy from comparable sources. As of 1984 MSU was still predicting that Grand Gulf power would become economical at some future date and that at some (even later) point the project will represent a net benefit to consumers. 26 FERC at 65,103. As AU Liebman noted, however, the decline in the price of oil makes these projections appear rather dubious. Id.
. Grand Gulf is located in Port Gibson, Mississippi. Under the original plan each operating company in the system would be responsible for the financing and construction of a major nuclear facility. It was soon determined, however, that the site for the NOPSI plant near New Orleans was unsuitable; that unit was transferred to Mississippi. Responsibility for construction of both units shifted to MP & L. 26 FERC at 65,102.
. In 1979 the Operating Committee of the MSU system recommended “Plan 4A” under which the operating companies would have the following responsibilities:
Company Percentage
AP&L 11.11
LP&L 13.51
MP&L 49.60
NOPSI 25.78
26 FERC at 65,102. Although "Plan 4A” was tentatively approved by the MSU Board of Directors in November of 1979, the Board soon retreated from this position and, in January of 1980, approved an allocation plan quite similar to the UPSA. Id. at 65,103.
. In 1981 AP & L’s share of Grand Gulf power under the Availability Agreement was calculated to be 17.1%, with LP & L responsible for 26.9%, MP & L responsible for 31.3%, and NOPSI responsible for 24.7%. 26 FERC at 65,102.
. UPSA assigns LP & L the entitlement to purchase 38.57% of the power available to MSE from Grand Gulf, MP & L 31.63%, and NOPSI 29.80%. 26 FERC at 65,097 (excluding Unit 2 percentages). MSE only owns 90% of Grand Gulf; 10% has been sold to South Mississippi Electric Power Association. Id. These figures therefore only refer to percentages of MSE’s share of the Grand Gulf facility.
. By order issued August 25, 1982 the Commission accepted the UPSA for filing but found that it constituted a rate change rather than an initial rate filing; FERC therefore suspended the rates which were to become effective under the UPSA, subject to refund. See Middle South Energy, Inc., 20 FERC ¶ 61,206 (1982). On May 24, 1983 the Commission recharacterized the UPSA as an initial rate, but held that it had the authority to suspend initial rates. Middle South Energy, Inc., 23 FERC ¶ 61,277 (1983). In Middle South Energy, Inc. v. FERC, 747 F.2d 763, 772 (D.C.Cir.1984), this court reversed the Commission, holding that the Federal Power Act only permits suspension of changed rates.
On remand FERC determined that the Sales Agreement rates were changed rates after all, giving it authority to suspend them subject to refund. That decision was appealed to this court, but the appeal has been held in abeyance pending the outcome of this case. See Arkansas Power & Light Co. v. FERC, No. 85-1504 (D.C.Cir., filed Aug. 14, 1985). As matters stand, the rates filed in the UPSA were never suspended because FERC issued its final decision in Order No. 234, amending the UPSA, before service from Grand Gulf commenced. As we uphold FERC’s decision here, the question whether the rates filed in the UPSA are subject to the suspension power of the Commission is now moot.
. ALJ Liebman, ALJ Head, and the Commission all addressed myriad issues that are not presented in the petitions before this court. These issues are not discussed in this opinion.
. He rejected, inter alia, the following arguments: (1) the reallocation of Grand Gulf costs violated the Mobile-Sierra doctrine, 26 FERC at 65,113-16; (2) the reallocation constituted a forced purchase of power barred by the Act, id. at 65,115-17; and (3) the PUHCA gives the Securities and Exchange Commission primary authority over the allocation of Grand Gulf costs, id. at 65,117.
. Section 205(b), 16 U.S.C. § 824d(b) (1982), similarly bars any "undue preference" in wholesale rates.
. This proposal was put forth by the Mississippi Public Service Commission.
. This proposal was put forward by the City of New Orleans. On appeal CNO has abandoned this view and adopted that of ALJ Head, i.e., the allocation of Grand Gulf capacity alone — and not that of all nuclear plants — but calculating that allocation on the basis of each company’s relative demand for system load in any particular year. See Brief of Petitioner City of New Orleans, Louisiana at 48.
. This proposal was originally put forward by the Louisiana Public Service Commission and Occidental Chemical Corporation. As the Commission suggested, this alternative can be broken down into the following three-step process:
(1) Calculating each company’s nuclear responsibility ratio. This ratio consists of each operating company’s 1982 share of the system’s total demand over the entire system's demand.
