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Panoche Energy Center, LLC v. Pacific Gas & Electric Co.

California Court of Appeals, First District, Fourth Division

July 1, 2016

PANOCHE ENERGY CENTER, LLC, Plaintiff and Respondent,

          Superior Court of San Francisco City & County, No. CPF13513060, Ernest H. Goldsmith, Judge.

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[Copyrighted Material Omitted]

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[Copyrighted Material Omitted]

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         Cooley, Martin S. Schenker, Jeffrey M. Gutkin and Lori R. Mason for Defendant and Appellant.

         Manatt, Phelps & Phillips, David L. Huard, Andrew A. Bassak, Benjamin G. Shatz and Kevin P. Dwight for Plaintiff and Respondent.

         Opinion by Streeter, J., with Ruvolo, P. J., and Reardon, J. concurring.


          [205 Cal.Rptr.3d 43] STREETER, J.


         This case involves a long-running dispute between Panoche Energy Center, LLC (Panoche), a producer of electricity, and Pacific Gas and Electric Company (PG& E), a utility that purchases electricity from Panoche, over which of them should bear the costs of complying with a legislatively mandated program to reduce greenhouse gas (GHG) emissions pursuant to the California Global Warming Solutions Act of 2006 (Health & Saf. Code, § 38500 et seq.; Assem. Bill No. 32 (2005-2006 Reg. Sess.) (Assembly Bill 32).

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         In an effort to resolve the matter, PG& E invoked the arbitration clause in its power purchase and sale agreement (PPA) with Panoche, seeking an arbitral declaration of Panoche's obligations under the PPA. Panoche resisted the arbitration, moving to dismiss or stay it on grounds the controversy was not ripe for resolution because of ongoing regulatory proceedings at the State Air Resources Board (CARB) and the Public Utilities Commission (CPUC). These proceedings, Panoche argued, would at least provide guidance in the arbitration and could render the proceeding unnecessary.

         The arbitration panel denied Panoche's motion, and after a five-day hearing rendered a decision declaring that Panoche had indeed assumed the cost of implementing Assembly Bill 32 under the PPA and fully understood this to be the case at the time of signing. In response to a counterclaim for declaratory relief filed by Panoche, the arbitrators also concluded that the parties " provide[ed] for recovery of GHG costs" by Panoche through a " payment mechanism" in section 4.3 of the PPA.

         Panoche filed a petition to vacate the arbitration award under Code of Civil Procedure[1] section 1286.2, subdivision (a)(5), alleging its rights were " substantially prejudiced" by the arbitrators' refusal to " postpone" the hearing " upon sufficient [205 Cal.Rptr.3d 44] cause being shown" (i.e., until the regulatory proceedings were completed so that the outcome of those proceedings could be considered in the arbitration). PG& E, for its part, requested confirmation of the award under section 1287.4. The trial court agreed with Panoche, ruled that the arbitration had been premature, and vacated the arbitration award.

         PG& E now appeals. We shall reverse the court's order vacating the arbitration award and direct that the award be confirmed.


         A. The Power Purchase Agreement

         PG& E, an investor-owned utility (IOU) regulated by the CPUC, provides gas and electrical service to some 15 million end users in northern and central California. In 2004, with the CPUC's approval, PG& E published a long-term request for offers (LTRFO) for the construction and operation of new electrical generating facilities to help meet anticipated future demands for electricity in northern California. Panoche, a Delaware-based privately owned energy production company, submitted a proposal to build a 400-megawatt, natural gas-fired electrical production facility in Firebaugh, near Fresno.

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         The ensuing negotiations concerning Panoche's proposal culminated in a PPA executed on March 28, 2006, which was approved by the CPUC in November 2006. Under the PPA, PG& E supplies natural gas to the Firebaugh facility, Panoche converts that gas into electricity, and PG& E purchases the electricity under a 20-year " tolling agreement" for a " peaking plant," meaning that PG& E dictates when the facility will be operated and how much electricity will be generated, and the plant runs only when PG& E's power needs are especially high and it needs extra power on its grid to ensure consistent power supply.

