MEMORANDUM OPINION
BRADEN, Judge.This case concerns an alleged breach of an August 16, 1994 contract for electric power transmission and ancillary services, including regulating service, between the Western Area Power Administration (“WAPA”) and the Arizona Electric Power Cooperative, Inc. (“AEPCO”), pursuant to which North Star Steel Co. (“North Star”) has brought this action as a third-party beneficiary to recover monetary damages. Before turning to the pending motions, it is necessary to survey the labyrinth of laws that Congress enacted to regulate virtually all aspects of the electric utility industry and which directly affect the court’s limited jurisdiction and rulings in this complex and sui generis case.
BACKGROUND
A. Federal Regulation Of The Electric Utility Industry1
Federal regulation of the electric utility industry had its genesis when the government began to fund massive public work projects to utilize hydropower resources to create jobs and expand electric power service in rural and undeveloped areas of the country, primarily in the southern and western states. One of the most significant congressional endeavors in this area was the Boulder Canyon Project Act, enacted in 1928, authorizing the Secretary of the Department of Interior (“Interior”) to construct a dam and hydroelectric power plant on the Colorado River near the Nevada and Arizona border, known today as Hoover Dam. This Act also authorized the Secretary of Interior to enter into contracts for the sale of energy produced at that site. Id. Congress, however, required that contracts for the sale of hydroelectric power generated at Hoover Dam must provide for “payment of all expenses of construction, operation, and maintenance of said [works.]” 43 U.S.C. § 617c(b).
In 1935, Congress passed the Federal Power Act (“FPA”), which had a different objective: “to curb abusive [monopolistic] practices of public utility companies by bringing them under effective control, and to provide effective federal regulation of the expanding business of transmitting and selling electric power in interstate commerce.” Gulf States Util. Co. v. FPC, 411 U.S. 747, 758, 93 S.Ct. 1870, 36 L.Ed.2d 635 (1973). This revolutionary legislation created the Federal Power Commission (“FPC”) to regulate the nascent, but growing, business of selling electric power in interstate commerce, *723which became the catalyst for the modernization of the electric utility industry. The scope of power exercised by FPC is best summarized in the agency’s own words: “The public interest is far broader than the economic interest of a particular power supplier. It is our legal responsibility, as the Supreme Court made clear in Pennsylvania Water & Power Co. v. FPC, 343 U.S. 414, 72 S.Ct. 843, 96 L.Ed. 1042 (1952), to use our statutory authority to assure ‘an abundant supply of electric power throughout the United States,’ and particularly to use our statutory power ... to compel interconnection and coordination when the public interest requires it.” Otter Tail Power Co., 410 U.S. at 380, 93 S.Ct. 1022 (internal citation omitted).
Several years later, Congress’ interests turned to the financial terms under which power generated at Hoover Dam was being sold. Oversight hearings resulted in the enactment of the Boulder Canyon Project Adjustment Act, which authorized the Secretary of Interior to continue to approve such contracts, but only at rates sufficient to repay the United States for construction, operation, and maintenance costs related to the site. See 43 U.S.C. § 618g. Thereafter, regulations were enacted to clarify that the Secretary of Interior had sole authority to set rates for the sale of firm power 2 and secondary power generated at Hoover Dam, subject to annual adjustments for fluctuations in project operation and maintenance costs. Shortly thereafter, Congress enacted the Flood Control Act of 1944 to ensure that all such contracts would be coordinated with the Secretary of Interior, who in turn set up five regional federal Power Marketing Administrations (“PMAs”). Each PMA was required to prepare interim rate schedules for generation and transmission services,3 based on accounting and cost allocation studies and analyses. Congress allowed the Secretary of Interior to continue to approve federal PMA rates on an interim basis, but vested the increasingly powerful FPC with exclusive jurisdiction to finalize such rates applying its “special expertise in ratemaking,” pursuant to a “dual statutory standard of providing consumers with the benefits of power at the lowest possible price consistent with good business practices as well as protecting the interests of the United States in amortizing its investment in the projects within a reasonable period.” See Bonneville Power Admin., 34 F.P.C. 1462, 1465 (1965). This legislation effectively placed all final rates for federal hydroelectric projects and private utilities in the hands of one federal agency.
By the late 1970’s, the public became concerned about perceived and real energy shortages and the rising price of certain energy products, primarily gasoline. In response, Congress enacted the DOE Organization Act in 1977 to consolidate energy-related programs and agencies throughout the federal government into the new Department of Energy (“DOE” or “Energy”). See 42 U.S.C. §§ 7101 et seq. As part of this massive reorganization, the oversight of the marketing and transmission functions of the PMAs, other federal hydroelectric projects, and reservoirs was transferred from DOI to DOE. See 42 U.S.C. § 7152(a). In addition, FERC was established as an independent commission within DOE to assume the functions of FPC, but with expanded regulatory authority over the interstate sale of wholesale electric power and transmission services. See Department of Energy, Power Market *724Rates, Delegation Order for Confirmation and Approval, 43 Fed.Reg. 60636, 60636-37 (Dec. 28,1978). More important, FERC also was given exclusive jurisdiction to “confirm, approve, and place in effect on a final basis, to remand, or to disapprove” all final rates under the following standard:
(a) Whether the rates are the lowest possible to customers consistent with sound business principles; (b) whether the revenue levels generated by the rates are sufficient to recover the costs of producing and transmitting electric energy ...; and (c) the assumptions and projections used in developing the rate components that are subject to [FERC] review.
Delegation Order for Approval of Power Marketing Administration Power and Transmission Rates, 48 Fed.Reg. 55664, 55664-65 (Dec. 14, 1983). In 1983, the Department of Energy also issued Secretarial Delegation Order No. 0204-108 to clarify that WAPA was required to submit all rates to FERC for final approval. Id.
A related piece of legislation was enacted in the next year-, the Public Utility Regulatory Policies Act of 1978 (“PURPA”), to encourage the conservation of fossil fuels and promote the development of new generating facilities with “equitable rates.” By that time, significant technological advances made it possible to transmit electric power over long distances at a lower and lower cost by “wheeling power,” ie., the “transfer by direct transmission or displacement electric power from one utility to another over the facilities of an intermediate utility.” Otter Tail Power Co., 410 U.S. at 368, 93 S.Ct. 1022. The larger utilities, however, had control over most of the nation’s transmission lines and were reluctant to purchase power from nontraditional facilities. Therefore, Congress directed FERC to promulgate rules under PURPA to require utilities to purchase electricity from “qualifying” cogeneration and smaller power production facilities. These rules increased the “wheeling” of power across the country and allowed consumers to shop for the lowest available power rates.
On August 1, 1984, Congress passed the Hoover Power Plant Act of 1984, Pub.L. No. 98-381, 98 Stat. 1333 (codified at 43 U.S.C. §§ 619 et seq. (2000)), which again significantly upgraded and increased the generation capacity at Hoover Dam. This Act also allocated by specific contractor the amounts of long term firm energy and contingent capacity that would be available for contract renewals for the period of June 1, 1987 to September 30, 2017. See 43 U.S.C. §§ 619a-b. The principal purpose of this Act was to ensure that these preference contractors, specifically designated in the statute, had sufficient energy capacity reserved for their exclusive use. Id. In addition, Congress expanded the criteria that WAPA had to consider in establishing interim rates for sales of hydroelectric power to provide adequate revenues to cover all operational and maintenance expenses, as well as yield “reasonable returns,” adjusted by “competitive conditions at the distributing points of competitive een-ters[.]” 43 U.S.C. § 617d.
Next, Congress enacted the Energy Policy Act of 1992 authorizing FERC to order any public utility, including federal PMAs, to provide, on a case-by-case basis, transmission services to unaffiliated wholesale generators, such as rural electric cooperatives and municipalities, where such action was determined to be in the “public interest.” 16 U.S.C. §§ 824j-k. Such services could be priced to include “all the costs incurred in connection with the transmission services and necessary associated service ... and shall be just and reasonable, and not unduly discriminatory or preferential.” Id. at § 824k.
In April 1996, FERC issued Order No. 888, which was the result of an exhaustive agency investigation, numerous congressional and agency hearings, and hundreds of studies, concluding that most of the nation’s larger electric utilities were discriminating in the “bulk power marketplace” by providing inferior or no access to third-party power wholesalers. See 61 Fed.Reg. 21540, 21541-50 (May 10, 1996). To remedy this situation, FERC ordered the “functional unbundling" of wholesale generation and transmission services, ie., each utility had to provide customers with separate rates for wholesale generation, transmission, and ancillary ser*725vices,4 such as regulating services. Id. at 21551-52.5 In addition, each utility had to take transmission of its own wholesale sales and purchases under a single general rate that was applicable to the utility as well as its customers. Id. at 21541. FERC also imposed an open access requirement on unbundled retail transmission in interstate commerce, but did not mandate open access to the transmission component of bundled retail sales. Following extensive litigation, the United States Court of Appeals for the D.C. Circuit upheld the mandate of FERC Order No. 888. See Transmission Access Policy Study Group v. Federal Energy Regulatory Commission, 225 F.3d 667, 683 (D.C.Cir. 2000) (“The open access requirement of Order 888 is premised not on individualized findings of discrimination by specific transmission providers, but on FERC’s identification of a fundamental systemic problem in the industry.”), ajfd, New York v. FERC, 535 U.S. 1,122 S.Ct. 1012,152 L.Ed.2d 47 (2002).
B. Relevant Facts 6
1. Consolidated Contract Negotiations And Provisions To Ensure That WAPA Would Recover The Costs Of Providing Regulating Service To North Star.