(2) Calculating each company’s share of total system nuclear investment. This figure is derived from multiplying the total system investment in nuclear power by a company’s nuclear responsibility ratio.
(3) Calculating each company’s share of Grand Gulf costs. This amount equals the shortfall between the operating company’s proportionate share of nuclear costs (estimated in step 2) and that company's own nuclear investment.
Each company would then receive an entitlement to Grand Gulf power corresponding to its relative contribution to Grand Gulf investment costs. 30 FERC at 61,655.
. "Base load” units are those units that are in continuous operation. By contrast, reserve units (oil and gas units) can be fired up quickly to meet special surges in demand. 483-R. 7112, VII JA 1564.
. In this context “equalization” does not mean that each operating company would pay the same absolute number of dollars. Rather, it means that each operating company would have to pay a share proportionate to its share of system demand.
. He rejected the following contentions: (1) that a reallocation of Grand Gulf costs violates the Mobile-Sierra doctrine, 30 FERC at 65,146-47; (2) that such a reallocation violates the ban on federal regulation of “generating” facilities contained in § 201(b) of the FPA, 16 U.S.C. § 824(b) (1982), 30 FERC at 65,148-50; (3) that such a reallocation constitutes a “forced sale” of power, barred by § 202(b) of the FPA, 16 U.S.C. § 824a(b) (1982), 30 FERC at 65,154; (4) that such a reallocation expands federal regulation of a utility’s rate base in a manner that improperly limits the power of the states over retail rates, 30 FERC at 65,149-51; (5) that the Public Utility Holding Company Act, 15 U.S.C. § 79 et seq. (1982), bars FERC jurisdiction in this matter, 30 FERC at 65,152-54; and (6) that the reallocation of Grand Gulf costs by FERC would present an obstacle to state certification of new generating plants. 30 FERC at 65,154.
. 30 FERC at 65,139. This proposal was supported by AP & L and various Arkansas interests in the proceedings before AU Head. The Arkansas parties continue to press this position on appeal.
. There were two variations on this theme:
(a) Base load equalization. This proposal would have required each operating company to bear a share of the system’s “base load” (coal and nuclear) capacity proportionate to its share of system load. 30 FERC at 65,140. This proposal was supported by the Commission staff in the proceedings before AU Head and was before the Commission. 31 FERC at 61,635 & n. 5. No party, however, has pressed this position on appeal.
(b) Base load equalization combined with rough equalization of intermediate capacity. This proposal would require base load capacity to be allocated in proportion to relative system demand while all other capacity would be equalized under the terms of the 1982 System Agreement, i.e., short companies would compensate long companies, with equalization payments pegged to the cost of the long companies’ intermediate (oil and gas) units. 30 FERC at 65,141. This proposál was put forward by the City of New Orleans before AU Head and the Commission. 31 FERC at 65,635 & n. 6. It is not pressed on appeal.
. 30 FERC at 65,141. This proposal was put forward by the Louisiana Public Service Commission. It continues to. press this position on appeal.
. 30 FERC at 65,141. This proposal was put forward by the Mississippi Public Service Commission. MPSC continues to press this position on appeal.
. Even AU Head conceded, however, that all of the operating companies would benefit from the economies of scale realized when an individual company built a plant providing more capacity than that company could absorb at the time. Moreover, he found that MSU was a "highly integrated system” which sought to achieve such economies of scale through "common planning.” 30 FERC at 65,168.
. Specifically, AU Head was impressed by the following facts: (1) the Grand Gulf project was an amalgam of the nuclear units assigned to MP & L and NOPSI; (2) the plant was planned on the basis of the combined load forecasts of all of the operating companies; (3) it was clear all along that the facility would produce much more energy than MP & L could ever use; and (4) the Atomic Energy Commission approved the Grand Gulf license because the entire system had placed its credit behind MSE. 30 FERC at 65,170-71.
. FERC reviewed both AUs’ decisions in issuing Order No. 234, even though it had previously declined to consolidate the two cases. See 21 FERC ¶ 63,039 (1982), aff’d, 22 FERC ¶ 63,015 (1983).
. The Commission rejected the jurisdiction arguments AU Head had considered in the System Agreement case, see note 37 supra, with the exception of the state certification challenge.