         B. Assembly Bill 32: The California Global Warming Solutions Act of 2006

         While the PPA was being negotiated, proposed legislation aimed at addressing climate change through the regulation of GHG emissions came before the California Legislature. As introduced in December 2004, Assembly Bill 32 dealt primarily with carbon emissions recordkeeping, reporting and protocols. It did not require electricity generators such as Panoche to bear any costs associated with reducing GHG emissions. But Assembly Bill 32 went through several amendments before it was finally passed at the end of August 2006, and as the bill progressed through the legislative process, it focused increasingly on reduction of GHG emissions.

         The Legislature was not alone in moving on this issue. In June 2005, Governor Schwarzenegger issued an executive order directing the California Environmental Protection Agency (CEPA) to coordinate the efforts of various state agencies to reduce California GHG emissions by certain target amounts between 2010 and 2050. (Governor's Exec. Order No. S-3-05 (June 1, 2005) at <> [as of July 1, 2016].) Specifically, the Governor called for reduction of GHG emissions to 1990 levels by 2020 and to 80 percent below 1990 levels by 2050. ( Ibid. )

         On August 15, 2005, an amendment to Assembly Bill 32 was introduced, including The California Climate Act of 2006, which would have required the CEPA " to institute a cap on greenhouse gas emissions" from, among other sectors, the electrical power industry. (Legis. Counsel's Digest, Assem. Bill 32, as amended Aug. 15, 2005, & introducing proposed Health & Saf. Code, § 42877, subd. (a)(2) [205 Cal.Rptr.3d 45] & (3) at <> [as of July 1, 2016].) The intent of the proposed amendments was to require the CEPA to " institute a schedule of emissions reductions for specified entities, develop an enforcement mechanism for reducing greenhouse gas emissions to the target level, and establish a program to track and report greenhouse gas emissions and to monitor and enforce compliance with the greenhouse gas emissions cap" by January 1, 2008.

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( Ibid. ) Although this amendment did not become part of the law as finally adopted, its pendency was no doubt on the radar screens of market participants in the energy field in California.

         By April 18, 2006, approximately three weeks after the PPA was signed, the Legislative Counsel's Digest for the version of Assembly Bill 32 then under consideration summarized the proposed legislation as follows: " The bill would require the state board to adopt regulations, on or before January 1, 2008, to reduce statewide greenhouse gas emissions to 1990 emission levels by 2020 ... ." (Legis. Counsel's Digest, Assem. Bill 32, as amended Apr. 18, 2006.) That iteration of the bill also included a requirement that the CARB adopt regulations to, among other things, " [d]istribute the costs and benefits of the program, including emission allowances, in a manner that is equitable, maximizes the total benefit to the economy, does not disproportionately burden low- and moderate-income households, provides compliance flexibility where appropriate, and ensures that entities that have voluntarily reduced their emissions receive appropriate consideration for emissions reductions made prior to the implementation of this program." (Legis. Counsel's Digest, Assem. Bill 32, as amended Apr. 18, 2006, proposed amends. to Health & Saf. Code § 42877, subd. (c)(1).) Again, though the quoted language was not ultimately included in Assembly Bill 32 as passed, it presumably constituted a red flag to participants in energy production indicating that costs would be entailed in implementing Assembly Bill 32 if it did ultimately pass.

         By June 2006, although the term " cap-and-trade" had not yet come into common use, Assembly Bill 32 had further evolved and began to include the concept of " allowances" --defined as " authorization[s] to emit, during a specified year, up to one ton of carbon dioxide equivalence" --and " '[f]lexible compliance mechanisms'" that would allow GHG emitters to " bank[], borrow[], and [use other] market mechanisms that provide compliance flexibility to entities that are required to ensure that their greenhouse gas emissions do not exceed their emissions allowances." [2] (Assem. Bill 32, as amended June 22, 2006, proposed amends. to Health & Saf. Code § 42876, subds. (a) & (g).)

