California ex rel. Brown v. United States

OPINION AND ORDER SMITH, Judge. Plaintiffs bring this breach of contract case to recover refunds from overcharges of electricity prices during the Energy Crisis of 2000-2001 in the state of California. In this — 20 — liability phase, the Court held a four week trial in San Francisco, CA. After consideration of all the evidence, briefs and arguments, the Court finds that the United States breached its contract with the Plaintiffs. INTRODUCTION During the summer of 2000 through 2001, California experienced a power crisis which dramatically affected the price of electricity. During that time, the electricity used in the California market was sold in two new centralized auction electricity markets, one run by the California Independent System Operation Corporation (“ISO”) and one run by a centralized market called the California Power Exchange (PX). In both of these markets, participants signed contracts binding themselves to the terms of tariffs that governed the operations of the markets. Plaintiffs now bring these suits based upon these contracts and tariffs and seek refunds of the overcharges on electric power the Agencies sold between May 1, 2000 and June 20, 2001 in wholesale markets operated by the PX and ISO. Specifically, in their complaint, Plaintiffs allege two breach of contract claims. First, Plaintiffs allege breach by anticipatory repudiation. Second, Plaintiffs allege a present breach, as well as declaratory relief claims. The Court held trial in San Francisco, CA. The record in this ease, including all the briefing, the trial testimony, and the exhibits is extensive. Much of the evidence at trial was to provide the Court with an explanation of the market structure and the economics that gave rise to Plaintiffs’ claims. However, Plaintiffs assert that most of the evidence is not necessary to decide the issues before the Court. Despite the daunting complexity of the tariffs, at least to one not schooled in utility economics, of the transaction at issue, and of the variety of litigation related to the power crisis, Defendant also asserts that these cases are quite simple. Defendant argues that the agencies have no obligation to pay the Plaintiffs anything. Instead, Defendant argues that the contracts signed by the agencies were with the ISO and the PX, not with the Plaintiffs. Further, Defendant argues that by Plaintiffs’ own admission, no obligations have arisen under the contracts. Even though both parties claim that these eases are quite simple, however, in order to fully understand this ease, the Court must delve into the novel utility markets created by the State of California, as well as the economy of the time. The Court will, therefore, begin its opinion with the parties in this litigation, the history of the electricity market, and then the tariffs. The Court will thereafter move into the FERC and Ninth Circuit litigation and, thereafter, the issues before the Court. BACKGROUND AND FINDINGS OF FACT A. The Parties 1. The Plaintiffs Plaintiffs Pacific Gas and Electric (“PG & E”), Southern California Edison Company (“SCE”) and San Diego Gas & Electric (“SDG & E”) are investor owned utilities (IOUs) engaged in the purchase, transmission, distribution, and sale of electric energy within California. The IOUs provide electric power to the vast majority of California’s businesses and residences, and together serve about 70 percent of all electric customers in the State. PG & E is one of the nation’s largest IOUs, providing electricity to approximately 15 million people in northern and central California. SCE serves approximately 15 million people in 15 Southern California counties. SDG & E services approximately 14 million people in both San Diego County and southern Orange County. Plaintiffs the People are represented by the California Attorney General’s Office on behalf of the ratepayers of the State and the California Energy Resources Scheduling Division (“CERS”). CERS is a state governmental entity created in January 2001 to serve as the power buyer of last resort for the State’s electricity customers. CERS is a division within California’s Department of Water Resources (“DWR”). — 21 — 2. The Agencies The United States is defending Plaintiffs’ claims on behalf of Bonneville Power Administration (“BPA”) and Western Area Power Administration (“WAPA”), which are federal agencies responsible for marketing hydroelectric power generated by certain federal and non-federal facilities. BPA markets more than 20,000 megawatts of power per year generated by a nuclear power plant and 31 federal hydro projects that constitute the federal Columbia River power system in the Pacific Northwest. WAP A markets and transmits about 10,000 megawatts of power per year from some 55 hydro power plants to a 15-state region in the central and western United States, selling about 40 percent of all the hydroelectric power generated in that region. B. Acquisition of Power from the Agencies Prior to 1998 Prior to 1998, the IOUs were vertically integrated. Specifically, the IOUs owned and operated their own generation, transmission, and distribution systems. The power rates which the IOUs could charge were regulated by the California Public Utilities Commission (“CPUC”). For the wholesale power bought and sold by the IOUs on the Western transmission grid, FERC regulated such activities. See CPUC v. FERC, 462 F.3d 1027 (9th Cir.2006). During this time, the IOUs generated through their own facilities the power needed to serve their customers. To meet their demand, if necessary, the IOUs would purchase electricity from other suppliers. In order to effectuate the sale, the IOUs and out-of-state suppliers would enter into bilateral contracts. The IOUs had such agreements with BPA and WAP A, and some IOUs continue to do so today. The bilateral contracts negotiated price and volume, the specific source from which the power would be delivered to the transmission grid, and defined the transmission path through which the power would be distributed. In order to determine how much was owed, the parties used a settlement process basing the amount owed on metering data showing how much power was actually generated, transmitted, and received. C. Acquisition of Power from the Agencies After 1998 In 1996, California enacted Assembly bill 1890 (“AB 1890”), which restructured California’s electric power markets. This bill created two new wholesale electricity markets: the PX and the ISO. Both the PX and ISO are non-profit, public benefit corporations organized under California law and they are FERC jurisdictional public utilities which commenced operations in 1998. Under AB 1890, the IOUs were required to “unbundle” their functions by separating their generation, transmission, and distribution functions. The IOUs had to divest substantial amounts of their power generation facilities and to transfer control of their transmission systems to the ISO. In addition, the IOUs were not permitted to use their remaining generating capacity to serve their customers, but instead were required to sell all of the power they generated, and buy substantially all of the power they needed through the PX and ISO. This buy-sell requirement applied only to the three IOUs in this ease. 1. The PX The PX was deemed a public utility pursuant to the Federal Power Act (FPA) and, as such, its operations and transactions were governed by a tariff approved by FERC. The PX was a nonprofit corporation that provided a centralized clearinghouse, similar to a stock exchange, which facilitated electricity transactions between sellers and buyers. The trading parties were called “market participants” and, therefore, the IOUs, CERS, and the Agencies all were considered Market Participants who bought and sold power in the PX. Pursuant to its FERC-regulated Tariff, the PX operated daily auctions in which buyers purchased power for the following day, as well as hourly auctions that allowed buyers to make any necessary adjustments to purchases. As with any trading exchange, sellers submitted offers (“bids”) to sell power in each auction and buyers submitted demand — 22 — bids for the amount of electricity they wanted to buy. For each auction, the PX ranked the sellers offers to buy from low to high with a resulting supply curve. Price was mapped vertically and quantity horizontally, and the chart would depict the supply curve slopped upward because as the price increased, sellers were willing to sell more. On the other hand, the buyers’ offers formed the “demand curve” which sloped downward because as the price increased, purchasers were willing to purchase less. Like all supply and demand curves, the point where the lines intersected represented the quantity sold in that auction and the “market clearing price” (“MCP”) for that power. The PX and ISO Tariffs provided the formula for the price; thus, the price of the last accepted seller’s bid (the highest price) set the MCP for all of the power sold in that auction. PX Tariff § 3.8, Pis. Exh. 57 at 910; id., Schedule 3, Pis. Exh. 57 at 958; id., Appendix B, Master Definitions Supplement, Pis. Exh. 57 at 1061. After the MCP was set, the PX informed the participants whose bid had been accepted, and the winning buyer and sellers would submit a “schedule” to the PX in which the sellers provided the location where the power would be delivered and the buyers identified the location where the power would be received. 