Sometime in the early 1990s, North Star decided to build, own, and operate an electric are furnace recycling mill and related facilities to manufacture steel rod and bar, near Kingman, Arizona. See DPF at ¶ 5; see also PSGI at ¶ 5. Large amounts of electricity would be needed to operate this furnace, which would recycle scrap steel into new products. See DPF at ¶ 5; Pl.App. C at 2-3 (Jan. 21, 2002 Affidavit of Michael Sarafolean, North Star’s Energy Procurement Manager (“Sarafolean Aff.”), at ¶ 4); see also PSGI at ¶ 5.
By this time, WAPA was engaged in selling power generated at the Hoover Dam, as well as fifty-four other hydroelectric power-plants at wholesale rates to statutory preference customers. See 43 U.S.C. § 485h(c). In addition, WAPA also operated and maintained 16,819 miles of transmission lines, including the Parker-Davis Project Electric Transmission System. See DPF at ¶ 4. In fact, WAPA owned the only transmission lines in the geographic area of Kingman, Arizona with sufficient voltage (230 kv) to provide North Star’s electric power requirements. See Pl.App. C at 3 (Sarafolean Aff. at ¶ 5); see also DPF at ¶ 6;. PSGI at ¶ 6.
WAPA, however, was unable to sell firm power to North Star because it was not a statutory preference customer and WAPA previously committed all its firm power to such customers. See 43 U.S.C. § 485h(c); see also DPF at ¶ 7. In order to be able to use WAPA’s transmission lines and facilities to wheel in power from other sources, North Star, AEPCO, and MEC worked with WAPA to find a creative solution to arrange for North Star to meet its power requirements, working around the existing regulatory structure. First, North Star petitioned the State of Arizona to transfer the area retail power franchise from Citizens Utilities Company to Mohave Electric Cooperative, Inc. (“MEC”), a member of AEPCO, a generation and transmission cooperative that was eligible to purchase power and other *726services from WAPA. See 43 U.S.C. § 485h(c). (“[I]n ... sales or leases [of electric power] preference shall be given [by WAPA] to municipalities and other public corporations or agencies; and also to cooperatives and other nonprofit organizations financed in whole or in part by loans made pursuant to the Rural Electrification Act of 1936.”); see also DPF at 17; PSGI at ¶ 7. Next, on August 16, 1994, North Star, AEP-CO, and MEG entered into an electric service agreement (“ES Agreement”) obligating AEPCO and MEG to purchase non-firm energy for North Star from other sources, but to deliver it to WAPA via interconnecting transmission systems. See Def.App. at 50-118; see also DPF at ¶ 9. Since the electric power purchased was non-firm and could be interrupted at any time, neither WAPA, AEPCO, nor MEG was required to reserve any generation capacity for North Star or any transmission assets to serve North Star. See Pl.App. C at 4-5 (Sarafolean Aff. at 17). Under the ES Agreement, North Star was obligated to pay AEPCO for transmission services, pursuant to WAPA’s FERC Rate Schedule PD-NFT4, plus additional specified charges. See Def.App. at 50-118; see also PLApp. C at 5 (Sarafolean Aff. at ¶ 8).
On August 16, 1994, WAPA and AEPCO entered into two other contracts of which North Star was the intended third-party beneficiary. The first contract, No. 94-PAO-10589, provided for the construction and interconnection of facilities required to connect North Star’s mill to WAPA’s transmission system. See Def.App. at 1-15; see also DPF at ¶ 8(a); PSGI at ¶ 8.
The second contract, No. 94-PAO-10590 (“Consolidated Contract”), provided for transmission services, operating arrangements, regulating service, and operation and maintenance to enable WAPA to meet North Star’s load. See Def.App. at 16-49 (“Consolidated Contract”); see also DPF at ¶8(b); PSGI at ¶ 8.7 Pursuant to Section 7.1 of the Consolidated Contract, WAPA charged AEP-CO “rates, charges, and conditions set forth in [FERC] Rate Schedule PD-NFT4 ... for Non-Firm Transmission serviee[.]” Def. App. at 26 (Consolidated Contract at § 7.1); see also Def.App. at 48-49 (FERC Rate Schedule PD-NFT4, effective Oct. 1, 1995-Dec. 31,1998).
WAPA also agreed to provide AEPCO with dynamic “regulating services” for North Star’s load. See Def.App. at 31-32 (Consolidated Contract at § 14.1); see also DPF at ¶¶ 8(b), 10. At this time, however, WAPA did not offer separate ancillary services, including regulating service, which were included as part of WAPA’s standard transmission FERC Rate Schedule PD-NFT4. Any requirements that WAPA’s transmission customers may have had for regulating service, however, were based on a significantly smaller load than North Star required.8 Therefore, WAPA and AEPCO agreed that the “regulating service” to be provided to North Star would be made and paid for pursuant to an ad hoc methodology for an “In-Kind Energy” payment. See Def.App. at 31-33, 36-37 (Consolidated Contract at §§ 13, 14, 21). This rate surrogate was supposed to be determined as follows. AEPCO, on North Star’s behalf, would pre-schedule non-firm energy for delivery to WAPA’s transmission system, including such amounts as WAPA advised were necessary to service its own load. See Def.App. at 31-33 (Consolidated Contract at §§ 14.1-14.7); see also DPF at ¶ 11; Pl.App. B at 6 (June 16, 2002 Affidavit of James Rein, Director of Sales for Sierra Southwest Cooperative Services and AEPCO’s former Director of Power Services (“Rein Aff.”) at ¶ 7 # 11(a)). This allowed WAPA to “back down” generation of electricity in the same amount pre-scheduled by AEPCO while still being able to dedicate all its capacity to WAPA’s preference customers. See PLApp. B at 6 (Rein Aff. at ¶ 7 # 11(b)); DPF at ¶ 11. In other words, “In-Kind Energy” in megawatt (“MW”) hours was transferred from AEPCO to WAPA to compensate WAPA for the displacement and *727use of its otherwise committed, but not always used, firm power, which then was used to meet North Star’s load. See Def.App. at 31-32 (Consolidated Contract at §§ 14.1-14.3); see also DPF at ¶¶ 11-12. At its discretion, WAPA used any excess “In-Kind Energy” to service its own load or resold it on the open market. See DPF at ¶ 1.
WAPA was concerned, however, that this arrangement might not allow it to recover costs. See 43 U.S.C. § 617d; see also PL App. C. at 5 (Sarafolean Aff. at ¶ 9). Therefore, WAPA insisted that the Consolidated Contract include several provisions to protect its interests. First, WAPA retained the right to interrupt transmission of electricity to North Star or automatically “shed” North Star’s load for any reason. See Def.App. at 35 (Consolidated Contract at § 17); see also Pl.App. B at 6-7 (Rein Aff. at ¶ 7 # 11(b)).
Second, North Star was required to pay not only the standard FERC-approved transmission rate, but also an additional charge specifically designed to recover whatever other costs WAPA may incur. See Def-App. at 32-33 (Consolidated Contract at § 14.3). In addition, if North Star’s load exceeded pre-scheduled demand by more than 5 MW and WAPA did not exercise its right to interrupt transmission, WAPA had authority to impose a penalty on the excess demand. Id. at 33 (Consolidated Contract at § 14.4).
Third, WAPA proposed a methodology to calculate an “In-Kind Energy” payment for regulating service based on load information provided by North Star, pertaining to a similar mill, and the product replacement cost of procuring regulating service via “In-Kind Energy” from an alternative provider. Compare Def.App. at 121-41; DPF at ¶¶ 12-13 with PSGI at ¶ 13 (“Nowhere in the documents cited is there any analysis by WAPA of its estimated cost to provide service, let alone evidence of a methodology that it developed to support the initial 20% charge.”). This equated to an “In-Kind Energy” payment of 20 percent (20%) of “actual” metered non-firm energy. See Def.App. at 32-33 (Consolidated Contract at § 14.3); see also PLApp. C at 6 (Sarafolean Aff. at ¶ 11); Def.App. at 160 (“[Regulation and load following services for North Star are paid through 20% In-Kind payment which is added to North Star’s pre-scheduled loads.”). WAPA, AEP-CO, and North Star agreed, however, that after one year of normal operation, the 20% formula would be adjusted upward or downward to reflect a consensus methodology. See Def.App. at 36-37 (Consolidated Contract at § 21) (“[T]he Parties shall ... periodically, if necessary, adjust the percentage associated with the In-Kind Energy payment.”) (emphasis added); see also Def.App. at 119 (Rein Dep. at 17) (“[WAPA] just did not know how to price regulating service, so they wanted to have as much flexibility to go up or down ... whenever they determined what the cost should finally be.”); DFP ¶¶ 12, 14.
2. Post Consolidated Contract Communications Between WAPA And North Star Failed To Achieve “An Appropriate Cost-Based Methodology” For The “In-Kind Energy Payment.”
On July 1, 1997, North Star’s mill began commercial operation. See Pl.App. C at 7 (Sarafolean Aff. at ¶ 13); Def.App. at 160; see also DPF at ¶ 16. From October 23, 1997 to July 28, 1999, WAPA AEPCO, and North Star engaged in negotiations under to Section 21 of the Consolidated Contract to ascertain “an appropriate cost-based methodology” for the “In-Kind Energy” payment. See PLApp. C at 7 (Sarafolean Aff. at ¶ 14); see also DPF at ¶ 17. As the following chronology of these negotiations details, no agreement was reached.