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         After further amendment in late August 2006, Assembly Bill 32 was signed into law in September 2006 as the California Global Warming Solutions Act of 2006, some six months after the PPA was signed, and was codified as Health and Safety Code sections 38500-38599, [205 Cal.Rptr.3d 46] effective January 1, 2007. (See Stats. 2006, ch. 488, § 1, p. 3419.) As initially adopted, however, the legislation did not pinpoint how emissions were to be reduced or who was to pay associated costs. Those questions were left to CARB to answer.

         C. Impact of the Pending Legislation on PPA Negotiations

         According to PG& E, during the PPA negotiations the negotiators on both sides were aware of developments in the GHG legislation as it progressed through the Legislature, and they all understood it could have significant financial and other impacts on future energy production in California. PG& E claims that under [205 Cal.Rptr.3d 47] a " change in law" provision in the draft PPA, a clause it insisted upon in all of its power purchase agreements at the time, both parties fully understood Panoche would be responsible for any costs associated with the pending GHG legislation, and indeed the PPA negotiators specifically discussed the fact that this clause covered potential GHG compliance costs, even though the legislation had not yet progressed to the point where those costs could be quantified.

         Panoche, on the other hand, claims to have been blindsided by Assembly Bill 32. Panoche argues it was not foreseeable to energy producers until at least June 2006 that Assembly Bill 32 costs could become a major concern. The " change in law" provision, it argues, was just a " generic" clause that made no specific reference to Assembly Bill 32 or GHG costs and therefore did not apply to such costs; allocation of such costs was " never part of the parties' deal." Because such costs were not quantifiable when it signed the PPA, Panoche asserts it " would never have signed" if it had understood it would be on the hook for unknown and unquantifiable future costs.

         PG& E supports its position by pointing out that on December 16, 2004, eight days after Assembly Bill 32 was introduced in the Assembly and 15 months before the PPA was signed, the CPUC issued a long-term plan decision in which it insisted, for the first time, that PG& E and certain other utilities then in the process of negotiating power purchase agreements take into account the cost of GHG emissions in evaluating bids under the LTRFO. " To further the state's clear goal of promoting environmentally responsible energy generation, [the CPUC] also adopt[s] a policy that reflects and attempts to mitigate the impact of GHG emissions in influencing global climate patterns. As described in this decision, the IOUs are to employ a 'GHG adder' when evaluating fossil and renewable generation bids. This method, which will be refined in future proceedings, will serve to internalize

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the significant and under-recognized cost of GHG emissions, help protect customers from the financial risk of future climate regulation, and continue California's leadership in addressing this important problem." ( Opinion Adopting PG& E's Long-term Procurement Plans (Dec. 16, 2004) Cal.P.U.C. Dec. No. 04-12-048 [Id. at pp. *15-*16].)

         In response to the CPUC's long-term plan decision, PG& E updated its LTRFO to require bidders on new electrical generating facility projects to accept liability for changes in the law, and it specifically assessed applicants' bids in part on their willingness to assume financial responsibility for what PG& E deemed to be foreseeable changes in the law. In March 2005, PG& E reissued the LTRFO, requiring that all counterparties getting contract positions would have to take on the risk of future changes in the law,[3] specifically insisting on adherence to a " change in law" provision that cast upon PG& E's counterparty in each contract the obligation to assume the risk of associated costs.[4]

         Aside from the evidence of the negotiations surrounding the amended LTRFO, PG& E argues that at least as of the time of the August 2005 amendments to Assembly Bill 32, more than seven months before the PPA was signed, those following the progress of Assembly Bill 32 were aware that (1) GHG emissions would have to be reduced over time, (2) there would be a regulatory " cap" on such emissions, and (3) some " enforcement mechanism" would be used to ensure compliance. To a sophisticated participant in energy production such as Panoche, PG& E argues, all of this clearly signaled that the passage of Assembly Bill 32 would entail a significant new cost burden of GHG emissions reduction compliance.