2. The ISO Unlike the PX, the ISO acted as the buyers’ agent for all buyers in the market. ISO Tariff § 2.2.1. The role of the ISO was to maintain a stable power supply and adequate reserves as well as ensuring nondiseriminato-ry access to power. After the restructuring, the IOUs continued to own and maintain their transmission lines, but the ISO controlled access to and transmission over these lines, including minute-by-minute balancing of power supply and demand. The ISO, therefore, operated the electricity grid, and directed the necessary power to the loads of the IOUs. The parties who participated in the buying and selling of power in the ISO markets were called “Scheduling Coordinators.” Hence, the IOUs, CERS, and the Agencies all were ISO Scheduling Coordinators. Additionally, by statute, the PX also was authorized to act as a Scheduling Cooi’di-nator for the PX market participants. After the PX held the auctions, the ISO then accepted the schedules for power supply and usage. The ISO also procured additional electric power to make up the difference between the amount sold in the PX and the amount the ISO determined would actually be necessary to meet the demand. To accomplish this, the ISO set a single market clearing price for each interval and then the MCP was paid to every seller whose bid was accepted, even if that seller’s bid was below the MCP. The cost of the additional supply was paid by the IOUs and other entities that used power from the system during that time interval, in proportion to its usage. At times, the ISO had to obtain power outside the auction process to maintain the reliability of California’s electric grid. This outside power was known as “out-of-market” or “OOM” power. The Tariff allowed for these types of transactions, see ISO Tariff § 2.3.5.1.5, and when the ISO acquired the power in this way, the costs were passed on to the market participants that used it. During the crisis, both WAPA and BPA made OOM sales to the ISO by way of “energy exchanges” in which the Agencies delivered energy in exchange for the ISO’s agreement that they would be paid “in kind” rather than in cash by a subsequent return of an agreed amount of energy to the Agencies. D. The Contracts In order for the Agencies to have access to the PX and ISO markets, the Agencies were required to sign written contracts that incorporated the entire Tariffs, as well as agreeing to abide by the Tariffs’ terms and subsequent changes to those Tariffs. PX participants were required to sign a PX Participation Agreement (“PX Agreement”). PX Tariff § 2.6.2(f), P.Ex. 57 at 903. In the ISO, the Scheduling Coordinators were also required to sign a Scheduling Coordinator Agreement (“SC Agreement”). ISO Tariff § 2.2.3.1., Pis. Exh. 66 at 31. The PX and ISO Tariffs were incorporated by reference, in their entirety, into the PX and SC Agreements. PX Tariff, Appendix A, PX Agreement §§ II, 8, Pis. Exh. 57 at 1056, 1058; — 23 — ISO Tariff, Appendix B, SC Agreement §§ 2, 8, Pis. Exh. 66 at 388, 390. As the Tariffs were incorporated in their entirety, the Participants were obligated to abide by not only the PX and ISO Agreements, but were obligated to abide by the Tariffs as well. Specifically, the PX Agreements stated that the Agencies would “abide by and will perform all of the obligations under the PX Tariff in respect to all matters set forth therein including, without limitation all matters relating to the trading of Energy by [them] through the PX Markets ... [and] billing payments.” PX Tariff, Appendix A, Participation Agreement § 11(B), Pis. Exh. 67 at 1056. With regard to the SC Agreements, those agreements specifically stated that the Agencies would “abide by, and will perform all of the obligations under the ISO Tariff placed on Scheduling Coordinators in respect of all matters set forth therein including, without limitation, all matters relating to the scheduling of Energy and Ancillary Services on the ISO Controlled Grid, ... [and] billing and payments....” ISO Tariff, Appendix B, SC Agreement § 2(b), Pis. Exh. at 388. FERC LITIGATION A. The FPA and FERC Jurisdiction The Federal Power Act (“FPA”) gives FERC exclusive jurisdiction over all wholesale power transactions by “public utilities.” The term only applies to private market participants such as the IOUs, the PX, and the ISO, but not governmental entities such as the Agencies. FPA § 201(b), (e), 16 U.S.C. § 824(b), (e) (2000). See generally N.Y. v. FERC, 535 U.S. 1, 122 S.Ct. 1012, 152 L.Ed.2d 47 (2002). Although governmental entities such as the Agencies are not “public utilities” under the FPA, (FPA § 201(f), 16 U.S.C. § 824(f) (2000)), they may contract to abide by FERC-regulated rates. See Bonneville, 422 F.3d at 925-26. The rates, terms, and conditions for all wholesale sales of power must be filed with and approved by FERC. FPA § 205(a), 16 U.S.C. § 824d(a) (2000). FERC’s regulatory authority extends not only to particular prices, but also to rate formulas, practices, and other terms and conditions of service. See Pub. Utils. Comm’n of the State of Cal. v. FERC, 254 F.3d 250, 254 (D.C.Cir.2001). Interested parties, and FERC itself, may initiate complaint proceedings to challenge electric rates under FPA Section 206, 16 U.S.C. § 824e (2000). When a party files a challenge under FPA Section 206, FERC must investigate whether the rates being charged under the tariff are unjust, unreasonable, or otherwise unlawful. Id. § 824e(a). If the rates are not just and reasonable, FERC must determine the just and reasonable rate, id., and has authority to order refunds for transactions occurring after a FERC-speeified “refund effective date.” The “refund effective date” established by FERC must be at least sixty days after the filing of the complaint. FPA § 206(b), 16 U.S.C. § 824e(b) (2000). Pursuant to Section 309 of the FPA, FERC may also order refunds for the period prior to the refund effective date if it finds that there has been a tariff violation. Id. § 825h (2009); CPUC v. FERC, 462 F.3d at 1045. B. The PX and ISO Tariffs and FERC As already noted, the PX and ISO were “public utilities” under the FPA, therefore, all sales and purchases of power in those markets were governed by FERC-regulated tariffs. See FPA § 201(b), (d), (e), 16 U.S.C. § 824(b), (d), (e) (2000). Automated Power Exch. v. FERC, 204 F.3d 1144 (D.C.Cir.2000) (upholding FERC jurisdiction over power exchanges that facilitate power trading in California). The Tariffs, which were filed with FERC, specified the rules to abide by in order to participate in these markets, including when and in what form participants would submit bids to buy and sell power, and the formulas used to establish prices for all purchase-sale transactions. The Tariffs also prescribed the financial settlements resulting from market transactions. They also allocated risks as between the markets and the market participants. FERC could alter or amend the Tariffs, including their pricing formulas, and to review and correct the market-clearing prices. See San Diego Gas & Elec. Co., 127 FERC ¶ 61,191, at P 31 (2009) (“May 29, 2009 Order”); CPUC v. FERC, 462 — 24 — F.3d at 1043-44. Both Tariffs authorized market participants to seek FERC’s review and correction of prices set under the Tariff formulas. PX Tariff § 13, Pis. Exh. 57 at 918-19 (preserving PX participants’ rights to seek FERC review of prices under FPA Section 206); ISO Tariff § 19, Pis. Exh. 66 at 316-17. Thus, it is uneontested that when the Agencies signed the PX and SC Agreements, they agreed to accept the prices, terms, and conditions established by the PX and ISO Tariffs, as determined and modified from time to time by FERC. C. FERC Determined that PX and ISO Sellers’ Prices Were Unjust and Unreasonable SDG & E filed a complaint with FERC on August 2, 2000 against all sellers of electricity into the PX and ISO markets, alleging that the California wholesale power markets were not competitive, and that FERC should grant relief consistent with its statutory charge to assure that wholesale rates are just and reasonable.1 PG & E, SCE, and the People all intervened in that proceeding, asking FERC to investigate the markets, place caps on prices, and to change the markets’ rules if FERC found the rules were not working as intended and were contributing to the market dysfunction, as well as order refunds. Thereafter, on August 23, 2000, FERC opened an investigation into whether sellers’ rates were just and reasonable. San Diego Gas & Elec. Co., 92 FERC ¶ 61,172, at 61,603, 61,609 (2000) (“August 23, 2000 Order”) (“Remedy Proceeding”). The