On January 7, 1998, WAPA advised AEP-CO and North Star that it intended to offer regulating service to preference customers, which included “frequency response, voltage control, capacity, ramping and associated energy, scheduling and dispatch, and power accounting.” Def.App. at 160. In providing these services, WAPA would be required to evaluate: resource availability, generator control, and response to its customer’s moment to moment changes; generator control and response to variations in loads to maintain sixty hertz frequency; and factors to prevent generation and transmission system contingencies. Id. at 170-72. At a January *72813, 1998 meeting, however, WAPA provided AEPCO and North Star with a different methodology for the “In-Kind Energy” payment, based on WAPA’s estimate of the market value of generating capacity, including certain assumptions about the amount of regulating service required by North Star’s load. Id. at 159-62; see also DPF at ¶19; PSGI at ¶ 19. WAPA represented that this methodology did not include any “incremental costs” associated with possible fluctuations in North Star’s load and any additional stress that such fluctuations may have imposed on WAPA’s equipment and system. See Def. App. at 167 (“[D]eriving the incremental costs to the system of regulation provided specific to North Star loads may be indeterminable.”); see also DPF at ¶ 20 and n. 4
On February 3, 1998, WAPA provided AEPCO and North Star with a revised proposal that compared regulating service for a “typical” WAPA wholesale customer with an average 6 MW load with North Star’s 85 MW load. See Def.App. at 166-68, 172; see also DPF at ¶ 20. On March 6, 1998, another meeting was held. Def.App. at 169-81. Again, no agreement was reached. On May 27, 1998, WAPA proposed still another payment methodology for North Star’s consideration. Id. at 182-94. This methodology utilized the regulating service rate schedules of regional utilities and applied a volatility factor, based on North Star’s actual load fluctuation. Id. at 182-85. On June 5,1998, AEP-CO made two counterproposals on behalf of North Star, both of which were rejected by WAPA. Id. at 195.
On June 16,1998, WAPA issued a notice to its preference customers that it would be providing “long-term open access transmission and ancillary service rate methodologies” on an interim basis, as of November 1, 1998. See June 16, 1998 letter from Maher A. Nasir, WAPA Power Marketing Rates Team Leader, to “Southwest Region Customers.” WAPA further advised that its marketing arm intended to file rates with FERC for six ancillary services, including “Regulation and Frequency Response Service,” which prior to this time was not offered at an “unbundled rate.” See June 16, 1998 WAPA Brochure at 3.
Following a public comment period, WAPA filed an Open Access Transmission Tariff on December 7, 1998 with FERC that utilized a formula methodology for short-term sales of network integration transmission services, which became final on January 20, 2000. See Order Confirming and Approving Rate Schedules on a Final Basis, 90 FEC. ¶ 62032, *1-3 (Jan. 20, 2000). WAPA also filed Rate Schedule DSW-FR1 for ancillary services with FERC on December 7, 1998, including “regulation and frequency response service[.]” See Desert Southwest Customer Service Region Network Integration Transmission and Ancillary Services, Rate Order No. WAPA-84, 64 Fed.Reg. 25323, 25323 (May 11,1999). This rate was to be effective from April 1, 1999 through March 31, 2004. Id. Specifically, “[rjegulation and frequency response service” was to be provided, if available, at a charge reflecting “the firm capacity rate of the project providing the regulation.” Id. at 25327. If transmission or ancillary services, such as regulating service, were not available, they were to be obtained in the open market and sold to the customer at a “pass through” rate at the cost of the service, plus a ten percent (10%) administrative charge. Id.; see also Pl.App. B at 9-10 (Rein Aff. at ¶ 7 #20).
On December 8, 1998, WAPA solicited approximately 65 potential suppliers to provide bids for service to regulate North Star’s load. See Def.App. at 197-98. No responses were received because none of the regional utilities standard tariff rates offered the regulating service that met North Star’s requirements. Id.
On March 8, 1999, WAPA requested that AEPCO comment on another methodology for calculating the “In-Kind Energy Charge,” noting: that “[WAPA] agrees with you that this contract has not been implemented as it is written. If [WAPA], AEPCO and [North Star] take action to change the current scheduling practices so that the contract is implemented as written, then [WAPA] will realize some benefits. As a result, [WAPA] would be willing to implement the calculation methodology shown ... and reduce the [current 20%] In-Kind Energy Charge percentage.” Id. at 200 (empha*729sis added). In April 1999, other negotiating meetings were held between WAPA, AEP-CO, and North Star “regarding regulating services.” Id. at 203. On May 11, 1999, North Star’s counsel provided WAPA with comments on those discussions. See Pl.App. K at 609-11. On May 27, 1999, WAPA proposed a new methodology using the standard FERC tariff rate of the Salt River Project and a volatility factor “to fix the In-Kind percent from July 1, 1999, through June 30, 2000.” Def-App. at 203. WAPA represented, however, that it was “willing to consider options and alternatives that can be implemented within the provisions of the existing contract with [AEPCO] through modifications to operating procedures.” Id.
On July 28,1999, WAPA informed AEPCO and North Star that negotiations had now ended and presented a “take-it-or-leave-it offer,” based on a revenue stream that WAPA projected would be produced by the Consolidated Contract, and which had been provided to its preference customers. Id. at 207-08; see also Pl.App. C at 8 (Sarafolean Aff. at ¶ 18). On July 29, 1999, North Star authorized AEPCO to accept Amendment No. 3 amending the Consolidated Contract by adding and incorporating Exhibit H. See Def.App. 217-28. The “cost-based” methodology (set forth in Attachment H-l) compensated WAPA for the value of “In-Kind Energy” payments provided by AEPCO up to $1.5 million annually, ie., an estimated “In-Kind” percentage of 19.67%. See Def-App. at 222-23; see also DPF at ¶ 22. In addition, Exhibit H provided that, under certain specified conditions, WAPA or AEPCO could invoke an alternative methodology (set forth in Attachment H-2), compensating WAPA for the value of “In-Kind Energy” up to $750,000 annually, ie., an estimated “In-Kind” percentage of 9.83%. See Def.App. at 224-28; see also DPF ¶ 23. Moreover, Exhibit H provided that WAPA had the unilateral right, with notice, to “review, evaluate and adjust the value of the In-Kind Energy payment” under certain circumstances, such as where the spot market price increased above a specified level. See Def.App. at 219; see also DPF at ¶ 24. The methodology set forth in Attachment H-l was instituted and remained in effect for fiscal year 2000 (October 1999— September 2000). See Def-App. at 251-52; see also DPF at ¶ 27.
On September 15, 1999, WAPA and AEP-CO, on North Star’s behalf, signed Amendment No. 3, effective retroactively to August 1, 1999, despite North Star’s express reservation that WAPA’s proposal was unreasonable and not based on actual costs: “It is North Star’s view that none of the proposals put forth by [WAPA] are truly cost-based and that all are unreasonable. The current charge is so excessive, however, that even the unreasonable lesser charge is preferable to the continuation of the charge at the existing level.” See Def-App. at 207; see also PSGI at H 21; PLApp. B at 10 (Rein Aff. at ¶ 7 # 21); Pl.App. C at 9 (Sarafolean Aff. at ¶ 19) (“North Star ... was in effect coerced ... to accept WAPA’s ‘bottom line’ offer[.]”); Def.App. at 209-28; DPF at ¶¶ 21, 26. North Star objected, but admitted that Amendment No. 3 “had the effect of reducing the economic value of North Star’s In-Kind Energy Payment from approximately $2.1 million to $1.5 million____North Star continued [however] to be responsible for tariff transmission charges that amount to $1.2 million per year____ charges! North Star asserts were] sufficient to compensate WAPA for Control Area and Regulating Services[.]” PLApp. C at 9 (Sarafolean Aff. at ¶ 20).
On April 27, 2000, North Star filed a complaint in this court for breach of the Consolidated Contract and other claims seeking, among other relief, monetary damages in the form of a refund for WAPA’s overcharges concerning the methodologies used to determine the “In-Kind Energy” payments.
On August 1, 2000, WAPA notified AEP-CO and North Star that WAPA was invoking its right to re-evaluate the “In-Kind Energy” payment because the spot market price of electricity had risen above specified levels in the contract. See Def.App. at 229; see also DPF at f 28. Discussions commenced in December 2000 and continued into January 2001 to determine if an alternative methodology, agreeable to WAPA and North Star, could be applied retroactively to October 1, 2000. See Def.App. at 230-33; see also DPF *730at ¶ 29. Those efforts were unsuccessful. See DefApp. at 234-53; see also DPF at ¶ 37. On January 5, 2001, another meeting was held to finalize the “regulation fee.” Def.App. at 230-33. Again, no agreement was reached. See DPF at ¶ 37.
On June 29, 2001, WAPA unilaterally modified Exhibit H and implemented another payment methodology for “In-Kind Energy,” retroactive to October 2000, that is still currently in effect. See DPF at ¶¶ 30-31. This methodology was described as REVISION No. 1 or REV 1. Id. at ¶ 32.
REVISION No. 1 provides for the following scheduling methodology:
AEPCO will pre- and post-schedule Non-Firm Energy to [WAPA] to provide for the metered North Star load plus In-Kind Energy, based upon the anticipated metered North Star load. Effective October 1, 2000, In-Kind Energy will be scheduled in an amount such that the total value of the In-Kind Energy equals an amount' calculated in accordance with the methodology set forth in Attachment H-l, REVISION No. 1, hereto and the hourly peak demand for pre-scheduling and accounting shall be interpreted in accordance with MSI3 as measured, determined, and reported by [WAPA].
DefApp. at 236; see also DPF at ¶ 33.
On August 7, 2001, WAPA forwarded REVISION No. 1 to North Star and AEPCO for execution. See Def.App. at 234-51; see also DPF at ¶ 32. On October 17, 2001, North Star responded with a counterproposal that substantially departed from the previous methodology in that AEPCO would no longer pre-schedule “In-Kind Energy” with WAPA. See Def.App. at 253; see also DPF at ¶ 34-36.
Despite their disagreement over the methodology for determining the “In-Kind Energy” payment for regulating services, there is no dispute that WAPA provided North Star with transmission and regulating services from August 17, 1994 to August 1, 1999 for which AEPCO (North Star) paid WAPA, pursuant to Section 21 of the Consolidated Contract. From August 1, 1999 to October 1, 2000, AEPCO (North Star) paid WAPA, pursuant to Amendment No. 3. And, from October 1, 2000 to the present, AEPCO (North Star) paid WAPA, pursuant to REVISION No. 1. North Star asserts, however, that all of the aforementioned methodologies violated and continue to violate the Consolidated Contract. See Pl.App. C at 10 (Sarafolean Aff. at ¶ 21).