. The 1973 System Agreement had stated that the Operating Committee “assigns” responsibility for new generating units to particular operating companies; the 1982 System Agreement does not use the word "assigns.” Notwithstanding this change, the Commission found the 1982 Agreement to vest the same authority in the Operating Committee over allocation of responsibility for generating units as had existed in previous System Agreements. 31 FERC at 61,646.
. The Commission also noted that changes in the 1982 Agreement had enhanced the power of the Operating Committee to override the wishes of an individual operating company by providing for majority rule rather than a two-thirds vote. This provision made it impossible for a single company to block a Committee decision. 31 FERC at 61,651.
. The Commission declined to update the cost estimates for the Grand Gulf and Waterford 3 units, stating that both the cost and pertinent demand projections were constantly changing. 30 FERC at 61,657.
. In its initial decision the Commission did not expressly discuss the rationality of the alternatives to ALJ Liebman’s approach presented in the record of ER-483. It implicitly addressed these concerns by adopting the AU’s analysis. 31 FERC at 61,655.
. FERC also disputed AP & L’s contention that at least on one occasion an operating company had refused to build a unit despite a “recommendation” by the Operating Committee that it do so. FERC noted that although it was true that LP & L had never built coal units in northern Louisiana in the early 1980's, there was no record evidence suggesting actual defiance of the Operating Committee. 32 FERC at 61,953-54.
. 16 U.S.C. §§ 824 et seq. (1982).
. Id. § 824. The states retain jurisdiction over retail rates.
. Id. § 824(b).
. 16 U.S.C. § 824d(a) (1982). Section 205(b), 16 U.S.C. § 824d(b) (1982), further provides that no public utility shall, with respect to any jurisdictional sale, "maintain any unreasonable difference in rates, charges, service, facilities, or in any other respect, ... between localities____"
. Id. § 824e(a) (emphasis supplied).
. 32 FERC f 61,425, at 61,949-50 (quoting 31 FERC ¶ 61,304, at 61,627 (1985) (Order on remand)).
. The Commission explained the effect of the intersection of the UPSA and the 1982 System Agreement as follows:
The impact of these Grand Gulf allotments (or any other Grand Gulf allotments) on reserve equalization under Service Schedule MSS-l of the 1982 System Agreement will likely be a change in the shortness or longness of each member. For example, when Grand Gulf 1 becomes commercially operable, to the extent that the fixed Grand Gulf allotment ratio exceeds (or is exceeded by) the monthly 1982 System Agreement responsibility ratio for a given pool member, that member will become either more long (or short) or less long (or short) for pool reserve equalization purposes. The excess capacity of the long members will be equalized in accordance with the 1982 Agreement, i.e., to the extent a member having excess capacity cannot reach voluntary agreements to sell its excess capacity and energy under Service Schedule MSS-4 (Unit Power Purchase), its excess capacity will be equalized among the short members based on the costs of the long member's intermediate generating units under Service Schedule MSS-l (Reserve Equalization). Any excess energy will be shared with the pool under Service Schedule MSS-3 (Exchange of Electric Energy Among the Companies).
31 FERC ¶ 61,305, at 61,656.
. 734 F.2d 1286 (8th Cir.1984).
. Id. at 1287.
. Id. at 1288.
. Id. at 1289.
. In South Dakota Public Utilities Comm'n v. FERC, 690 F.2d 674 (8th Cir.1982), a case also involving the NSP Companies, an amendment to the Coordinating Agreement allocated costs arising from the cancellation of a system nuclear plant project in Wisconsin. The court upheld FERC’s decision that the NSP Companies would share the cancellation costs on the basis of a pre-existing arrangement equalizing generating costs in the Coordinating Agreement and quoted with approval the following language from the FERC order:
The Amendment to the Coordinating Agreement of Northern States Power Company (Minnesota) and Northern Power Company (Wisconsin) filed with the Commission ... is just and reasonable. It is approved as a rate schedule change pursuant to § 205 of the Federal Power Act subject to the modification ordered in Paragraph (B) below.
Id. at 677. It is noteworthy that no question was raised as to the Commission’s jurisdiction to review this amendment to the Coordinating Agreement.
. — U.S. -, 106 S.Ct. 2349, 90 L.Ed.2d 943 (1986).
. Id. at -, 106 S.Ct. at 2354.
. Id. at -, 106 S.Ct. at 2359.