Agencies were respondents to the initial SDG & E complaint, and they also formally intervened as parties and gained full participatory rights in the Remedy Proceeding. Pis. Exh. 67, 69. In the August 23, 2000 Order, FERC established a “refund effective date” to begin October 2000 and end June 20, 2001 (“refund period”) putting sellers on notice that any sales they made between these dates might be subject to refund if FERC concluded, following investigation, that prices must be corrected. August 23, 2000 Order, 92 FERC at 61,609; see also San Diego Gas & Elec. Co., 93 FERC ¶ 61,121, at 61,370 (2000) (“November 1, 2000 Order”); CPUC v. FERC, 462 F.3d at 1046-47. Additionally, FERC announced that its investigation would consider modification of the PX and ISO Tariffs and related agreements. August 23, 2000 Order, 92 FERC, at 61,606; PX Tariff § 13, Pis. Exh. 57 at 918-19; ISO Tariff § 19, Pis. Exh. 66 at 316-17. FERC has been granted this authority and it is undisputed, as WAPA’s own witness Mr. Sanderson conceded that FERC has power to amend the PX and ISO Tariffs, including revising the prices set under the Tariffs, and that the Agencies are bound to follow the Tariffs as amended by FERC. In its November Order, FERC acknowledged that serious flaws in the market structure and rules, along with an artificially created imbalance of supply and demand, were causing unjust and unreasonable electricity rates. November 1, 2000 Order, 93 FERC ¶ 61,121, at 61,349-50. See also CPUC v. FERC, 462 F.3d at 1039-40 (discussing the potential for manipulation by sellers under the market rules and Enron fraudulent strategies). In the case at bar, during trial, Plaintiffs put forth evidence that showed that during the Energy Crisis, the Agencies sought to “cash in” on the market dysfunction and stratospheric prices. For instance, the evidence showed that BPA gave instructions to its traders dealing with the PX and ISO through documents called “Operations Memos” or “UFNs” (“Until Further Notice”) and that BPA’s September 15, 2000 UFN stated that the ISO expected Stage 2 and possibly Stage 3 emergencies, and went on to say: “[T]he [ISO] called this morning to warn us of their expected heavy loads early next week.... Our ability to aid (cash in) in there [sic] anticipated crisis would be limited by transmission space.” Pis. Exh. 65 at 119675 (emphasis added); Trial Tr. 2101:5-13 (Oliver). The evidence is clear that the Agencies’ traders recognized that the Energy Crisis provided the Agencies an opportunity to reap windfall profits. As BPA explained in another UFN, “[s]elling at such times is — 25 — an ancient but still true marketing strategy derived from Neanderthal hunting philosophy translated from cave paintings: ‘wait till they fall in the tar pit then whomp ‘era.’ ” BPA June 22, 2000 Operations Memo, Pis. Exh. 54 at 119648 (emphasis added); see Trial Tr. 2103:10-2104:5 (Oliver). D. FERC Corrected Prices Charged in the PX and ISO Markets During the Refund Period FERC eventually altered the pricing formulas in the PX and ISO Tariffs and corrected prices set under those formulas for sales in the PX and ISO markets. Specifically, in its July 25, 2001 Order, FERC corrected the prices for the PX and ISO auction and OOM sales during the refund period. San Diego Gas & Elec. Co., 96 FERC ¶ 61,120 (2001) (“July 25, 2001 Order”). FERC adopted a methodology to recalculate, on a market-wide basis, the maximum prices that would have existed in the PX and ISO markets if sellers had charged just and reasonable rates. Id. at 61,516-19. The corrected, maximum rates were called the “Mitigated Market Clearing Price,” or “MMCP.” FERC rejected requests by various market participants to set different MMCPs for different classes of sellers, and crafted the MMCP as a single, market-wide remedy. See, e.g., December 19, 2001 Order, 97 FERC ¶ 61,275, at 62,218. FERC’s price correction included an interest component to compensate market participants who had originally overpaid for their power purchases, as authorized by the Tariffs. PX Tariff § 15.6, Pis. Exh. 57 at 922; ISO Tariff § 12.6, Pis. Exh. 66 at 298; see also July 25, 2001 Order, 96 FERC ¶ 61,120, at 61,519; 18 C.F.R. § 35.19(a)(2). On appeal from FERC’s July 25, 2001 Order and related orders, the Ninth Circuit affirmed FERC’s authority to correct the market clearing price that all sellers, including the Agencies, agreed to accept for their sales during the Refund Period, including OOM sales. CPUC v. FERC, 462 F.3d at 1051-53. The court held that FERC’s price corrections were not impermissibly “retroactive;” in fact, FERC complied with the rule against retroactive ratemaking by limiting its remedies to the period following the refund effective date. Id. at 1063. E. The PX and ISO Recalculated Prices and Published Settlement Statements The PX and ISO were responsible for tracking how much power each market participant bought and sold and the price associated with each transaction in those markets. PX Tariff §§ 3.1, 6.2, Pis. Exh. 57 at 904-905; ISO Tariff §§ 11.1, 11.2, Pis. Exh. 66 at 274-75. For each “Settlement Period,” the PX and ISO calculated each PX Participant’s and Scheduling Coordinator’s respective purchases and sales, netted out the credits and debits attributable to each buyer and seller, and prepared and distributed “settlement statements” reflecting the amounts payable and receivable by market participants in connection with their transactions. PX PSABP § 5.4, Pis. Exh. 188 at 1743-44; ISO Tariff § 11.9, Pis. Exh. 66 at 289. FERC directed the PX and ISO to apply the MMCP to sales for each auction interval during the refund period in order to recalculate the corrected prices that all sellers should have charged and to re-run their settlement and billing processes under their respective Tariffs. July 25, 2001 Order, 96 FERC ¶ 61,120, at 61,513, 61,516-20. The PX and the ISO complied with the directive and recalculated the accounts of all sellers and buyers in their markets to reflect the corrected prices for the Refund Period. BPA never raised any objection to those. In order to apply the MMCP, the ISO needed factual data related to the sellers’ actual generation costs. Evidentiary hearings were held to establish the facts needed to calculate the MMCP and resulting refunds, July 25, 2001 Order, 96 FERC ¶ 61,-120, at 61,519-20, and thereafter proposed findings were issued on December 12, 2002. On March 26, 2003, FERC issued an order largely adopting the proposed factual findings regarding the various market transactions and related costs. San Diego Gas & Elec. Co., 102 FERC ¶ 61,317 (2003). The PX and ISO then applied the MMCP to the Agencies’ sales data to calculate the Agencies’ refund obligations — the amounts the Agencies charged for each of their sales — 26 — transactions during the Refund Period in excess of the MMCP — including the interest component authorized by the Tariffs. In 2004-2005 the PX and ISO furnished those calculations to the Agencies in the form of revised settlement statements known as “refund rerun settlement statements.” See Forty-Fifth Status Report of the California Independent System Operator Corporation on Settlement Re-Run Activity (Jul 16, 2010) (“ISO 45th Status Report”), Pls. Exh. 254 at 1969, 1982. The PX furnished PX market participants with preliminary refund rerun settlement statements on February 8, 2005. See PX’s February 9, 2005 market notice, Pis. Exh. 127 (“[yjesterday, February 8, 2005, all CalPX settlement statements in the FERC [Remedy Proceeding] were published”); Trial Tr. 1033:23-1034:3 (Conn) (explaining that PX’s February 9, 2005 market notice notified market participants that “the refund calculations were complete and that the settlement statements were available for review”). Final refund renin settlement statements were published on May 17, 2005. See PX’s May 17, 2005 market notice, Pis. Exh. 132; Trial Tr. 1041:22-1042:13 (Conn) (explaining that PX’s May 17, 2005 market notice notified market participants that PX had published final refund rerun settlement statements). Following the PX action, the ISO furnished Scheduling Coordinators with refund reran settlement statements covering the Refund Period on a rolling basis between October 25, 2004 and February 17, 2006. For a seller, these settlement statements showed the amount of the seller’s refund obligation. The evidence is undisputed that the refund calculations are complete, and there are no outstanding or unresolved disputes concerning BPA or WAPA. See Forty-Third Status Report of the California Independent System Operator Corporation on Settlement Re-Run Activity (May 8, 2009)' (“ISO 43rd Status Report”), Pis. Exh. 178 at Attachment A; ISO 45th Status Report, Pis. Exh. 254 at 1968. At trial, Dr. Conn explained that the PX’s remaining adjustments to the refund calculations are items that will be allocated to buyers, not sellers like BPA and WAPA Mr. Bouillon of the ISO confirmed that ongoing adjustments to refund obligations for fuel costs and emissions do not