C. Procedural Background
On April 18, 2001, North Star filed a First Amended Complaint in the United States Court of Federal Claims seeking a declaration that the amount North Star was required to pay for WAPA control area and regulating services since its date of initial operation on July 1, 1997, which WAPA argues violates the Consolidated Contract, various federal statutes, and is arbitrary, capricious, an abuse of discretion, and otherwise not in accordance with applicable law. In addition, North Star requested entry of an order requiring WAPA to refund the full value of the “In-Kind Energy” payments made by North Star from the beginning of its operation on July 1, 1997 to the date of judgment or, in the alternative, to refund the difference between what North Star paid for services for the period between July 1, 1997 and August 1, 1999, and the amount North Star would have paid under the methodology set forth in Amendment No. 3. See First Amended Complaint at 8 (Prayer for Relief).
On December 7, 2001, WAPA moved for summary judgment. Briefing was completed on February 5, 2002. On August 15, 2003, the Honorable Lynn J. Bush transferred this case to the undersigned judge.
DISCUSSION
A. Jurisdictional Issues
Even though the court’s jurisdiction has not been challenged in this case, the court nevertheless has an obligation to undertake an independent analysis of this issue. See Palmer v. Barram, 184 F.3d 1373, 1377 (Fed.Cir.1999) (“Although the government did not move to dismiss, it is always the duty of the court to determine its jurisdiction[J”).
*7311. Effect Of The DOE Organization Act
Certainly the court has subject matter jurisdiction to hear actions for monetary relief against the United States, pursuant to the Tucker Act’s waiver of sovereign immunity. See 28 U.S.C. § 1491(a)(1). Such actions include “contracts with the United States, actions to recover illegal exactions of money by the United States, and actions brought pursuant to money-mandating constitutional provisions, statutes, regulations or executive orders.” Martinez v. United States, 333 F.3d 1295, 1302-03 (Fed.Cir.2003). North Star asserts, however, that 28 U.S.C. § 1491(a) alone provides the court with jurisdiction over its breach of contract and other claims. See April 18, 2001 First Amended Complaint at ¶ 1. The court’s jurisdiction, however, is not so easily resolved in this case because the determinative issue is whether the explicit waiver of sovereign immunity and grant of jurisdiction under the Tucker Act of 1887 was trumped by Congress when it enacted the DOE Organization Act in 1977.9
When Congress enacted the DOE Organization Act transferring jurisdiction from FPC to FERC for all final rates of the PMAs, including WAPA, no provision was included that specifically provided for judicial review of such determinations. Since that time, some federal appellate courts have held that a district court may review FERC final action, but only under the Administrative Procedure Act, 5 U.S.C. §§ 701-02 (2000) (“APA”). See Central Lincoln Peoples’ Util. Dist. v. Johnson, 735 F.2d 1101, 1109 (9th Cir.1984) (“Since there are no special provisions for judicial review of ... [final FEC.] rate determinations, challenges to other PMA rates are brought in district court under the [APA].”) (citing FERC Supplemental Status Report 1 n. 1 (June 3, 1983));10 see also Nader v. Volpe, 466 F.2d 261, 266-67 (D.C.Cir.1972) (denying an injunction under the APA where the regulation at issue was not final and observing: “The implicit legislative concept of separateness in the functioning of agencies and courts is ill served by improvident judicial interference in agency administrative proceedings.”).
In Overton Power District No. 5 v. O’Leary, 73 F.3d 253, 255-258 (9th Cir.1996), the United States Court of Appeals for the Ninth Circuit went further, dismissing an action brought by two power suppliers challenging final FERC approval of WAPA rates for power generated at Hoover Dam, holding that the presumption of reviewability under the APA was overcome “whenever the congressional intent to preclude judicial review is ‘fairly discernable in the statutory scheme.’ ” Id. at 255 (citations omitted). In reaching this determination, that federal appellate court relied on Block v. Community Nutrition Inst., 467 U.S. 340,104 S.Ct. 2450, 81 L.Ed.2d 270 (1984), in which consumers *732were held not to have standing to seek judicial review of milk marketing orders because “the congressional intent to preclude is fairly discernible in the statutory scheme ... consumer suits might themselves frustrate achievement of the statutory purposes [by disrupting the] cooperative venture among the Secretary [of Agriculture], producers, and handlers ... [and] undermining] the congressional preference for administrative remedies!.]” Id. at 351-52, 104 S.Ct. 2450 (quotations omitted) (emphasis added); see also Clarke v. Securities Indus. Ass’n, 479 U.S. 388, 400, 107 S.Ct. 750, 93 L.Ed.2d 757 (1987) (“In Community Nutrition Inst., ... the Court found that... the reviewability question turns on congressional intent[.]”) Id. at 400, 107 S.Ct. 750 (quotations omitted) (emphasis added).
The gravamen of North Star’s breach of contract claim, if a breach occurred, necessarily will require the court to determine whether the methodologies used to determine the “In-Kind Energy” payment for regulating service WAPA utilized after July 1, 1998, i.e., one year after the Consolidated Contract became effective and the date on which the parties were to have arrived at a consensus methodology, were “reasonable,” and, if not, what methodology or methodologies would be “reasonable.” See Aviation Contractor Employees, Inc. v. United States, 945 F.2d 1568, 1573 (Fed.Cir.1991) (“[A] court can enforce the contract by determining a reasonable price.”); see also Willi-ston on contracts § 4.28 (4th ed.) (“[I]f the contract cannot be performed without resolution of the undetermined point, but the parties have intended to contract, and a reasonable term can be inferred to have been intended, each party will be bound to a reasonable determination of the unsettled point in order that the main promise may be enforced.”) (emphasis added); Restatement (Second) Contracts at § 33, comment e (1981). Therefore, the court must ascertain whether Congress intended that the pervasive regulatory system it put into place with the enactment of the DOE Organization Act to limit or modify the court’s jurisdiction under the Tucker Act, leaving North Star only with the injunctive remedies provided in the APA.
On the date the Consolidated Contract was executed, WAPA had final power and transmission service rates on file with FERC, ie., rates determined to be reasonable and in the public interest. Accordingly, if North Star’s complaint challenged those rates, the court is persuaded that it would not have jurisdiction in light of clear congressional intent to delegate and commit final rate reviewability to FERC’s expertise and discretion. Likewise, the court would have no jurisdiction to adjudicate a challenge to WAPA’s ancillary services rate that was implemented, pursuant to FERC Order No. 888 and made final on May 11,1999. The Consolidated Contract at issue in this case, however, was entered on August 16, 1994, and at that time WAPA did not have a separate rate for regulating service and none had been submitted to FERC for final approval. Therefore, the surrogate rate or methodology for determining the “In-Kind Energy” payment for regulating service set forth in the Consolidated Contract was exempt from FERC’s jurisdiction on the date the contract was executed. Therefore, and only for this reason, the court has determined that it has jurisdiction only over North Star’s breach of contract claim with respect to WAPA’s methodology for determining “In-Kind Energy” payment for regulating service. The court has not yet determined whether its jurisdiction over North Star’s breach of contract claim is impacted by FERC’s action on May 11, 1999 finalizing WAPA’s first unbundled rate for regulating service, but will request briefing on this and other issues in the near future.
2. North Star’s Declaratory Judgment Claim
Paragraphs 33(a) and (b) of North Star’s April 18, 2001 First Amendment attempts to state a claim for declaratory judgment. The United States Court of Appeals for the D.C. Circuit dismissed a Little Tucker Act case holding that, “We know of no case in which a court has asserted jurisdiction either to grant a declaration that the United States was in breach of its contractual obligations or to issue an injunction compelling the United States to fulfill its contractual obligations ... the District Court lacked *733jurisdiction ... over appellant’s claim for a declaration that appellees would violate their contractual obligations.” Sharp v. Wein-berger, 798 F.2d 1521,1524-25 (D.C.Cir.1986) (Scalia, J.). It is settled that the court in this case also has no jurisdiction under 28 U.S.C. § 1491(a) to provide a declaratory judgment as relief. See First Hartford Corp. v. United States, 194 F.3d 1279, 1294 (Fed.Cir.1999) (reaffirming that the United States Court of Federal Claims “cannot grant nonmonetary equitable relief such as an injunction or a declaratory judgment, or specific performance.”). Therefore, to the extent that Paragraphs 33(a) and (b) of North Star’s April 18, 2001 First Amended Complaint attempt to seek a declaratory judgment, the court sua sponte dismisses this claim and strikes Paragraphs 33(a) and (b) and Paragraph (l)(a) and (b) of the Prayer for Relief.
3. North Star’s Administrative Procedure Act Claim
The United States Court of Federal Claims also does not have jurisdiction over North Star’s claim for relief under the APA since that statute is not money-mandating and affords only injunctive relief. Therefore, any such claim must be brought in a United States District Court. See James v. Caldera, 159 F.3d 573, 578-79 (Fed.Cir.1998); Murphy v. United States, 993 F.2d 871, 874 (Fed. Cir.1993). For this reason, to the extent that Paragraph 33(c) of the April 18, 2001 First Amended Complaint attempts to state a claim under the APA, the court sua sponte dismisses that claim and strikes Paragraph 33(c) and Paragraph 1(c) of the Prayer for Relief.
In light of the court’s rulings regarding North Star’s declaratory judgment and APA claims, and the disjointed nature of the remaining portions of the First Amended Complaint, the court hereby grants North Star leave for twenty (20) days in which to file a Second Amended Complaint stating with absolute clarity and brevity the precise nature of its breach of contract claim regarding the Consolidated Contract.