         PG& E claims its view of what sophisticated parties would have known is more than a matter of revisionist history. It points out the CPUC has taken that view as well, opining in a 2012 settlement approval decision that " contracts negotiated and executed when AB 32 was working its way through

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the legislature should have taken the potential impacts of AB 32 into consideration. Even those negotiating contracts shortly before then might also have reasonably foreseen that this issue could arise." ( Decision on System Track I and Rules Track III of the Long-term Procurement Plan Proceeding and Approving Settlement (Apr. 19, 2012) Cal.P.U.C. Dec. No. 12-04-046 [Id. p. *93].) And in another 2012 decision, PG& E points out, the CPUC specifically identified the August 15, 2005 amendments as being a significant indicator that GHG costs should be considered in negotiating power purchase agreements. ( Decision Granting Petition for Modification of Decision 04-06-011 Regarding Otay Mesa Energy Center (Dec. 20, 2012) Cal.P.U.C. Dec. No. 12-12-002 [Id. pp. *13-*14].)

         D. The Regulatory Proceedings and the Cap-and-trade Program

         As noted, the Legislature largely delegated to the CARB the task of determining how best to implement the broad goal of reducing GHG emissions. (Health & Saf. Code, § 38501, subds. (f)-(h).) The CARB held public hearings to assist in formulating a plan for implementing Assembly Bill 32, and in June 2008, the CARB released a draft scoping plan that included a proposed " cap-and-trade" program for the first time. (CARB Climate Change Draft Scoping Plan (June 2008) Executive Summary, pp. ES-1 to ES-9 at <> [as of July 1, 2016].)

         After much consideration, on October 26, 2011, the CARB adopted final rules for [205 Cal.Rptr.3d 48] a GHG cap-and-trade program, which became effective January 1, 2012. (See " California Cap on Greenhouse Gas Emissions and Market-Based Compliance Mechanisms," Cal. Code Regs., tit. 17, art. 5, § 95801 et seq.) Under that program, utilities are granted free of charge emissions permits (called " allowances" ), each authorizing the emission of one metric ton of GHG. (Cal. Code Regs., tit. 17, § § 95820, subds. (a) & (c), 95892.) The utilities must then surrender their allowances to CARB, which in turn sells allowances to emissions generators, such as Panoche, in periodic auctions. (Cal. Code Regs., tit. 17, § 95910.) Allowances may be bought, banked, or sold. ( Id., § § 95910, 95920, 95922; Our Children's Earth Foundation v. State Air Resources Bd. (2015) 234 Cal.App.4th 870, 877 [184 Cal.Rptr.3d 365].) Energy producers must acquire, through quarterly auctions, sufficient allowances to cover the amount of their GHG emissions.

         For Panoche, continued operation of its power plant requires procurement of allowances, which will become increasingly expensive over time. The theory underlying cap-and-trade is that, as time goes by, fewer allowances will be issued, thereby raising the price of allowances and creating a financial

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incentive for energy generators to find ways to reduce GHG emissions. Reducing public consumption is also a component of the emissions reduction plan, so the CARB also wanted to send a " price signal" to consumers. As the details of the program came into sharper focus, both the CARB and the CPUC received specific input from stakeholders about who should bear the cost of allowances (i.e., emissions generators or utilities, which could pass the cost on to the ultimate consumers through their approved rates).

         Panoche claims the CARB made a policy determination that the ultimate consumer should bear the costs of GHG regulation on the theory that increased cost to the consumer would lead to reduced consumption and thus to curtailed GHG emissions. The CARB's final statement of reasons (FSOR) adopting the cap-and-trade program, dated October 2011, does say: " A primary goal of the program is to create a price signal to reduce greenhouse gas emissions." (CARB, FSOR for California's Cap-and-Trade Program (Oct. 2011) Response to Comment I-49, p. 592 at <> [as of July 1, 2016].) With respect to GHG compliance costs generally, the CPUC also expressed a policy preference that utilities pay the costs of GHG compliance and compensate generators for those costs, including through modifications to power purchase agreements if necessary.