apply to the Agencies as sellers. Athough BPA’s Stephen Oliver initially claimed that the calculation of refunds remained incomplete because adjustments were being made to the refund figures, he later admitted that none of the adjustments had any bearing on BPA’s refund obligations. F. Current FERC Litigation The Agencies also made sales for which FERC is in the process of determining corrected prices pursuant to the Ninth Circuit’s decision. See infra pp. 26-27. FERC has already corrected prices for many of the transactions, however, it had concluded that it lacked authority to order refunds for the Summer Period (May 1, 2000 to October 1, 2000), and thus denied relief for that period. CPUC v. FERC, 462 F.3d at 1045-1048. FERC also refused to correct the rates for Refund Period energy exchanges and multi-day sales (sales of power for periods longer than 24 hours), which are collectively referred to as the “Excluded Transactions.” Id. at 1055, 1059. The Ninth Circuit reversed FERC’s orders refusing to grant such relief. Id. at 1065. The court held that FERC failed to provide any valid reason for its refusal to apply its MCP methodology to the Excluded Transactions, id. at 1057-58 (multi-day transactions), 1059 -61 (energy exchanges), and granted Plaintiffs’ petitions “challenging FERC’s exclusion of such transactions.” Id. at 1065. Similarly, as to Summer Period transactions, the court held that FERC provided insufficient justification for its refusal to consider a market-wide remedy. Id. Noting that Plaintiffs provided “significant evidence of pervasive tariff violations,” id. at 1049, the court held that “FERC’s categorical rejection of the California Parties’ request for ... relief was arbitrary, capricious, and an abuse of discretion.” Id. at 1051. This matter is still moving forward on remand. G. Ninth Circuit Litigation FERC’s July 25, 2001 Order contained two distinct rulings relating to the Agencies’ re — 27 — fund obligations. First, FERC adopted the MMCP, altering the Tariffs’ pricing formulas, to correct the prices that all sellers— public utilities and governmental agencies alike — agreed to accept for their sales during the refund period. That action was upheld by the Ninth Circuit. CPUC v. FERC, 462 F.3d at 1043-44. In its second ruling, FERC held that its power to enforce sellers’ payment of their refund obligations under the FPA extended to governmental entities such as the Agencies. This was reversed on appeal holding that FERC lacked statutory authority to enforce governmental entities’ refund obligations. Bonneville Power Admin. v. F.E.R.C., 422 F.3d 908, 911 (9th Cir.2005). The effect of that holding was that, after Bonneville, Plaintiffs’ refund claims against the Agencies were no longer being determined within the Remedy Proceeding but would be decided by the Court. At the same time, FERC retained jurisdiction over the Agencies’ claims against the IOUs for the amounts the IOUs still owe for their purchases of the Agencies’ power, and for refunds owed by the IOUs or other sellers for overcharges on any purchases by the Agencies. October 19, 2007 Order, 121 FERC ¶ 61,067, at PP 42, 57. The Ninth Circuit suggested in Bonneville that although FERC could not enforce governmental sellers’ refund obligations, market participants could obtain “the equivalent refund relief’ by bringing claims in court directly against the Agencies to enforce the contractual obligations created by the Tariffs and related agreements. Bonneville, 422 F.3d at 925-26. On remand and in light of Bonneville, FERC reaffirmed that it had found prices in the PX and ISO markets excessive and had reset the prices that all parties in those markets, including the Agencies, agreed to accept for sales in those markets. San Diego Gas & Elec. Co., 121 FERC ¶ 61,188, at PP 10-13 (2007), clarifying October 19, 2007 Order, 121 FERC ¶ 61,067, at P 36 (confirming FERC “revised the pricing formulations contained in the CAISO/PX tariffs” to “reset the market clearing prices” for PX and ISO transactions during refund period). However, as the Ninth Circuit ruled in Bonneville that FERC did not have authority to enforce the corrected prices with respect to governmental entities, FERC vacated its orders that had previously required governmental entities to refund their overcharges, and ruled that the PX and ISO should disburse any remaining payments for the Agencies’ sales to them in the first in stance at the original, unmitigated prices, without withholding the refunds they owe. October 19, 2007 Order, 121 FERC ¶ 61,067, at PP 23-24, 36, 57. FERC expressly left the determination of the Agencies’ refund obligations to this Court, holding that “[ajmounts owed and payments thereof by [governmental sellers], if any, as a result of these contractual claims are a matter to be resolved by the relevant court.” October 19, 2007 Order, 121 FERC 1161,067, at P 76, PP 3, 37, 59. FERC further held that the PX and ISO should finish calculating the governmental entities’ refund liabilities, and that the shortfall resulting from these entities’ refusal to pay refunds would be re-allocated to other market participants, including Plaintiffs. Id. at PP 38-39. WITNESSES Several witnesses testified at trial. For Plaintiff PG & E, Roy Kuga, Vice President, Energy Supply Management, Veronica Andrews, Senior Director of Short Term Electric Supply, and Joseph Castillo Manager of FERC Refund Settlements, testified. For SCE, Gary Stern Director of Market Strategy and Resource Planning testified. Michael Strong Manager of Settlements and Systems testified for SDG & E. Peter Garris, (former) Deputy Director for CERS, and Susan Lee, (former) Manager of Trading and Scheduling for CERS testified for The People. Other witnesses who testified for the PX and ISO included Lawrence Conn, Director of Operations and John Melby, (former) Senior Director of Marketing and Product Development as well as Bradley Bouillon Settlements Manager, Michael Epstein, Director of Financial Planning, and William Regan, (former) ISO Chief Financial Officer. BPA had testify on its behalf Stephen Oliver, Vice President, Generation Asset Man — 28 — agement and Donald Wolfe (by deposition), Public Utilities Specialist. WAPA called Jeffrey Ackerman, Manager of the Colorado River Storage Project Energy Management and Marketing Office and Sean Sanderson, Billing and Settlements Manager. Two experts were called. Robert Gee, President, Gee Strategies Group LLC for the Plaintiffs, and Jeffrey Tranen, Senior Vice President, Compass Lexeeon, for the Defendant. DISCUSSION Plaintiffs have brought this suit under two independent alternative legal theories of contract recovery. First, Plaintiffs assert that the Agencies anticipatorily breached their contracts by repudiating their obligation to refund their overcharges to Plaintiffs, entitling Plaintiffs to sue now for damages. PG & E and SCE Complaint, Docket No. 1, Case No. 07-157 (Mar. 12, 2007) (“Compl”) ¶¶ 78-79. To constitute repudiation, the Agencies’ renunciation of their contract obligation need only be “sufficiently positive to be reasonably interpreted to mean that [they] will not or cannot perform.” Restatement § 250 cmt. b. The promisor’s repudiation of its contractual obligations “ripens into a breach” if and when the promisee “elects to treat it as such.” Franconia, 536 U.S. at 143-44, 122 S.Ct. 1993. Second, and alternatively, Plaintiffs argue that the Agencies have a present contractual duty to pay the-refunds they owe, and they have breached that duty by nonpayment. Compl. ¶1173-76. Plaintiffs argue that the Agencies contractually agreed to abide by the prices set by FERC, and are obligated to refund the amounts they charged in excess of those prices. Id. It is true and the evidence is undisputed that the Agencies have not paid the refunds FERC has determined they owe. BPA’s rejection of IOUs’ claims, Pis. Exh. 162; WAPA’s rejection of IOUs’ claims, Pis. Exh. 165; BPA’s rejection of the Peoples’ claim, Pis. Exh. 163; WAPA’s rejection of the Peoples’ claim, Pis. Exh. 166. Plaintiffs assert that between July 25, 2001, when FERC corrected the prices for the refund period, and September 6, 2005, when the Ninth Circuit issued its Bonneville decision, FERC was exerting exclusive jurisdiction over the refund obligations of all PX and ISO sellers. That meant that the Agencies’ contractual refund obligations — the amount, and when and how the refunds would be paid — could be determined only through the FERC regulatory process, and would be enforced by FERC order. After the Bonneville decision, the Agencies could not be compelled to refund their overcharges through the FERC process. Plaintiffs claim, therefore, that the Agencies breached their contracts by failing and refusing to refund their overcharges within a reasonable time after the Bonneville decision, and, in any event, no later than March 2006, when the Agencies denied Plaintiffs’ CDA claims demanding payment of the refunds the Agencies owe. Pis. Post-Trial Brief 59. On the other