4. North Star’s Breach Of Contract Claim
It was well established in the Federal Circuit that the existence of a contract is a mixed question of law and fact. See, e.g., Castle v. United States, 301 F.3d 1328, 1337 (Fed.Cir.2002); Cienega Gardens v. United States, 194 F.3d 1231, 1239 (Fed.Cir.1998). The issues of contract formation necessarily raised by WAPA’s motion for summary judgment are whether WAPA, AEPCO, and North Star intended the Consolidated Contract to create a binding obligation concerning regulating service and whether the Consolidated Contract is “sufficiently definite to permit a determination of a breach and remedies.” See Modem Sys. Tech. Corp. v. United States, 979 F.2d 200, 202 (Fed.Cir. 1992); see also Restatement (second) Contracts § 33 (1981) (“The terms of a contract are reasonably certain if they provide a basis for determining the existence of a breach and for giving an appropriate remedy.”). If the Consolidated Contract is too indefinite to ascertain whether and when a breach has occurred and the appropriate remedy, as a matter of law, the court has no jurisdiction because there is no contract and the case should be dismissed.
The key provisions governing the disposition of this issue are Sections 14.3 and 21 of the Consolidated Contract. Section 14.3 of the Consolidated Contract states:
[WAPA] shall receive In-Kind Energy from AEPCO for service rendered in connection with the North Star Load in the amount of Non-Firm Energy equal to twenty percent (20%) of the actual metered Non-Firm Energy to serve the Harris Substation hourly metered load measured in megawatt hours (Mwh). The In-Kind Energy payment can be received by [WAPA] from (I) the Non-Firm Energy in excess of the hourly integrated North Star Load in Mwh, (ii) the Return Energy scheduled by [WAPA] to support the North Star Load when [WAPA] elects, on an hourly basis, to make Return Energy available, or (in) subsequent Non-Firm Energy schedules from AEPCO, if required.
Def.App. at 32-33 (Consolidated Contract at § 14.3).
Section 21 of the Consolidated Contact further provides:
*734Prior to the conclusion of the first year of normal operation of the North Star Plant, the Parties shall jointly establish an appropriate cost-based methodology to review, evaluate and periodically, if necessary, adjust the percentage associated with the In-Kind Energy payment. After one (1) year of normal operation, the percentage may be adjusted in accordance with said methodology.
Id. at 36-37 (Consolidated Contract at § 21).
As discussed above, Section 21 of the Consolidated Contract evidences the clear intent of WAPA, AEPCO, and North Star that the 20% formula methodology, described in Section 14.3, would be replaced after a year of “normal operation” at North Star with “an appropriate cost-based methodology to review, evaluate and periodically, if necessary, adjust the percentage associated with the In-Kind Energy payment.” Id.
The Federal Circuit has recognized that “some courts have invalidated so-called ‘agreements to agree,’ [however] the emerging view is that any agreement which specifies that certain terms will be agreed on by future negotiation is sufficiently definite, because it impliedly places an obligation on the parties to negotiate in good faith.” Aviation Contractor Employees, 945 F.2d at 1572 (citing 1 Corbin, Corbin on Contracts § 97 (1963 and 1990 Supp.) (advising courts to be slow to deny enforcement of a contract based on indefiniteness)). Therefore, the Federal Circuit has found that the obligation to negotiate in “good faith” gives the contract “certainty by allowing the courts to determine when a breach has occurred by determining whether the parties have negotiated in good faith.” Aviation Contractor Employees, 945 F.2d at 1572. In this case, the extensive negotiations that were undertaken to reach a consensus methodology for the “In-Kind Energy” payment for regulating service demonstrates sufficient definiteness to evidence a contract,11 although the issue of whether those negotiations in fact were conducted in “good faith” remains for another day when the court must determine whether and when a breach may have occurred. Therefore, the court is satisfied that the Consolidated Contract is sufficiently definite that the court has jurisdiction to ascertain whether and when a breach has occurred and what remedies, if any, are appropriate.
5. North Star’s Standing As A Third-Party Beneficiary
The court also must ascertain whether North Star has standing to enforce the terms of the Consolidated Contract since it was not a signatory. See Anderson v. United States, 344 F.3d 1343, 1351 (Fed.Cir.2003) (holding that in order to have “standing to sue the sovereign on a contract claim, a plaintiff must be in privity of contract with the United States.”). The Federal Circuit recently held in Federal Deposit Ins. Corp. v. United States, 342 F.3d 1313 (Fed.Cir.2003) that a third party beneficiary may have standing where “the contract ... reflects] the express or implied intention of the parties to benefit the third party____Third party beneficiary status is an ‘exceptional privilege’ and, to avail oneself of this exceptional privilege, a party must ‘at least show that [the contract] was intended for his direct benefit.’ ” Id. at 1319 (quoting Glass v. United States, 258 F.3d 1349 (Fed.Cir.2001)).
The court finds that the circumstances concerning the formation,12 execution,13 and language of the Consolidated Contract,14 and subsequent actions taken by the parties to *735implement its terms,15 together evidence that the obligations, rights, and benefits thereunder specifically were to accrue to North Star. Accordingly, the court holds that North Star has standing to enforce its rights as a third-party beneficiary under the Consolidated Contract.
B. WAPA’s Motion for Summary Judgment
WAPA seeks summary judgment on three grounds: (1) the Consolidated Contract and/or federal statute does not require that WAPA charge AEPCO (North Star) only actual costs for regulating services; (2) the Consolidated Contract does not require any retroactive adjustment of the rates charged AEPCO for North Star’s regulating service requirements; and (3) North Star’s counter-proposal to REVISION No. 1 has the legal effect of reinstating the methodology set forth in Exhibit H retroactively. See Def. Mot. S.J. at 2-3. In addition, WAPA seeks summary dismissal of North Star’s entire breach of contract claim because WAPA has continued to provide AEPCO with regulating service for the benefit of North Star. Id. at 3.
1. Standard For Decision
Summary judgment is required where there is “no genuine issue as to any material fact and ... the moving party is entitled to judgment as a matter of law.” RCFC 56(c). No genuine issue of material fact exists when a rational trier of fact could only arrive at one reasonable conclusion. See Matsushita Elec. Indus. Co. v. Zenith Radio Corp., 475 U.S. 574, 587, 106 S.Ct. 1348, 89 L.Ed.2d 538 (1986). The party moving for summary judgment has the burden initially of establishing no genuine disputes of material fact are in dispute. See Celotex Corp. v. Catrett, 477 U.S. 317, 323, 106 S.Ct. 2548, 91 L.Ed.2d 265 (1986). The Supreme Court has held, however, that “the mere existence of some alleged factual dispute between the parties will not defeat an otherwise properly supported motion for summary judgment; the requirement is that there be no genuine issue of material fact.” Anderson v. Liberty Lobby, 477 U.S. 242, 247-48, 106 S.Ct. 2505, 91 L.Ed.2d 202 (1986). Once the movant discharges this burden, if the non-moving party demonstrates specific facts showing a genuine factual dispute and produces sufficient evidence to raise a question that would alter the outcome of the case, summary judgment must be denied. See Matsushita, 475 U.S. at 586-88, 106 S.Ct. 1348. In making this determination, any doubt regarding a factual issue must be resolved in favor of the non-moving party. Id. The non-moving party, however, must “go beyond the pleadings and by [its] own affidavits, or by the ‘depositions, answers to interrogatories, and admissions on file,’ designate ‘specific facts showing that there is a genuine issue for trial.’ ” Celotex, All U.S. at 324, 106 S.Ct. 2548. Ultimately, “[o]nly disputes over facts that might affect the outcome of the suit ... will properly preclude the entry of summary judgment. Factual disputes that are irrelevant or unnecessary will not be counted.” Anderson, All U.S. at 248, 106 S.Ct. 2505.
2. Resolution Of WAPA’s Motion For Summary Judgment
a. The Consolidated Contract Does Not Require That WAPA Charge Only “Actual Costs” For Regulating Service.
North Star claims that Section 21 of the Consolidated Contract requires that WAPA must charge only “actual costs.” Again, Section 21, in relevant part, states that:
Prior to the conclusion of the first year of normal operation of the North Star Plant, the Parties shall jointly establish an appropriate cost-based methodology to review, evaluate and periodically, if necessary, adjust the percentage associated with the In-Kind Energy payment.
Def.App. at 36-37 (Consolidated Contract at § 21) (emphasis added).
No provision of the Consolidated Contract, including Section 21, defines the term “ap*736propriate cost-based methodology,” “cost-based,” or “actual cost.” WAPA argues that since the “contract does not state ... a ‘cost-based methodology,’ it must be based solely upon WAPA’s actual cost (Le., incremental production) of providing regulation.” Def. Mot. S.J. at 17-18. North Star counters that “cost-based” is a term of art in the utility industry that “reflects a utility’s capital investment, together with its operation and maintenance ... expenses and is distinguished from market-based rates.” PL Opp. at 13. In support, North Star proffers two industry sources that define “cost-based.” The first states that “cost-based” are the costs to the vendor of providing the service, “since this is the only cost for which just compensation can be claimed.” Id. at 20-21 (quoting Bonbright et al., Principles of Public Utility Rates 114 (2d ed.1988)). The second source describes a “cost-based” rate as “the amount of money required to fund a utility’s operations, including expense liabilities of all kinds, depreciation, and a fair rate of return.” Id. at 21 (quoting Glossary P.U.R. for Utility Management 30 (Diane S. Boiler ed.1992)).