         E. " Legacy Contracts"

         Once cap-and-trade was in place, both the CARB and the CPUC showed some sensitivity to the plight of energy producers whose contracts had been negotiated before Assembly Bill 32 went into effect, since those producers could be subjected to unexpected and unforeseeable costs associated with the cap-and-trade program. To the extent such costs were not considered in negotiating these antecedent contracts, the costs of cap-and-trade were likely to be " stranded" with these producers. Such contracts became known as " legacy contracts." The regulatory definition of that term--and whether the PPA in this case qualifies as a legacy contract--became a matter of intense dispute between Panoche and PG& E.

         Both Panoche and PG& E participated in the CPUC and CARB proceedings to implement the cap-and-trade regulation, advocating opposite viewpoints. While Panoche favored imposing GHG compliance [205 Cal.Rptr.3d 49] costs on the utilities and passing on the cost to consumers, PG& E advocated making the energy producers pay for allowances if they had contracted to do so. Panoche emphasized that its point of view best aligned with the intent of Assembly Bill 32 since putting compliance costs on utilities would send a " price signal" to consumers and thereby reduce consumption, but PG& E's theory was that where power purchase contracts are negotiated with anticipated GHG costs

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built into the price term, then the utility's ratepayers had already been paying those costs and should not be charged twice.

         With respect to Panoche in particular, PG& E told the regulators that Panoche had undertaken in the PPA to pay for costs related to Assembly Bill 32 and this was a " key issue in the parties' negotiations." Panoche told them the opposite: " The issue of GHG compliance cost responsibility is not addressed in the PPA, the CPUC testimony or exhibits, nor is there any allegation that [Panoche] would bear such potential costs in the CPUC public record." " Furthermore, the ... PPA does not include a change in law provision." Panoche even went so far as to say that " PG& E stated it was too early in the legislative process to address [GHG legislation] in the contract and withdrew the issue from consideration." Panoche further suggested to the CPUC it would be financially crippled and might be forced to discontinue operations if required to foot the whole bill for compliance with Assembly Bill 32. Panoche also opined that imposing Assembly Bill 32's GHG costs on energy generators might well be considered an unconstitutional " taking" or an " unlawful tax."

         In April 2012, the CPUC ordered utilities such as PG& E to renegotiate within 60 days any contracts entered before Assembly Bill 32's effective date that " do not address the allocation of AB 32 compliance costs," so that they would " be consistent with [the CPUC] policy," including revisiting if necessary " questions of whether the existing contract may have taken the passage of AB 32 into consideration." [5] (Cal.P.U.C. Dec. No. 12-04-046, supra, Id. at p. *94.) Panoche claims the CPUC was concerned with the fair treatment of independent energy producers, quoting the statement that it " appears somewhat arbitrary and unfair for the recovery of greenhouse gas compliance costs to vary between otherwise similarly-situated generators based on whether the applicable contract was signed before or after the passage of AB 32." [6] (Id. at p. *93.) [205 Cal.Rptr.3d 50] At the same time, the CPUC made clear it was not interested in " bailing ... out"

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energy producers who had simply made an error in business judgment during contract negotiations. (See fn. 6, ante.)

         Beginning in June 2012, Panoche and PG& E exchanged correspondence in which both claimed they had attempted to renegotiate their dispute, each blaming the other for failure of the negotiations. Nearing the end of the 60-day period specified in the CPUC's renegotiation order, PG& E requested an extension. The executive director of the CPUC replied in a letter dated June 20, 2012, that the 60-day period indicated in the renegotiation order was not intended to impose a deadline: " The [CPUC] has a strong preference that contract disputes be addressed by the signatories to the contract given that such parties have the most in-depth knowledge of the contract itself and their own operations." The letter advised PG& E that it " may and should continue to negotiate bilaterally," although the CPUC did not intend to allow the issue to " languish indefinitely." The impasse in renegotiation ultimately led to PG& E's filing of a request for arbitration some four or five months later.