hand, Defendant raises several arguments in its post-trial brief asserting that the Plaintiffs’ breach of contract claims must fail. To begin, Defendant asserts that Plaintiffs have failed to demonstrate that the United States breached the SC Agreements that it entered into with the ISO or PX. Def. Post Trial Br. at 2. Additionally, Defendant asserts that the IOUs are estopped from asserting that they are in privity with the United States regarding the PX transactions. Id. Next, Defendant argues that the IOUs failed to demonstrate that they are third-party beneficiaries of the agreements between the United States and the PX, as well as arguing that the State of California failed to demonstrate that is was a surety for the IOUs ISO power purchases. Id. And lastly, Defendant argues that Plaintiffs failed to demonstrate that they are entitled to declaratory relief. Id. In the alternative, Defendant asks this Court to defer judgment in these cases until the question of the authority of the FERC to “reset” rates retroactively has been determined. Id. That question is presently before the United States Court of Appeals for the Ninth Circuit. Defendant requests this in order “[t]o avoid the prejudice to the United States of potentially inconsistent judgments in that litigation and this [litigation] ... before deciding whether the United States has — 29 — breached any obligation of its agreements with the ISO or the PX.” Id. The Court DENIES Defendant’s request to defer judgment. If this was the only case with this issue the Court might be persuaded to stay but since there are cases that say that FERC is entitled to reset prices, this Court is not persuaded to stay this case. See e.g. Bonneville Power Admin. v. F.E.R.C., 422 F.3d 908 (9th Cir.2005); CPUC v. FERC, 462 F.3d 1027 (9th Cir.2006). Furthermore, for the reasons set forth below, the Court finds that the evidence Plaintiffs produced at trial proves that there was a contract and that Defendant breached its present contractual obligation to refund its overcharges. I. Are the Plaintiffs Estopped from Asserting Privity? Throughout this case, Defendant has argued that Plaintiffs lack privity with the Agencies. As held above, the facts at trial showed that the Agencies contracted with and owe contract obligations to the Plaintiffs. First, the evidence showed that the PX and ISO were “public utilities” under the FPA Second, as a public utility, all the sales and all the purchases of power in those markets were governed by FERC-regulated tariffs. Third, the applicable Tariffs in this ease which were filed with FERC, specified the rales to abide by in order to participate in these markets. The Tariffs included when and in what form participants would submit bids to buy and sell power, and the formulas used to establish prices for all purchase-sale transactions as well as prescribing the financial settlements resulting from market transactions. The Tariffs also allocated risks as between the markets and the market participants. Fourth, because the Tariffs were FERC regulated, FERC could alter or amend them, including their pricing formulas, and to review and correct the market-clearing prices. And finally, the Tariffs authorized market participants to seek FERC’s review and correction of prices set under the Tariff formulas. At trial, the evidence was clear that in order for the Agencies to have access to the PX and ISO markets, the Agencies were required to sign written contracts that incorporated these Tariffs, as well as agreeing to abide by the Tariffs’ terms and subsequent changes to those Tariffs. In the ISO, the Scheduling Coordinators were also required to sign a Scheduling Coordinator Agreement. Thus, the evidence is clear and uneontested that when the Agencies signed the PX and SC Agreements, they agreed to accept the prices, terms, and conditions established by the Tariffs, as determined and modified from time to time by FERC. Thus the facts at trial proved that the PX and ISO were facilitators only, and that the payment obligations were between the buyer and seller.2 Since the PX and ISO were pass-through.entities or clearinghouses, the contractual relationships of offer, acceptance, and mutual intent ran between the Agencies and the IOUs, the Plaintiffs. The Defendant’s argument is illogical that there is no relationship between the Agencies and Plaintiffs. For example, when one pays a bill with a check, the money may go into the creditor’s bank account, but it is the legal property of the creditor. It meets the debtor’s legal obligations. The same relationship existed here. The PX and ISO were like a bank, and the Agencies and the Plaintiffs had the obligations. It appears that now, as a last resort, Defendant revives another previously rejected argument, that the IOUs are collaterally es-topped from asserting privity. Def. Post-trial Br. 22-25. In support of its argument, Defendant argues that a FERC order, Southern California Edison Co., 80 FERC ¶ 61,262 (1997) (“Edison”), estops the IOUs from asserting privity in PX transactions. Def. Br. 24. The Court must, therefore, turn its attention to the question as to whether collateral estoppels applies. — 30 — A court’s determination of whether collateral estoppel is appropriate turns on a four-part test. Ammex, Inc. v. U.S., 384 F.3d 1368, 1371 (Fed.Cir.2004). To collaterally estop Plaintiffs from asserting a contractual relationship, Defendant bears the burden of showing that: (1) the issue is identical to the issue decided in a former proceeding; (2) the issue was actually litigated in the former proceeding; (3) the issue was necessarily decided in the former proceeding; and (4) the party against whom preclusion is sought had a full and fair opportunity to litigate its position. Id. In addressing Edison, Defendant asserts at most that only two parts of the test are met. Thus Defendant ignores the first step, that the issues in the two proceedings must be identical. In Edison, SCE sought an order declaring whether sales through the PX should be considered wholesale or retail sales under the Public Utility Company Holding Act. Here, the issue is whether PX market participants can sue one another under the terms of the PX Tariff. Thus, as the four part test is not satisfied, Defendant’s collateral estoppel argument must fail. Defendant also contends that SCE should be collaterally estopped from asserting privity with respect to PX transactions on the basis of Southern California Edison Co. v. Lynch, 307 F.3d 794 (9th Cir.2002) (“Lynch ”). Def. Post-trial Br. 24-25. Once again, Defendant does not and cannot demonstrate that Lynch meets the four-part test. Again, there is no identity of issues. The issue in Lynch was whether two generators that were owed money for power they had sold in the PX markets could intervene to challenge the settlement of a lawsuit in which SCE sought to compel the California Public Utilities Commission to increase SCE’s retail rates during the Energy crisis — not, as here, whether SCE and generators could sue one another to enforce obligations under the PX Tariff. Accordingly, the Court finds Defendant has established no grounds on which estoppel could properly be applied. Having found that privity exists and that estoppel does not apply, the Court moves on to the merits of this case. II. Did Defendant Breach its Contractual Obligation to Refund its Overcharges? Defendant raises several arguments with respect to its contention that the Defendant did not breach any contract. Defendant first raises the defense that it is not obligated to pay the Plaintiffs anything because the contracts signed by the agencies were with the ISO and the PX, not with the Plaintiffs. Defendant further argues that no obligations have arisen under the contracts nor have Plaintiffs identified a tariff provision that they allege defendant breached as well as failing to identify the breach of any contract provision that governs how and when that alleged refund obligation was to have been satisfied. The Court will, therefore, turn its attention to these arguments. A. Did the Tariffs Allow Prices to be Corrected by FERC? Defendant contends that because FERC was not authorized to reset ISO and PX prices for the Agencies’ sales, the Agencies did not agree to refund their overcharges when they agreed to be bound by the Tariffs. Def. Post Trial Br. 4-5. First, Defendant argues that the ISO Scheduling Coordinating Agreements and PX Participation Agreements, which, incorporated the ISO and PX Tariffs provide that the Tariffs govern bidding and settlement. Pis. Exh. 23 at 600 ¶ 2, 603 § 8; Pis. Exh. 26 at 606 § II.A, 608 § 8. These provisions, Defendant argues, do not contain language that the prices that the agencies received for power were subject to retroactive revision, or to any revision of rate change at which the United States agreed to sell power. Def. Post Trial Br. 4. Second, Defendant argues that Plaintiffs reliance on PX Tariff § 13 and ISO Tariff § 19 is misplaced as Defendant contends these provisions