Reviewing relevant decisions of the Federal Circuit, the court has found that the meaning of “cost-based” is dependent on the context in which it is used. See, e.g., Raney v. Federal Bureau of Prisons, 222 F.3d 927, 931-32 (Fed.Cir.2000) (contrasting the term “cost-based approach,” in the context of calculating attorney’s fees with “market-rate fees”); Florida Power & Light Co. v. United States, 198 F.3d 1358, 1359-62 (Fed.Cir.1999) (considering whether “cost-recovery based pricing” includes other components); American Tel. and Tel. Co. v. United States, 124 F.3d 1471, 1474A75 (Fed.Cir.1997) (contrasting between a cost-based contract that would entitle a party to allowable costs in performing the contract, plus an appropriate profit margin with “fixed price-type” contracts), vacated, 136 F.3d 793 (Fed.Cir.1998); Yancey v. United States, 915 F.2d 1534, 1542 (Fed. Cir.1990) (affirming that standard costs “include no allowance for commercial value”); PPG Indus., Inc., v. Celanese Polymer Specialties Co., Inc., 840 F.2d 1565, 1570 (Fed. Cir.1988) (finding that a cost-based standard for attorney’s fees includes cost plus overhead); Smithr-Corona Group v. United States, 713 F.2d 1568, 1576 (Fed.Cir.1983) (noting “The legislative history [of the Trade Agreements Act of 1979] reflects a long felt and understandable congressional distrust of cost as a basis for the computation of dumping margins ... cost is subject to manipulation and Congress has recognized its inherent unreliability.”). And, as the decision of the United States Court of Appeals for the Ninth Circuit in Trinity County Pub. Util. Dist. v. Harrington, 781 F.2d 163, 168 (9th Cir.1986) illustrates, a rate based on the “cost” of hydroelectric power from an individual plant operated by WAPA can differ substantially from the “actual costs” of hydroelectric power from a “system,” such as the Boulder Dam Project. Accordingly, plaintiffs in Trinity County were found “not entitled to preferential rates based on the operating costs of [two WAPA] plants alone, as opposed to operating costs of the [Central Valley Project].” Id. at 168.
The Federal Circuit has held that the general rules of interpretation apply when the United States is a party to a contract and begins with the plain language thereof. See Scott Timber Co. v. United States, 333 F.3d 1358, 1366 (Fed.Cir.2003). When the terms of a contract are “phrased in clear and unambiguous language, they must be given their plain and ordinary meaning[J” Coast Fed. Bank, FSB v. Unites States, 323 F.3d 1035, 1038 (Fed.Cir.2003) (citing McAbee Constr., Inc. v. United States, 97 F.3d 1431, 1435 (Fed.Cir.1996)). On the other hand, when such language is “susceptible to more than one reasonable interpretation, it contains an ambiguity.” Metric Constructors, Inc. v. National Aeronautics and Space Admin., 169 F.3d 747, 751 (Fed.Cir.1999). In this case, the court is compelled to conclude that the term “cost-based” may have more than one. meaning and, therefore, is ambiguous as a matter of law.
If an ambiguity exists, then the court must determine whether the ambiguity is patent or latent. The doctrine of patent ambiguity is “an exception to the general rule of contra proferentem which construes an ambiguity against the drafter ... An ambiguity is patent if ‘so glaring as to raise a duty to in*737quire[.]’ If an ambiguity is ... latent, [the Federal Circuit] enforces the general rule.” Metric, 169 F.3d at 751 (citations omitted); see also Comtrol, Inc. v. United States, 294 F.3d 1357, 1365 (Fed.Cir.2002). (“An patent ambiguity is one that is glaring, substantial, or patently obvious.”). The court also holds that the term “cost-based” in this case is patently ambiguous.
The methodology used by WAPA to determine the “In-Kind Energy” payment for its regulating service is both material and relevant to whether there was adequate consideration to support WAPA’s promise to provide these services to AEPCO for North Star’s benefit. Surprisingly, there is no evidence in the record even suggesting that either AEPCO or North Star sought any clarification of this essential contractual term at any time before it was executed. Therefore, the court declines to construe “cost-based” against WAPA, the drafter, under the circumstances. North Star could have required the details of WAPA’s methodology regarding the “In-Kind Energy” payment for regulating service to be specified before it approved the terms of the Consolidated Contract or started the construction and operation of its mill. Instead, North Star imprudently chose to proceed without having a definitive agreement of what components would be included in an appropriate cost-based methodology or how such a methodology would be calculated. Therefore, North Star may not now claim that only “actual costs” were contemplated to be included in the rate that WAPA would charge for regulating service so critical to North Star’s operation. Accordingly, the court grants summary judgment for WAPA on this issue and holds that the Consolidated Contract does not require that WAPA charge only “actual costs” for regulating service.
b. No Federal Statute Requires That WAPA Charge Only “Actual Costs” For Regulating Service.
North Star also claims that four federal statutes require WAPA only to charge “actual costs” for regulating service. See April 18, 2001 First Amended. Complaint, at 116. “The unadorned language of a statute is [the] starting point for statutory interpretation.” Butterbaugh v. Department of Justice, 336 F.3d 1332, 1337 (Fed.Cir.2003). When a court is required to interpret a statute, the words are given their “ ‘ordinary, contemporary, common meaning,’ absent an indication that Congress intended them to bear some different import.” Williams v. Taylor, 529 U.S. 420, 431, 120 S.Ct. 1479, 146 L.Ed.2d 435 (2000) (citations omitted). If a statute’s language is “plain and unambiguous” with respect to the issue at hand, then statutory interpretation is at an end. Clary v. United States, 333 F.3d 1345, 1348 (Fed.Cir.2003). With this guidance in mind, the court now examines each federal statute that North Star claims require WAPA to charge only “actual costs” for regulating service.
First, North Star asserts that the Reclamation Act of 1902, 32 Stat. 388, 389 (codified at 43 U.S.C. § 461 (2000)) “provide[s], among other things that WAPA’s rates and charges must be based upon its cost of providing service.” First Amended Complaint at H 31. This statute requires, however, only that the Secretary of Interior charge users of water from the federal irrigation projects rates that are “determined with a view of returning to the reclamation fund the estimated cost of construction of the project[.]” 43 U.S.C. § 461. Therefore, the court holds, as a matter of law, that this Act is irrelevant to the breach of contract claim asserted in this case, which concerns the methodology regarding the “In-Kind Energy” payment for electric power regulating service.
Next, North Star contends that the Reclamation Project Act of 1939, 53 Stat. 1187, 1193 (codified at 43 U.S.C. § 485h(c) (2000)) requires that WAPA charge only “actual costs” for regulating services. This statute states only that: “Any sale of electric power ... shall be ... at such rates as [in the Secretary of Energy’s] judgment will produce power revenues at least sufficient to cover an appropriate share of the annual operation and maintenance costs, interest ... and such other charges as the Secretary deems proper[.]” 43 U.S.C. § 485h(c) (emphasis added). The court holds that the plain language of this statute applies only to sales of electric power, i.e., generation, not sales of transmission or ancillary services, such as regulating service.
*738North Star also argues that 68 Stat. 143 (codified at 43 U.S.C. Ch. 12A (2000)), which consolidated the Parker-Davis Project with other similar federal hydroelectric projects, requires that WAPA must obtain “reasonable returns” in contracts for such service. See 43 U.S.C. § 617d(a). The court finds that the rates for Parker-Davis Project transmission services certainly must include “reasonable returns,” however, such services did not include regulating service at the time the Consolidated Contract was executed. See FERC Order No. 888; see also Def.App. at 48-49; WAPA Definitions at A-2, A-3.
Finally, North Star claims that the DOE Organization Act, which transferred the marketing functions of federal PMAs from DOI to DOE, is relevant to the methodology implemented regarding the “In-Kind Energy” payment for WAPA’s regulating service. This Act, however, says nothing about what WAPA should charge for any services, much less regulating service. Consequently, the court holds that this statute also is irrelevant to the issue of what the “In-Kind Energy” payment for WAPA’s regulating service should be.
For these reasons, the court grants WAPA’s motion for summary judgment with respect to each of these four statutes does not require WAPA to charge only “actual costs” for regulating service and dismisses Paragraph 31 of the April 18, 2001 First Amended Complaint and strikes Paragraph 31 and Paragraph 1(b) in the Prayer for Relief.
c. The Consolidated Contract Does Not Provide For Retroactive Refunds, However, Evidence In The Record . Suggests That The Parties May Have Agreed Otherwise.