         Meanwhile, after expiration of the 60-day renegotiation period, Panoche sought and was granted party status in the CPUC rulemaking proceeding ( Administrative Law Judge's Ruling Confirming Party Status, Cal.P.U.C. Ruling No. 11-03-012 (July 9, 2012) <> [as of July 1, 2016]) in early July 2012 and also successfully moved to enlarge the scope of the CPUC proceeding to consider which party should bear responsibility for GHG compliance costs in legacy contracts. At this point the dispute between the parties intensified because, according to PG& E, Panoche had misrepresented to the regulators the contractual provisions of the PPA. PG& E suggested Panoche cannot rightly be considered a party to a " legacy contract" at all and is not being saddled with costs " stranded" by the PPA. Instead, according to PG& E, Panoche negotiated and entered into the PPA with its eyes wide open to the potential costs associated with GHG emissions, and yet was trying to evade the bargained-for costs that it agreed to bear and, at least at that point in the dispute, was attempting to shift those costs to PG& E and its ratepayers.

         Panoche's version of events, not surprisingly, was sharply different. It told the CPUC on July 3, 2012: " The PPA does not address GHG compliance cost responsibility and does not compensate [Panoche] for the costs of obtaining GHG allowances ... ." In a separate filing the same date, Panoche elaborated: " The [Panoche] PPA includes no provision that can be reasonably read to assign GHG cost responsibility to [Panoche]. ... PG& E's position

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that [Panoche] assumed responsibility for GHG compliance costs and priced this cost into the price of energy in the PPA is not only completely unsupported by any provision in the PPA but also contrary to common sense. [Panoche] could not have priced GHG compliance costs into the PPA because GHG compliance costs were speculative and unquantifiable at the time the PPA was executed."

         In August 2012, two CPUC administrative law judges (ALJs) issued proposed criteria for determining whether parties to legacy contracts could obtain financial relief, which came to be known as " transition [205 Cal.Rptr.3d 51] assistance" to the new cap-and-trade regime. The CPUC requested comment on the following proposed " Eligibility Guidelines" : " We propose for comment that a contract between a generator and a utility must meet the following criteria in order to be eligible to receive relief, should the Commission decide relief is warranted, in this proceeding: [¶ ] 1. The contract must have been executed prior to the effective date of AB 32 (January 1, 2007); [¶ ] 2. The contract must not have been subsequently amended; [¶ ] 3. The contract does not provide for recovery of GHG costs, either explicitly or by virtue of a payment mechanism ... ; and, [¶ ] 4. The contract does not expire before the start of the first cap-and-trade compliance period (i.e., January 1, 2013)." ( Administrative Law Judges' Ruling Setting Forth Next Steps in Track 1 Phase 2 of This Proceeding, Cal.P.U.C. Ruling No. 11-03-012 (Aug. 7, 2012) <> [as of July 1, 2016].) The purpose of the proposal was to " set boundaries on the world of contracts that may be eligible for compensation." Compensation was not guaranteed by the establishment of these criteria, and no final resolution of the issue of stranded GHG costs was achieved. But at the time PG& E initiated arbitration some two or three months later, this pronouncement from the CPUC ALJs was the most recent regulatory iteration of the definition of a " legacy contract."

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Later in August 2012, Panoche submitted comments on the proposed criteria. First, Panoche urged the CPUC to adopt a bright-line rule granting transitional relief to all independent energy producers who entered into PPAs with utilities " executed prior to the ... effective date" of Assembly Bill 32, arguing this should be the " sole necessary criterion" for such relief. Second, Panoche suggested the CPUC " may wish to avoid establishing criteria that will require the [CPUC] to review and interpret individual contracts." And third, Panoche suggested the CPUC should " provide relief for any generator providing service under a legacy PPA that does not include an express and explicit provision imposing GHG emissions reduction program costs ... on the seller. Mere reference to GHG reporting, environmental attributes, or Clean Air Act emissions reductions credits in the PPA should not be construed as ...

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