. 16 U.S.C. § 824(b) (1982) (emphasis supplied).
. Id. (emphasis supplied).
. H.R.Rep. No. 1903, 74th Cong., 1st Sess. 74 (1935).
. See § 201(b)(1) of the FPA, 16 U.S.C. § 824 (1982).
. 32 FERC ¶ 61,425, at 61,947.
. See 26 FERC ¶ 63,044, at 65,113-14.
. 324 U.S. 515, 65 S.Ct. 749, 89 L.Ed.2d 1150 (1945).
. 324 U.S. at 528 n. 6, 65 S.Ct. at 755 n. 6. (The Court rejected the holding of a previous circuit decision in Hartford Electric Co. v. FPC, 131 F.2d 953 (2d Cir.1942), cert. denied, 319 U.S. 741, 63 S.Ct. 1028, 87 L.Ed. 1698 (1943), but cited with approval the alternative rationale for that decision.)
. The Arkansas-Missouri petitioners also cite cases prohibiting FERC from ordering the wheeling of power, Florida Power & Light Co. v. FERC, 660 F.2d 668 (5th Cir.1981), cert. denied, 459 U.S. 1156, 103 S.Ct. 800, 74 L.Ed.2d 1003 (1983); New York State Electric & Gas Corp. v. FERC, 638 F.2d 388 (2d Cir.1980), cert. denied, 454 U.S. 821, 102 S.Ct. 105, 70 L.Ed.2d 93 (1981); Richmond Power & Light v. FERC, 574 F.2d 610 (D.C.Cir.1978), or the modification of retail rates, FPC v. Conway Corp., 426 U.S. 271, 276-77, 96 S.Ct. 1999, 2003, 48 L.Ed.2d 626 (1976). They maintain that these cases demonstrate that even where the FPA grants power— such as the power over interstate wholesale sales of electric energy — "that grant must be reconciled with [the Act’s] limitations on power, such as ... the lack of jurisdiction over generating facilities.” Arkansas Public Service Commission ("APSC”) Brief at 28. These cases are inapposite here because, under the clear terms of the statute, the Commission has been awarded jurisdiction over generating facilities “to the extent provided in other sections,” including jurisdiction necessary to effectuate regulation of interstate wholesale rates.
. 31 FERC ¶ 61,305, at 61,643. The Commission suggests upon reconsideration that its authority is unchanged whether "the central issue is viewed as one of cost allocation or as ‘forced’ purchases.” 32 FERC ¶ 61,425, at 61,949. We do not interpret this comment as an assertion by FERC that it may, under any circumstances, force a purchase among nonaffiliates.
. 343 U.S. 414, 72 S.Ct. 843, 96 L.Ed. 1042 (1952). See also discussion of Nantahala Power & Light, supra text at notes 63-65.
. Id. at 422-23, 72 S.Ct. at 847. The Court specifically noted that the Commission’s order was based on authority derived from section 206 of the FPA, and not from the underlying contract between the parties. Id. at 422, 72 S.Ct. at 847.
. 606 F.2d 1156 (D.C.Cir.1979).
. Id. at 1167 (quoting with approval the Decision of the Commission).
. Id. at 1167 n. 33.
. Id. at 1168 (emphasis supplied).
. 20 FERC ¶ 61,332 (1982).
. 473 F.2d 1253 (8th Cir.1973).
. 273 U.S. 83, 47 S.Ct. 294, 71 L.Ed. 54 (1927).
. FPC v. Southern California Edison Co., 376 U.S. 205, 215-16, 84 S.Ct. 644, 651, 11 L.Ed.2d 638 (1964).
. 461 U.S. 190, 103 S.Ct. 1713, 75 L.Ed.2d 752 (1983).
. Id. at 205-06, 103 S.Ct. at 1723. The Arkansas parties accuse FERC of contravening the Supreme Court’s decision in Arkansas Electric Cooperative Corp. v. APSC, 461 U.S. 375, 103 S.Ct. 1905, 76 L.Ed.2d 1 (1983). In that case, the Court upheld state jurisdiction over the wholesale rates of a rural power cooperative, in part because the FPC had previously determined that it lacked jurisdiction to regulate these entities which fall under the supervision of the Rural Electrification Administration. The Court, therefore, rejected the old “bright line" between state and federal jurisdiction, i.e., the distinction drawn between regulation of retail or wholesale rates under the commerce clause. Simultaneously, however, the Court emphasized that a new "bright line” between state and federal jurisdiction had been drawn by Congress in the FPA. We hold that the Commission’s actions fall within a domain assigned to federal control by the FPA.