WAPA also seeks summary judgment because “it is undisputed that the [Consoli-
dated Contract] contains no provision for ret-roactivity.” Def. Mot. S.J. at 24. North Star concedes, as it must, that neither the Consolidated Contract nor Amendment No. 3 contains the word “retroactive,” but instead argues that Section 21 of the Consolidated Contract requires that the methodology for “In-Kind Energy” payment for WAPA’s regulating service must be “cost-based” and that a “cost-based” methodology implicitly requires a retroactive adjustment upward or downward once “actual costs” are determined. See PI. Opp. at 23. To support this contention, North Star submitted excerpts from the deposition of Mr. James Rein, AEP-CO’s former Director of Power Services, who testified that WAPA insisted on using the word “cost-based” in Section 21 of the Consolidated Contract because “they just did not know how to price regulation service, so they wanted to have as much flexibility to go up or down, whatever it would be, whenever they determined what the cost should finally be.” See PLApp. D (Rein Dep. at 17). With respect to Section 14.3 of the Consolidated Contract, Mr. Rein further testified that WAPA intended that there would be a reconciliation or “true up” of the amount collected under this Section once a determination was reached regarding WAPA’s “actual costs” and that the initial 20% formula was intended only to cover WAPA’s interim costs, which would be adjusted after the parties had a year of experience under the Consolidated Contract. Id. at 17-18. Consequently, North Star argues that WAPA is not entitled to summary judgment as to whether the Consolidated Contract requires retroactive refunds for regulating service charges because material facts are at issue. The court agrees, for these and other reasons.16
The Consolidated Contract does not include any integration clause and Section 21 *739specifically states that the “methodology [would be used] to review, evaluate and periodically, if necessary, adjust the percentage associated with the In-Kind Energy payment.” Def.App. at 36-37 (Consolidated Contract at ¶ 21). In addition, the Consolidated Contract contemplates “amendments to which the party may agree from time to time.” See Def.App. at 22 (Consolidated Contract § 4.4). Therefore, the parol evidence rule need not be strictly enforced in this case. See McAbee Constr., Inc. v. United States, 97 F.3d 1431, 1434 (Fed.Cir.1996) (extrinsic evidence is “especially pertinent in instances where ... the writing itself contains no recitals or other evidence testifying to its intended completeness and finality.”) (quoting David Nassif Assoc, v. United States, 214 Ct.Cl. 407, 557 F.2d 249, 256 (1977)). Moreover, conflicting evidence in WAPA’s internal documents, apparently overlooked by both parties, suggests that WAPA may have agreed that any refunds for regulating service would be applied retroactively. Compare Def.App. at 204-05 (May 27, 1999 letter from Jean Gray, WAPA’s Resource Manager, to AEPCO and counsel for North Star) (“The contract makes no provisions for retroactive adjustments and therefore [WAPA] disagrees with [North Star’s] proposal [to ‘true-up’ for In-Kind payments to WAPA to date] ... but putting a ‘collar’ on the annual adjustment of prices to plus or minus three percent is a good idea. However, [WAPA] and AEPCO should jointly review and change the price in the event a sustained change in short-term energy prices occurs.”); with Def-App. at 252 (Oct. 16, 2001 memo from Jean Gray regarding North Star Steel Contract No. 10590, Proposed Revision to Exhibit H) (“We [WAPA] agreed to a retroactive application of the new methodology back to October of 2000.”) (“When we retroactively applied the In-Kind Energy percentages at the end of June 2001 to implement the proposed revision to Exhibit H, [North Star] also got a credit on their non-firm transmission bill of $6,747.38.”).
For these reasons, WAPA’s motion for summary judgment regarding whether the Consolidated Contract requires retroactive refunds is denied.
d. Material Facts Are At Issue Regarding The Effect Of North Star’s Rejection Of REVISION No. 1.
In addition, WAPA seeks summary judgment with respect to whether North Star’s rejection of REVISION No. 1 reinstates Exhibit H as the methodology under which WAPA’s payment for regulating service should be determined, as of October 1, 2000. See Def. Mot. S.J. at 3, 28-29. To understand this contention, a brief review of the three methodologies used by the parties to determine the “In-Kind Energy” payment is helpful.
First, from the period from July 1, 1997 to July 1, 1998, the terms of the Consolidated Contract provide that AEPCO (North Star) is obligated to pay WAPA for regulating services on a 20% payment methodology, as described in Section 14 of the Consolidated Contract. See Def-App. at 31-33 (Consolidated Contract at § 14); see also DPF ¶¶ 14, 16. From July 1, 1998 to July 31, 1999, AEPCO and WAPA continued to use the 20% payment methodology since the parties were unable to reach an agreement as to “an appropriate cost-based methodology” to determine the “In-Kind Energy” payment. See DPF at ¶¶ 17-20.
Second, on September 15, 1999, WAPA and AEPCO (North Star) agreed to a new methodology, retroactively, effective as of August 1, 1999, based on either an “In-Kind Energy” payment of 19.67%, assuming the value of “In-Kind Energy” up to $1.5 million, as described in Exhibit H and Attachment H-l, or an “In-Kind Energy” payment of 9.83% based on the value of “In-Kind Ener-
*740gy” up to $750,000, as described in Attachment H-2. See DPF ¶¶ 21-23, 27; PSI at ¶ 27. Exhibit H was utilized from August 1, 1999 to October 1, 2000. Id. On August 1, 2000, WAPA notified AEPCO (North Star) that WAPA was re-evaluating the methodology for the “In-Kind Energy” payment because of increases in the spot market. See DPF at ¶ 28. WAPA further claims that a new “oral” methodology was negotiated in January 2001 and made retroactive to October 1, 2000. See DefApp. at 230-33; DPF at If 29. North Star, however, disputes that any agreement was reached regarding a methodology to replace Exhibit H. See PSGI at 1129.
Third, on June 29, 2001, WAPA unilaterally announced that it was implementing this new methodology, retroactive to October 2000, set forth in REVISION No. 1, dated August 7, 2001. Id. at U 30. This methodology resulted in a decrease of the “In-Kind Energy” scheduled from 6,051,475 kWh to 3,626,202 kWh; a credit for non-firm wheeling charges; a reduction in the value of North Star’s “In-Kind Energy” obligation for fiscal year 2000 to $305,850 or a savings of $1,194,150 over the amount charged under Exhibit H. See Def. Mot. S.J. at 13; DPF at ¶ 33. REVISION No. 1 was rejected by AEPCO on August 7, 2001. See PSGI at ¶¶ 29-31. North Star, however, made all required payments thereunder, albeit under protest. Compare DPF at U 31 (“[North Star] accepted, and has continued to accept, WAPA’s implemented retroactive adjustments of the new methodology, as of June 29, 2001. ”) with PSGI at ¶ 31. On October 17, 2001, North Star presented WAPA with a counterproposal that would not require it to pre-schedule anticipated “In-Kind Energy” needs in advance, which WAPA has characterized as “a substantial change to the contract’s scheduling methodology[.]” See Def. Mot. S.J. at 29; see also DPF at ¶¶ 34-37.
Because material facts are in dispute as to the underlying facts, the court denies WAPA’s motion for summary judgment with respect to whether North Star’s rejection of REVISION No. 1 reinstates the methodology in Exhibit H.
e. Material Facts Are At Issue Regarding The Effect Of WAPA’s Continuation To Provide North Star With Regulating Service.
Finally, WAPA asserts that North Star’s entire complaint should be “summarily dismissed as a matter of law” because WAPA continues to provide regulating service at “reasonable cost-based charges.” Def. Mot. S.J. at 3. As discussed herein, whether the methodology utilized by WAPA to determine the “In-Kind Energy” payment for regulating service complies with the Consolidated Contract or otherwise is “reasonable” is very much at issue. Accordingly, the court holds there is no basis to dismiss North Star’s contract claim on this ground.
C. Disposition of North Star’s Motion to Strike
On January 22, 2002, North Star moved to strike two portions of WAPA’s motion for summary judgment. First, North Star moved to strike WAPA’s summary judgment motion as to whether North Star’s counter-proposal to REVISION No. 1 constitutes a rejection of that payment methodology. See PL Mot. at 2-4. In light of the court’s denial of WAPA’s motion for summary judgment on this issue, North Star’s motion to strike is denied as moot. See RCFC 12(f).
North Star also moved to strike footnote 5 of the Defendant’s Proposed Findings of Un-eontroverted Facts, which states: “[North Star] is currently unable to run its mill at full operation and instead is operating at reduced capacity since approximately December 2000, due in large part to its violation of Arizona clean-air standards.” DPF at U 33 n. 5. North Star admitted that it is unable to run its plant at full capacity, but asserts the cause is high energy costs. See PLApp. C at 10 (Sarafolean Aff. at U 22). The court fails to see the relevance of footnote 5 to the pending motion or the contract claim at issue. Accordingly, this aspect of North Star’s motion to strike is granted. See Fed. R. Ev. 401-03.
CONCLUSION
Since there is no just cause for delay, to the extent that Paragraphs 33(a) and (b) of *741the North Star’s April 18, 2001 First Amended Complaint attempt to state a claim for declaratory judgment that claim is dismissed and Paragraphs 33(a) and (b) and Paragraphs 1(a) and (b) of the Prayer for Relief are stricken. In addition, to the extent that Paragraph 33(c) of North Star’s April 18, 2001 First Amended Complaint attempts to state a claim under the APA, it is dismissed and Paragraph 33(c) and Paragraph 1(c) of the Prayer for Relief are stricken. In light of the aforementioned rulings and disjointed nature of the remaining portions of the April 18, 2001 First Amended Complaint, however, the court hereby grants North Star leave for twenty (20) days in which to file a Second Amended Complaint stating with absolute clarity and brevity the precise nature of its breach of contract claim regarding the Consolidated Contract.
WAPA’s December 7, 2001 Motion for Summary Judgment is granted to the extent that the court holds that neither the Consolidated Contract nor the federal statutes set forth in Paragraph 21 of the April 18, 2001 First Amended Complaint require that WAPA charge only “actual costs” for regulating service under the Consolidated Contract. Accordingly, to the extent that Paragraphs 31, 33(a) and (b) of North Star’s April 18, 2001 First Amended Complaint attempt to state such claims, they are dismissed and Paragraphs 31, 33(a) and (b) and Paragraph 1(c) of the Prayer for Relief are stricken.
Because material facts are at issue as to whether the parties agreed that any refunds for WAPA’s regulating service would be applied retroactively; the effect of North Star’s rejection of REVISION No. 1; and WAPA’s continuing to provide North Star with regulating service, these remaining bases for WAPA’s December 7, 2001 Motion for Summary Judgment are denied. Accordingly, North Star’s January 22, 2002 Motion to Strike regarding WAPA’s summary judgment motion as regarding the effect of North Star’s counterproposal to REVISION No. 1 is denied as moot. North Star’s Motion to Strike footnote 5 of Defendant’s Proposed Findings of Uncontroverted Facts is granted, as that footnote is irrelevant to WAPA’s December 7, 2001 Motion for Summary Judgment, as well as the remaining issues before the court.
The Clerk of Court is hereby ordered to enter judgment in accordance with this Memorandum Opinion.
IT IS SO ORDERED.