merely preserve the ability of scheduling coordinators and market participants to exercise rights under sections 205 and 206 of the FPA, 16 U.S.C. §§ 824d, 824e(a), “and FERC’s rules and regulations thereunder.” Pis. Exh. 57 at 918-19 § 13; Pis. Exh. 66 at 316-17 § 19, Def. Post Trial Br. 4. As FERC’s rate jurisdiction under — 31 — sections 205 and 206 expressly applies only to public utilities, Defendant asserts that governmental entities such as BPA and WAPA cannot be regulated under such provisions. Bonneville Power Admin. v. F.E.R.C., 422 F.3d 908, 918 (9th Cir.2005). Defendant’s arguments notwithstanding, the Court finds that the evidence at trial showed that the Tariffs contain provisions as a matter of contract law allowing FERC to reset prices for all PX and ISO transactions during the relevant time period. This role for FERC is created by a contract between all market participants, both private and governmental. The evidence showed that the PX and ISO Tariffs gave Plaintiffs the contractual right to ask FERC to review and modify the prices charged under those Tariffs during the Energy Crisis.3 It makes FERC an arbitrator under the contract apart from any independent authority FERC has under Federal law over government participants in the PX and ISO markets. Specifically, PX Tariff Section 13 states: Any amendment or other modification of any provision of this PX Tariff must be in writing and approved by the PX Governing Board in accordance with the bylaws of the PX. Any such amendment or modification shall be effective upon the date it is permitted to become effective by FERC.... Nothing contained in this Tariff or any service or participation agreement shall be construed as affecting, in any way, the ability of any PX Participant receiving service under this Tariff to exercise its rights under Section 206 of the FPA and pursuant to FERC’s rules and regulations promulgated thereunder. Pls. Exh. 57 at 918-919 (emphasis added.) Section 19 of the ISO Tariff is substantively identical. Pls. Exh. 66 at 316-17. The intention of the parties in creating a contract is key to its interpretation. Beta Sys., Inc. v. United States, 838 F.2d 1179, 1185 (Fed.Cir.1988). Defendant argues that when they entered into the agreements with the ISO and the PX, the agencies could not have intended to be bound by a retroactive revision of rates implemented by FERC because such a revision would have been entirely novel and unforeseeable. Def. Post Trial Br. 4-5. However, in determining the meaning of terms in a contract, the Court may receive and review evidence of trade practice and custom. See e.g., Metric Constructors, Inc. v. NASA, 169 F.3d 747, 752-53 (Fed.Cir.1999) (considering evidence of trade practice and custom); Bos. Edison Co. v. FERC, 441 F.3d 10, 13-16 (1st Cir.2006). The evidence at trial showed, and as Plaintiffs’ expert witness, Robert Gee explained, PX Tariff Section 13 and ISO Tariff Section 19 have a well understood meaning in the specialized practice and custom of the energy industry. These provisions, he testified, are known in the industry as “Memphis clauses,” and signify that prices charged under the contract are not “fixed,” but rather are subject to review and change by FERC. Additionally, Defendant’s own expert, Jeffrey Tranen, conceded that PX Tariff Section 13 and ISO Tariff Section 19 are “Memphis Clauses” that expressly give the contracting parties the right to seek FERC correction of prices for sales made under the Tariffs. The Court finds that under industry usage, PX Tariff § 13 and ISO Tariff § 19 represent a contractual agreement of the market participants. That agreement is that the participants could petition FERC to investigate whether prices being charged are just and reasonable and, if FERC found they were not, correct those prices to just and reasonable levels. In addition, the Court holds that FERC’s correction of prices for PX and ISO market sales is, therefore, contemplated by the contract and contractually binding on the Agencies. Although FERC’s regulatory jurisdiction applies only to the rates charged by — 32 — “public utilities” the ISO and PX are public utilities and the Agencies voluntarily contracted to abide by prices set under the FERC regulated ISO and PX Tariffs because they wanted to trade in those markets. Therefore, the Court finds that the Agencies contractually bound themselves to the corrected rates even though FERC lacked jurisdiction to regulate the Agencies directly. Even so, Defendant argues that pursuant to § 206(a) of the FPA, FERC possesses the authority to determine a rate only prospectively. Def. Post Trial Br. 4-5. Thus, according to Defendant, FERC does not possess authority pursuant to § 206(a) to reset rates retroactively and, therefore, FERC’s action of resetting rates retroactively is beyond its authority. Thus says Defendant, this action has no effect upon the agencies’ contract obligations. Cf. Del-Rio Drilling Programs, Inc. v. United States, 146 F.3d 1358, 1362 (Fed.Cir.1998) (holding that the ultra vires conduct of a Government official cannot affect a governmental taking). Defendant relies on the testimony of its expert witness Jeffery Tranen that “under the Federal Power Act ... FERC cannot engage in the retroactive resetting of rates.” Trial Tr. 2277:9-14 (Tranen). In support of this position, Mr. Tranen testified that before and after this case, FERC has only ever changed rates on a prospective basis. During his testimony, Mr. Tranen discussed his understanding of section 206; and in his opinion, FERC does not retroactively reset rates. He further opined that market participants could not have been on notice that FERC would retroactively reset rates basing his opinion upon his direct experience, as an industry executive, with FERC’s customs and practices in eases in which he was involved. Plaintiffs assert, and the Court agrees, that Defendant’s argument and the testimony provided is contrary to FERC’s own rulings addressing its authority to reset prices for sales under the PX and ISO Tariffs. The testimony provided by Mr. Tranen indicates that he misunderstood how FPA Section 206(b) operates. Under Section 206(b), a market participant files a complaint and FERC initiates proceedings to assess the complaint. As part of that process FERC establishes a “refund effective date” 60 days after the date the complaint is filed. FPA § 206(b), 16 U.S.C. § 824e(b) (2000). The imposition of a refund effective date places market participants on notice that prices charged after the refund effective date are provisional and subject to change. CPUC v. FERC, 462 F.3d at 1046-47. FERC’s price correction is prospective from the refund effective date, not retroactive. As Senator Bumpers, the sponsor of the Regulatory Fairness Act, the bill that added this particular provision to FPA Section 206 explained, the statute “would provide that rate reductions ordered by FERC be prospective from a refund effective date set by the Commission as contrasted to the date of the final Commission order.” 134 Cong. Ree. 22,906, 22,907 (1988) (statement of Sen. Bumpers) (emphasis added); Pis. Post Trial Br. 53. On cross-examination, Mr. Tranen admitted he was unaware of these facts. Moreover, Mr. Tranen purported to base his opinion on Court of Appeals decisions that discussed retroactive ratemaking generally, but he was unaware of specifically relevant decisions. For instance, in Public Utilities Commission of the State of California v. FERC, 988 F.2d 154 (D.C.Cir.1993), the court explained that “when determining whether a FERC order violates either the filed rate doctrine or the rule against retroactive rate-making, this court inquires whether, as a practical matter, the [parties] ... had sufficient notice that the approved rate was subject to change.” Id. at 164 (emphasis added). Significantly, notice does not mean that the rule against retroactive ratemaking does not apply; rather, notice, such as that provided by a refund effective date, “changes what would be purely retroactive ratemaking into a functionally prospective process by placing the relevant audience on notice at the outset that the rates being promulgated are provisional only and subject to later revision.” Id. (internal quotations and citations omitted). Mr. Tranen did not consider this authority, and others, in formulating his opinion. As such, the Court finds Mr. Tranen’s testimony with regard to this issue of no probative value. — 33 — Likewise, it is well settled that FERC’s orders are binding law, unless and until overturned on direct review by a federal court of appeals. As Defendant concedes, this Court has no jurisdiction to consider this attack on FERC’s authority, or to take any action on the assumption that a FERC order may be erroneous. As both FERC and the Ninth Circuit have held, The Commission’s actions in this proceeding are well within the authority granted to it under section 206, which specifically provides that the Commission may reset prices in Commission-jurisdictional