Petitioner Arkansas Industries accuses FERC of concluding that federal and state jurisdictions are overlapping and of performing a balancing of the relevant federal and state interests under the commerce clause — a course of action eschewed by the "bright line” test as articulated in Arkansas Electric — in its decision to allocate Grand Gulf. As detailed above, we have decided that FERC’s allocation of Grand Gulf costs is within its exclusive authority over wholesale rates in interstate commerce under the FPA. The Commission’s explicit sensitivity to state concerns in determining the extent to which it would exercise its authority to remedy the unlawfulness of the UPSA is not equivalent to an inquiry under the commerce clause to determine whether a state may regulate in this realm.
. Nantahala Power & Light Co. v. Thornburg, — U.S. at -, 106 S.Ct. at 2357.
. Id.
. In Northern States Power Co. v. Minnesota Public Utilities Comm'n, 344 N.W.2d 374 (Minn.), cert. denied, 467 U.S. 1256, 104 S.Ct. 3546, 82 L.Ed.2d 850 (1984), and Northern States Power Co. v. Hagen, 314 N.W.2d 32 (N.D.1981), two state supreme courts determined that their respective state regulatory commissions had to accept and collect the allocated costs of an abandoned nuclear plant project in the retail rates charged for NSP Company power. We endorse the state courts’ conclusion that FERC had authority to approve or reject the cost allocation.
. 30 FERC ¶ 63,030, at 65,151.
. Western Massachusetts Electric Co., 23 FERC ¶ 61,025, at 61,064 (1983). Most recently, the Eighth Circuit spoke to a similar question in the same factual context involved in the instant case. In Middle South Energy, Inc. v. APSC, 593 F.Supp. 363 (E.D.Ark.1984), aff'd, 772 F.2d 404 (8th Cir.1985), cert. denied, — U.S. -, 106 S.Ct. 884, 88 L.Ed.2d 919 (1986), the APSC sought to require AP & L to show cause why the UPSA and the other Grand Gulf allocation agreements were not void ab initio because the utility had failed to obtain the APSC's prior approval. The district court enjoined the inquiry, holding that it constituted a collateral challenge to the FERC proceedings and an intrusion into a preempted area. On appeal, the Eighth Circuit affirmed, but rested its decision on an alternative finding that APSC's inquiry was an unwarranted burden on interstate commerce. The Eighth Circuit’s characterization of APSC’s purpose is instructive and highlights the merit of federal regulation in the present case:
The APSC seeks to cancel the Grand Gulf agreements ostensibly because they have not received the necessary state regulatory approval. Its apparent concern, which has been made abundantly plain in its orders and its arguments before the SEC and FERC, however, is the economic impact on Arkansas citizens caused by AP & L’s participation in Grand Gulf. It seeks to deflect what it has estimated to be rate increases of more than $3.5 billion over the next ten years. Given free rein, the APSC would shift this burden to the citizens of Mississippi and Louisiana, citizens who are powerless to directly influence Arkansas’ internal affairs.
772 F.2d at 416-17 (footnote omitted).
. The Arkansas-Missouri petitioners further maintain that FERC’s orders usurp state jurisdiction by imposing costs on AP & L for capacity it does not need. This argument appears ludicrous in light of the integrated planning and construction of generating capacity on a system-wide basis. Moreover, none of the operating companies seek Grand Gulf capacity at the present time.
Equally fallacious is the APSC’s argument that FERC’s orders have unlawfully ”remove[d] low cost facilities from AP & L by forcing a sale from those facilities to consumers in Louisiana and Mississippi.” APSC Brief at 41. The reallocation of Grand Gulf simply adjusts AP & L’s share of MSU’s generation capacity costs — costs incurred jointly by the system.
APSC also asserts that it issued certifications for Arkansas’ nuclear and coal plants based upon its perception of the needs of AP & L’s customers and that it carefully supervised construction of these plants to insure low costs. Hence, the state regulatory authority contends that it would be unfair to impose upon Arkansas generating capacity not subject to similar prior scrutiny. This argument, too, fails; AP & L’s supporters are not free to ignore the historical integration of the MSU system and AP & L’s continuous involvement and responsibility in planning generation capacity for that system.