. The court found the following landmark decisions to be most helpful in understanding how the electric utility industry became one of the most highly regulated in our economy. See, e.g., New York v. Federal Energy Regulatory Comm'n, 535 U.S. 1, 4-16, 122 S.Ct. 1012, 152 L.Ed.2d 47 (2002) (discussing the Public Utility Regulatory Policies Act of 1978, Pub.L. No. 95-617, 92 Stat. 3117 (codified at 16 U.S.C. §§ 2601 et seq. (2000)), the Energy Policy Act of 1992, Pub.L. No. 102-486, 106 Stat. 2776 (codified at 16 U.S.C. § 824 et seq. (2000)), the jurisdiction of Federal Regulatory Energy Commission ("FERC”), and the impact of FERC Order No. 888; United States v. City of Fulton, 475 U.S. 657, 659-64, 106 S.Ct. 1422, 89 L.Ed.2d 661 (1986) (discussing the history of the Flood Control Act of 1944, ch. 665, 58 Stat. 887 (codified at 16 U.S.C. § 460d (2000), 33 U.S.C. §§ 701-09 (2000), and 43 U.S.C. § 390 (2000)); and the United States Department of Energy Organization Act of 1977 ("DOE Organization Act”), Pub.L. No. 95-91, 91 Stat. 565 (codified at 42 U.S.C. §§ 7101 et seq. (2000)); Otter Tail Power Co. v. United States, 410 U.S. 366, 93 S.Ct. 1022, 35 L.Ed.2d 359 (1973) (discussing the Federal Power Act of 1935, 49 Stat. 863 (codified at 16 U.S.C. §§ 791 et seq. (2000)), and its relationship to federal antitrust laws); Detroit Edison Co. v. Federal Energy Regulatory Comm., 334 F.3d 48, 50-51 (D.C.Cir.2003) (discussing FERC Order No. 888); Southern California Edison Co. v. United States, 226 F.3d 1349, 1351-54 (Fed.Cir.2000) discussing the Boulder Canyon Project Act of 1928, Pub.L. No. 70-642, 45 Stat. 1057 (codified at 43 U.S.C. §§ 617-617v (2000)) and the Boulder Canyon Project Adjustment Act of 1940, Pub.L. No. 76-756, 54 Stat. 774 (codified at 43 U.S.C. §§ 618-618p (2000)); United States v. Tex-La Elec. Coop., Inc., 693 F.2d 392, 395-97 (5th Cir.1982) (also discussing the Flood Control Act of 1944).
. Firm power is “electric energy which is intended to have assured availability to the customer to meet all or any agreed portion of its load requirements ... 'Firm power’ is power which is guaranteed by the supplier to be available at all times[.]” Salt Lake City v. Western Area Power Admin., 926 F.2d 974, 980 n. 4 (10th Cir.1991). Non-firm power is that which may be interrupted for any reason at any time and its availability is unpredictable. See Pacific Gas & Elec. Co., 53 FERC 11 61146, 1990 WL 319356 (1990) (“[N]on-firm service is interruptible.") (citation precedes note 156 in the text).
. Transmission is "[a]n interconnected group of lines and associated equipment for the movement or transfer of electric energy between points of supply and points at which it is transformed for delivery to customers or is delivered to other electric systems.” June 16, 1998 WAPA Transmission and Ancillary Services Rate Adjustment Brochure ("June 16, 1998 WAPA Brochure”), Appendix A ("WAPA Definitions”), Definitions at A-3. Transmission service includes "Point-to-Point Transmission Service provided on a Firm or Non-Firm basis.” Id.
. Ancillary services are "services that are necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operations of the Transmission Provider's Transmission system in accordance with Good Utility Practice." WAPA Definitions at A-1.
. Regulation and Frequency Response Service entails "following the moment-to-moment variations in the demand or supply in a Control Area (i.e., an electric system bounded by interconnections metering and telemetry, capable of controlling generation to maintain its interchange schedule with other Control Areas and contributing frequency regulation of the Interconnection) and maintaining scheduled interconnection frequency." WAPA Definitions at A-l & A-2.
. WAPA’s December 7, 2001 Motion for Summary Judgment hereinafter is referred to as "Def. Mot. S.J.”; WAPA’s December 7, 2001 Proposed Findings of Fact as "DPF”; and WAPA’s December 17, 2001 Appendix as "Def.App.”
North Star’s January 23, 2002 Answer in Opposition hereinafter is referred to as "PI. Opp.;” North Star's January 22, 2002 Appendix as “PL App.;” North Star’s January 22, 2002 Statement of Genuine Issues as "PSGI;" and North Star January 22, 2002 Motion to Strike as "PL Mot.”
WAPA’s July 5, 2002 Response to Pl. Opp. hereinafter is referred to as "Def. Resp.”
. A load refers to "[a]n end-use device or customer that receives power from the electric system.” WAPA Definitions at A-l.
. The load variation for a typical WAPA wholesale customer was in the range of 6 MW. See Def.App. at 169-81; see also DPF at ¶ 20 n. 3. North Star’s load, however, was in the range of 85 MW. Id.
. The court has identified four cases in which the contractual rates for power sold by PMAs have been contested in the United States Court of Federal Claims, however, none of them had to confront the jurisdictional issues discussed herein. See, e.g., Southern California Edison v. United States, 58 Fed.Cl. 313, 319-20 (2003) (holding that the court’s jurisdiction under the Tucker Act was not "ousted nor supplanted by the Ninth Circuit under 16 U.S.C. § 839 f(e)(5)."); City of Burbank v. United States, 47 Fed.Cl. 261, 269 (2000) (dismissing contract claim for lack of subject matter jurisdiction under the Northwest Power Act), rev'd, 2Ti F.3d 1370 (Fed.Cir.2001) (holding the court had jurisdiction); Southern California Edison Co. v. United States, 43 Fed.Cl. 107, 118-21 (1999) (determining where subject matter jurisdiction was not challenged, the methodology WAPA used to calculate refunds due under a longer term contract for the purchase of electricity generated at Hoover Dam was contrary to applicable regulations), aff d in part and rev'd in part, 226 F.3d 1349 (Fed.Cir.2000) (finding WAPA’s method of allocating a contractual surplus for pre-FERC contracts entered between 1941 and 1960 to be reasonable without considering subject matter jurisdiction); Puget Sound Power & Light Co. v. United States, 23 Cl.Ct. 46 (1991) (holding challenge to extra regional sales of surplus power by the Bonneville Power Administration was dismissed because the Ninth Circuit had exclusive jurisdiction under the Northwest Power Act), aff d on other grounds, 944 F.2d 912 (Fed.Cir.I991) (holding that an immediate review by the Ninth Circuit of its jurisdiction was required and/or a motion to transfer in light of the collateral order doctrine).
. Judicial review of certain final actions of the Bonneville Power Administration has been committed to the exclusive jurisdiction of the United States Court of Appeals for the Ninth Circuit. See 16 U.S.C. § 839 f(e)(l); see also Southern California Edison v. United States, 58 Fed.Cl. 313,317-19(2003).
. See, e.g., Def.App. at 16-49 (Consolidated Contract §§ 2.6, 2.9, 2.10, 2.12, 2.13, 4.5, 4.13, 4.19, 5.1, 5.3.2, 6.2, 6.3, 14.1, 19, and 34).
. See, e.g., Def.App. at 119-20 (Rein Dep. at 17-18); Def.App. at 121-58; Pl.App. B at 6-8 (Rein Aff. at 11 7 # 11-13); Pl.App. C at 5-6 (Sarafolean Aff. at H1I 8-10); Pl.App. F (Deposition of Anthony Montoya, WAPA Representative, at 28); Pi. App. L (Anatomy of Negotiating a Contract AEP-CO/North Star Memorandum at 148-49); Pi. App. M (Dec. 15, 1994 WAPA email).
. See, e.g., Def.App. at 119-20 (Rein Dep. at 17-18); Def.App. at 121-58; Pl.App. B at 8 (Rein Aff. at 117 #13); Pl.App. C at 6-7 (Sarafolean Aff. at 111111-12).
. See, e.g., Def.App. at 16-49 (Consolidated Contract §§ 2.6, 2.9, 2.10, 2.12, 2.13, 4.5, 4.13, 4.19, 5.1, 5.3.2, 6.2, 6.3, 14.1, 19, and 34).
. See, e.g., Def.App. at 159-233; Pl.App. B at 8-9 (Rein Aff. at ¶ 7 # 15, 18); Pl.App. C at 7-9 (Sarafolean Aff. at ¶¶ 14-20); Pl.App. K at 609-11 (May 11, 1999 letter from North Star’s counsel to WAPA).
. The Consolidated Contract does not define "dynamic regulating services" or "regulating service.” See Def.App. at 31-32 (Consolidated Contract at § 14.1). In this litigation, WAPA has defined regulating service as “the raising or lowering [of] on-line generation as necessary to follow the moment-by-moment changes in load to maintain the balance between resources and load within a Control Area." DPF at H 10; see also WAPA Definitions at A-2, cited infra at n. 5.
North Star asserts, however, that "Control Area Regulating and Frequency Response Service" is "the continuous balancing of resources and load by committing online generation whose [sic] output is raised or lowered (predominately through the use of Automatic Generation Control equipment) as necessary to follow the moment-to-moment changes in load. This definition is based on transmission ancillary service as described [in FERC Order No. 888].” PLApp. A at *7392 (Jan. 21, 2002 Affidavit of Charles Liebold, North Star Consultant ("Liebold Aff.”), at H 3). North Star’s consultant contests, however, that FERC’s definition "does not accurately describe the actual function of Regulating Service or the manner in which the service is performed” and that "regulation service in the [Consolidated Contract] is a different product than the regulation service offered in WAPA’s [December 7, 1998] OATT [Open Access Transmission Tariff].” Id.; see also App. B at 10 (Rein Aff. H 7 # 20) ("WAPA’s OATT methodology is market based, not cost based.”); PSGI at H 20.