tariffs and order refunds back to the refund effective date. Contrary to the [governmental sellers’] argument, the Commission ... is not engaging in impermissible retroactive action with respect to rate changes [under the PX and ISO Tariffs]. Rather, in the November 2000 Order, we determined rates charged under the jurisdictional CAISO/PX tariffs to be unjust and unreasonable. Pursuant to the statutory requirement placed upon the Commission by Congress under FPA section 206(b), we established a refund effective date of October 20, 2000. FPA section 206(b) also permits the Commission to order refunds for the period subsequent to the refund effective date through a date fifteen months after such refund effective date. That is what occurred here. May 29, 2009 Order, 127 FERC ¶ 61,191, at PP 15, 18 (emphasis added). That Order is currently in effect and as such constitutes the governing federal law, unless and until it is overturned. See 18 C.F.R. § 385.2007(c) (2008). Hence, FERC’s actions in correcting prices are consistent with its authority under the FPA as the law now stands and the Agencies are bound by the rulings. B. Did Plaintiffs Place in Evidence Transactions Showing Overcharges? Defendant asserts that Plaintiffs have failed to identify transactions in which Plaintiffs were overcharged by the Agencies. Def. Post Trial Br. 6. This assertion ignores the undisputed evidence at trial. Pursuant to their Tariffs, the PX and ISO issued settlement statements to the Agencies showing each of the Agencies’ transactions. PX PSABP § 5.4, Pls. Exh. 188 at 1743-44; ISO Tariff § 11.9, Pls. Exh. 66 at 289. After FERC revised the market-clearing prices for the refund period sales, the PX and ISO issued “refund re-run settlement statements” showing the corrected prices for each of the Agencies’ transactions. Specifically, as the evidence showed, in the July 25, 2001 Order and subsequent orders, FERC directed the PX and ISO to apply the MMCP to sales for each auction interval during the Refund Period in order to recalculate the corrected prices that all sellers should have charged and to re-run their settlement and billing processes under their respective Tariffs. July 25, 2001 Order, 96 FERC ¶ 61,120, at 61,513, 61,516-20; Tr. 261:4-17 (Kuga); Tr. 1022:11-21 (Conn). Thereafter, and pursuant to FERC’s directive, the PX and the ISO recalculated the accounts of all sellers and buyers in their markets to reflect the corrected prices for the refund period. The evidence showed that BPA never raised any objection to those calculations. Trial Tr. 2069:8-14 (Oliver). The evidence further showed that the PX and ISO then applied the MMCP to the Agencies’ sales data to calculate the Agencies’ refund obligations — the amounts the Agencies charged for each of their sales transactions during the Refund Period in excess of the MMCP — including the interest component authorized by the Tariffs. In 2004-2005 the PX and ISO furnished those calculations to the Agencies in the form of revised settlement statements known as “refund rerun settlement statements.” See Forty-Fifth Status Report of the California Independent System Operator Corporation on Settlement Re-Run Activity (Jul 16, 2010) (“ISO 45th Status Report”), Pis. Exh. 254 at 1969, 1982; Trial Tr. 261:4-22 (Kuga); Trial Tr. 1030:20-1031:4, 1032:16-24, 1035:8-1036:8,1064:18-24 (Conn); Trial Tr. 1301:20-24, 1302:22-1303:4; Trial Tr. 1327:19-21 (Bouillon); Trial Tr. 1492:25-1493:5 (Andrews). On February 8, 2005, the PX furnished PX market participants with preliminary re — 34 — fund rerun settlement statements. See PX’s February 9, 2005 market notice, P.Ex. 127 (“[y]esterday, February 8, 2005, all CalPX settlement statements in the FERC [Remedy Proceeding] were published”); Trial Tr. 1033:23-1034:3 (Conn) (explaining that PX’s February 9, 2005 market notice notified market participants that “the refund calculations were complete and that the settlement statements were available for review”). The evidence conclusively showed that the final refund rerun settlement statements were provided on May 17, 2005. See PX’s May 17, 2005 market notice, Pis. Exh. 132; Trial Tr. 1041:22-1042:13 (Conn) (explaining that PX’s May 17, 2005 market notice notified market participants that PX had published final refund rerun settlement statements). In the ISO market, the ISO furnished Scheduling Coordinators with refund rerun settlement statements covering the Refund Period on a rolling basis between October 25, 2004 and February 17, 2006. Trial Tr. 1307:22-1308:2 (Bouillon); ISO 45th Status Report, Pis. Exh. 254 at 1982. For a seller, these settlement statements showed the amount of the seller’s refund obligation, or “delta,” i.e., the difference between the original ' price (MCP) and the FERC-corrected price (MMCP) per unit of power, multiplied by the quantity. See Forty-Fifth Status Report of the California Independent System Operator Corporation on Settlement Re-Run Activity (Jul 16, 2010) (“ISO 45th Status Report”), Pis. Exh. 254 at 1969, 1982; Trial Tr. 261:4-22 (Kuga); 1030:20-1031:4, 1032:16-24, 1035:8-1036:8, 1064:18-24 (Conn); Trial Tr. 1301:20-24, 1302:22-1303:4; Trial Tr. 1327:19-21 (Bouillon); Trial Tr. 1492:25-1493:5 (Andrews). (Feb. 23, 2006), Pis. Exh. 157; Trial Tr. 1050:10-11 (Conn). It is clear from the evidence that the Agencies have validated those statements, which are, therefore, binding on them. The evidence showed that the IOUs purchased power in every auction in which the Agencies sold power, therefore, the IOUs are entitled to a proportionate share of refunds on every sale the Agencies made at a price exceeding the MMCP during the Refund Period. The trial testimony established that the refund re-ran settlement data can be used to identify all such sales and that the specific amount that each Agency owes to each of the IOUs can be calculated from the data shown on the refund re-run settlement statements. See Trial Tr. 1506:9-14 (Andrews); 1570:17-1571:1 (Castillo). Cf. Def. Br. 12-13. Contrary to Defendant’s assertion, to establish liability, Plaintiffs need only show they have been injured by Defendant’s refusal to pay the refunds the Agencies owe. Fireman’s Fund Ins. Co. v. U.S., 92 Fed.Cl. 598, 698 (2010) (citing Lindemann Maschinenfabrik GmbH v. Am. Hoist & Derrick Co., 895 F.2d 1403, 1406 (Fed.Cir.1990)). The Court finds that Plaintiffs have done so. C. Do the Plaintiffs Get Paid Directly? Next, Defendant asserts that Plaintiffs’ have failed to identify any agency obligation to pay them directly. Def. Post Trial Br. 6. Plaintiffs assert that this miseharacterizes their claims as alleging the Agencies must pay refunds directly to Plaintiffs, rather than through the PX and ISO. Pis. Reply at 5 (emphasis in the original). The Court agrees. Here, in the liability phase, Plaintiffs are suing to establish the Agencies’ breach of their contractual duty to pay refunds. How damages eventually will be paid is irrelevant to the existence of the Agencies’ liability to refund their overcharges. Plaintiffs have been damaged by the Agencies’ nonpayment regardless of whether payment was to be made directly to Plaintiffs or through the PX and ISO, though the evidence clearly shows the PX and ISO were only conduits for exchanges between Plaintiffs and Defendant. As the Court has already observed during trial, “Plaintiffs will tell [Defendant] if they win” how Defendant should pay the judgment.” Trial Tr. 1527:9-14, 23-25. Whether payment should be made directly or through the PX and ISO is an issue for the Court to resolve after it determines liability. D. Did Plaintiffs Establish that the Agencies Owe Refunds? Defendant claims that the letters it solicited from the PX and ISO show that the Agencies owe no refunds. Def. Post Trial Br. 10-11. The undisputed evidence from the PX and ISO witnesses at trial, however, — 35 — was unambiguously to the contrary. As the PX and ISO witnesses explained at trial, these letters state on their faces that they do not reflect the amounts of the Agencies’ existing refund obligations, which the PX and ISO have calculated but which are reflected in different accounts. Specifically, Dr. Lawrence Conn of the PX testified that the amounts reflected on the PX’s letters to the Agencies, which he wrote, merely reflect the unpaid balances for the Agencies’ PX and ISO sales, and do not include the Agencies’ refund obligations. Trial Tr. 1077:21-1078:14 (Conn). The PX’s letters themselves state that they “do[] not provide a complete picture of a participant’s final balance with CalPX.” June 24, 2010 letter from PX to WAP A, PI. Exh. 238 at 2045. The letters then list four adjustments that were excluded from the cash balance amounts reported in the letters; one of those adjustments is the PX’s calculation of the Agencies’ refund obligations. Id. at 2046. The ISO’s letters are similar’. Michael Epstein of the ISO explained that its letters do not “indicate anything about whether BPA and WAPA have any refund liability for the refund period.” Tr. 1422:13-17 (Epstein). Rather, the letters refer only to the amount of any invoices issued to the Agencies that remain unpaid nor do the letters refer to the amounts shown on settlement statements issued to the Agencies for the Refund Period. Trial Tr. 1420:8-9, 1417:14— 23,1420:3-11 (Epstein). In addition, Defendant maintains that it has no obligation to pay refunds until it receives invoices from the PX and ISO. Def. Post Trial Br. 11-12. However, this is impossible in light of FERC’s clear direction in its October 19, 2007 Order, that in light of Bonneville, the collection of the refund payments from the Agencies will not be conducted by the PX and ISO through the issuance of invoices, but pursuant to this Court’s orders when liability is determined in this action. Furthermore, it is clear that the Tariffs do not make invoices a condition precedent to the obligation to pay. Defendant argues that the invoice shows the amount due and a payment date. But the evidence clearly demonstrated that invoices were merely a convenience, a prompt for payment and a summary of the obligation shown on the settlement statements. The invoice did not create the legal obligation to pay a specific amount on a specific date. E.g. Trial Tr. 430:23-34 (Melby); Trial Tr. 1946:4-1947:1,1947:8-1949:14 (Oliver). Agency witnesses did not dispute that the refund re-run settlement statements, which they have validated, establish a binding obligation for payment of a specific amount, without the need of an invoice. As Dr. Re-gan testified, the preliminary settlement statement “is a firm binding obligation for settlement.” Trial Tr. 1182:12-14 (Regan). BPA’s Stephen Oliver acknowledged that the settlement statements establish the amount owed, Trial Tr. 2075:6-8 (Oliver), and stated: “I understand that the basis for the obligations that were in those invoices are established by the settlement statements.” Trial Tr. 2075:13-15 (Oliver). If the Court were to accept Defendant’s position, that even though the Agencies received binding settlement statements establishing their obligations, the absence of an invoice would allow them to retain prices that far exceed those set under their contracts. Thus, to accept Defendant’s argument that the contracts make invoicing a condition precedent to the duty to pay, the Court would have to ignore provisions in the same contracts that set prices for the Agencies’ sales. In Unisys Corp. v. United States, 48 Fed.Cl. 451 (2001), the court held that the only reasonable interpretation of the contract was that the United States must refund overpay-ments it received under a settlement agreement, even though the contract did not expressly provide for refunds, because the United States’ interpretation would render meaningless the provisions setting the amount to be paid under the contract. Id. at 455. Similarly, an interpretation that the ISO and PX Tariffs do not require payment of refunds — merely because no invoice has been issued — would render meaningless the provisions setting the prices for transactions, as corrected by FERC. While the Bonneville decision and the October 19, 2007 Order have compelled Plaintiffs to resort to this Court to obtain payment from the Agencies rather — 36 — than relying on the ordinary invoicing and payment process under the Tariffs, that fact does not entitle the Agencies to simply retain their overcharges. Instead, the Court reads the invoicing and pricing provisions as consistent with each other so that the mere lack of an invoice does not allow the Agencies to keep funds to which they are not contractually entitled. III. Do Plaintiffs’ Contract Disputes Act Claims Satisfy the Statutory Requirements? Defendant contends that the Court lacks jurisdiction over Plaintiffs’ claims “because plaintiffs did not submit sum-certain claims to a contracting officer.” Def. Post-trial Br. 21. The Court previously rejected this argument in denying Defendant’s December 22, 2009 motion to dismiss. See Order, Docket No. 142, Case No. 07-0157 (May 5, 2010); see also April 16, 2010 Hearing Tr. at 72:4-5. Moreover, the sum certain requirement, which is found in the Federal Acquisition Regulations (“FAR”), does not even apply to the Agencies’ sales of electricity. See Little River Lumber Co. v. United States, 21 Cl.Ct. 527, 534-35 (1990) (timber sales by U.S.); FAR § 2.101 (48 C.F.R. 2.101); id. § 52.233-1 (48 C.F.R. 52.233-1). Rather, whether a CDA claim satisfies the requirements of the CDA depends on the terms of the contract, any applicable regulations, and the facts of the case. Garrett v. Gen. Elec. Co., 987 F.2d 747, 749 (Fed.Cir.1993). “[T]he submission to the contracting officer must include the amount claimed or some method or supporting material by which the total amount then claimed to be involved can be ascertained.” 25 New Chardon St. L.P. v. U.S., 19 Cl.Ct. 208, 210 (1990); see also United States v. Gen. Elec. Corp., 727 F.2d 1567, 1569 (Fed.Cir.1984). Here, the claims asserted that the Agencies were “contractually obligated to reimburse purchasers for the difference between the rates [they] initially charged in [their] sales in the ISO and PX markets and the lower FERC adjusted lawful rates” and that Plaintiffs sought to recover from the Agencies their “overcharges in the ISO and PX markets” pursuant to the revised prices set by FERC. IOUs’ Amended Claim to WAPA, Pis. Exh. 143 at 17; IOUs’ Amended Claim to BPA, Pls. Exh. 144 at 6; the Peoples’ Claim to WAPA, Pls. Exh. 145 at 799-800; the Peoples’ Second Amended Claim to BPA, Pls. Exh. 151 at 813. The IOUs’ CDA claims gave notice that the IOUs were owed “approximately $49.8 million” by BPA and “approximately $24.3 million” by WAPA. IOUs’ Amended Claim to WAPA, Pis. Exh. 143 at 17; IOUs’ Amended Claim to BPA, Pis. Exh. 144 at 6. The People’s claims gave notice that BPA was estimated to owe “$119 million” and WAPA owed “approximately $5.2 million.” The Peoples’ Claim to WAPA, Pls. Exh. 145 at 800; the Peoples’ Second Am Amended Claim to BPA, Pls. Exh. 151 at 814. The CDA claims thus informed the contracting officers of the amount of the claims and the method by which damages were calculated. The IOUs also explained that their stated estimates of the amounts of their damages claims were based on revised market data published by the ISO and PX, but did not reflect more recent refund rerun data from the ISO and PX. Letter from California Parties to BPA (Feb. 1, 2006), Pis. Exh. 152 at 34788; Letter from California Parties to WAPA (Feb. 1, 2006), Pis. Exh. 153 at 34790. There is no dispute that these data were provided to the Agencies. Nor is there any dispute that the Agencies could have determined their refund obligation from the refund rerun settlement data. Under these circumstances, Plaintiffs provided the best information available to them of the amounts of their Claims — all that is needed to satisfy the statutory requirements. See Sun Cal, Inc. v. United States, 21 Cl.Ct. 31, 35 (1990) (where components of claims “could not be ascertained with certainty at the time the claim was filed, it was necessary to estimate them”). And, even if the sum certain applied, that requirement is satisfied by Plaintiffs’ submission of their “[b]est, good faith estimate at the ... time” of the claim. Hernandez, Kroone & Assocs., Inc. v. United States., No. 07-165C, 2009 WL 5549368, at *1 (Fed.Cl. Oct. 5, 2009). The evidence is clear, Plaintiffs submitted their claim to the contracting officer. Plaintiffs gave adequate notice of their claim by — 37 — providing the method of their calculations. Therefore, the Government had notice of Plaintiffs claim, with the best available evidence satisfying the CDA requirements. CONCLUSION For the reasons set forth above, the Court hereby finds Defendant breached its present contractual duty to pay the refunds they owe, and they have breached that duty by nonpayment. IT IS SO ORDERED. Footnotes [1] Complaint of SDG & E, FERC Docket No. EL00-95 (Aug. 2, 2000), Pls. Exh. 58. [2] In light of this finding, the Court need not address whether the Plaintiffs are third party beneficiaries as the evidence proved that they are direct beneficiaries. Furthermore, the Court need not address whether the State of California is a surety. The facts proved that under the terms of the market, CERS was a market participant as California bought power through the PX and ISO. As a market participant, CERS had a direct contract relationship with the Government. Therefore, the State of California has the same relationship as any market participant. [3] In Bonneville, the Ninth Circuit validated this premise on which Plaintiffs’ contract claim is based: FERC and intervenor California Parties [Plaintiffs here] emphasize that the [Agencies] entered into agreements with ISO and CalPX that obligated them to abide by the ISO and CalPX tariffs. They argue that these agreements made it obvious to the [Agencies] that the tariffs setting the prices in the ISO and CalPX markets would be subject to FERC regulation .... All of this is true. 422 F.3d at 925.