. 30 FERC ¶ 63,030, at 65,166, cited in 31 FERC ¶ 61,305, at 61,645.
. 26 FERC ¶ 63,044, at 65,111-12. See also 30 FERC ¶ 63,030, at 65,166, cited in 31 FERC ¶ 61,305, at 61,645.
. 15 U.S.C. §§ 79 et seq. (1982).
. See 16 U.S.C. § 825q (1982).
. In the Matter of Middle South Utilities, Inc., Middle South Energy, Inc., SEC PUHCA Release No. 23,579, 32 SEC Docket 416, 419 n. 15 (Jan. 23, 1985) (Memorandum Opinion and Order Authorizing Common Stock Sale and Acquisition and Denying Request for Hearing) (emphasis supplied).
. The SEC has also observed that
[t]he operating subsidiaries in the Middle South system have been an integrated system since 1930. As an integrated system, the operating companies have been parties to a series of system agreements governing intercompany sales of electric energy, as well as the planning, construction and operation of generation and transmission facilities. These agreements are regulated by [FERC] under the Federal Power Act.
Id. at 417-18 (footnote omitted) (emphasis supplied).
. Middle South Energy, Inc., SEC PUHCA Release No. 22,280 (Nov. 18, 1981).
. See 15 U.S.C. § 79k(b) (1982).
. Id.
. Id. § 79b(a)(29).
. Middle South Utilities, Inc., 35 S.E.C. 1, 10 (1953).
. State of Minnesota, 344 N.W.2d at 382 n. 17 (quoting 15 U.S.C. § 79a(a) (1982)).
. Id.
. This doctrine is based on the companion cases of United Gas Pipe Line Co. v. Mobile Gas Service Corp., 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).
. Town of Norwood v. FERC, 587 F.2d 1306, 1310 (D.C.Cir.1978).
. 616-R. 2982, I J.A. 246.
. In fact, the record suggests that the parties contemplated FERC review of the terms of the UPSA. See Reallocation Agreement, July 28, 1981. 616-R. 3275, I J.A. 268 ("2. An agreement between LP & L, MSE, MP & L and NOPSI will be executed in form for filing with the Federal Energy Regulatory Commission in accordance with Part 35 of the Commission’s Regulations establishing the terms, conditions and rates for the sale of capacity and energy from MSE to LP & L, MP & L and NOPSI.... 7. The effectiveness of this Agreement is subject to the receipt of all necessary regulatory approvals.”).
. 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); Kansas Cities v. FERC, 723 F.2d 82, 87 (D.C.Cir.1983).
. Papago Tribal Utility Authority, 723 F.2d at 953. The APSC incorrectly suggests the Supreme Court’s holding in Sierra made the public interest standard the sole criteria for contract revision in section 205 or section 206 proceedings. In fact, as this court has made clear, either the interest of the public or the interest of the parties in nondiscriminatory rates will suffice to justify the Commission’s decision to reform rates, id. at 954 n. 5, so long as the parties’ contract does not eliminate the Commission’s authority over discrimination or preference that operates only against the signatories. Such discrimination may be waived "up to the point where it produces some independent harm to the public interest,” id. at 953 n. 4, but no such waiver took place in the instant case.
. ”[C]ourts and the Commission have almost universally construed contractual references to future rate changes to authorize § 206 proceedings with a just-and-reasonable standard of proof.” Kansas Cities, 723 F.2d at 88.
. See Richmond Power & Light v. FPC, 481 F.2d 490, 493 (D.C.Cir.) (describing the Mobile-Sierra doctrine as "refreshingly simple; ... Rate filings consistent with contractual obligations are valid; rate filings inconsistent with contractual obligations are invalid.”), cert. denied, 414 U.S. 1068, 94 S.Ct. 578, 38 L.Ed.2d 473 (1973).
. Mobile, 350 U.S. at 344, 76 S.Ct. at 381.
. Sierra, 350 U.S. at 353, 76 S.Ct. at 371.
. Id. at 355, 76 S.Ct. at 372.
. 26 FERC ¶ 63,044 at 65,108 & 65,104.
. Permian Basin Area Rate Cases, 390 U.S. 747, 822, 88 S.Ct. 1344, 1389, 20 L.Ed.2d 312 (1968).