Panoche Energy Center, LLC v. Pacific Gas & Electric Co. (1 Cal. App. 5th 68, 2016)

Opinion

STREETER, J.

I. INTRODUCTION

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).

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 California’s 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 section 1286.2, subdivision (a)(5), alleging its rights were “substantially prejudiced” by the arbitrators’ refusal to “postpone” the hearing “upon sufficient 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.

II. FACTUAL AND PROCEDURAL BACKGROUND

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.

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 Dig., Assem. Bill 32, as amended Aug. 15, 2005, & introducing proposed Health & Saf. Code, § 42877, subd. (a)(2) & (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. (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 Dig., 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, “[djistribute 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 Dig., 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^] to emit, during a specified year, up to one ton of carbon dioxide equivalence”—and “ ‘[flexible 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.” (Assem. Bill 32, as amended June 22, 2006, proposed amends, to Health & Saf. Code, § 42876, subds. (a) & (g).)

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, 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 signihcant hnancial and other impacts on future energy production in California. PG&E claims that under a “change in law” provision in the draft PEA, 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 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 [2004 Cal.P.U.C. Lexis 598 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, 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.

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 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 [2012 Cal.P.U.C. Lexis 192, 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 [2012 Cal.P.U.C. Lexis 563, 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 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 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 1-49, 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 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 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.” (Cal.P.U.C. Dec. No. 12-04-046, supra, 2012 Cal.P.U.C. Lexis 192 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.” (2012 Cal.P.U.C. Lexis 192 at p. *93.) At the same time, the CPUC made clear it was not interested in “bailing . . . out” 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 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 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.”

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 addressing GHG compliance costs nor should any implicit assumptions be the basis for denying relief to the generator.” (Original italics.) It appears, therefore, that Panoche was maneuvering in the regulatory proceedings to make sure its own PPA with PG&E would fit within the regulatory definition of a “legacy contract,” with the hope that it would then be deemed entitled to transition assistance.

PG&E’s comments on the proposed definition of “legacy contracts,” likewise, reflected the position it had been taking for years on who ought to bear the burden of Assembly Bill 32 GHG compliance costs. PG&E opposed inclusion in the eligibility criteria of any requirement that the contract “explicitly” or “specifically” allocate costs to the energy producers. (Pacific Gas and Electric Company’s (U 39 E) Comments on Administrative Law Judge’s Ruling on Track 1 Phase 2 Issues, p. 3 [as of July 1, 2016].) PG&E also proposed that if contracts were modified to shift GHG costs to PG&E, the energy producers should be required to accept in return certain contractual modifications “to ensure that PG&E’s customers are compensated for accepting GHG compliance cost responsibility for these sellers.” It further recommended the “use of contractual dispute resolution processes to resolve disputes over” individual contracts. {Ibid.)

Complicating the picture, in the fall of 2012 the CARB turned its attention to legacy contracts as well, which meant that regulatory proceedings on that issue were taking place before two different agencies. On September 20, 2012, the CARB issued a resolution stating its intention to develop a methodology to provide transition assistance to energy producers with a compliance obligation cost under the cap-and-trade regulation that could not be “reasonably recovered due to a legacy contract.” (CARB Resolution 12-33 (Sept. 20, 2012), p. 3 [as of July 1, 2016].) Although the CARB would ultimately take the lead in propounding regulations to deal with legacy contracts, at the time of the arbitration the most recent attempt to establish a working definition was the August 2012 definition by the CPUC ALJs.

F. The Arbitration

1. The initiation of the arbitration

Negotiation and mediation having failed, on November 8, 2012, PG&E initiated arbitration in accordance with the dispute resolution provisions of the PPA. A panel of three arbitrators was convened to hear the dispute: Judge W. Scott Snowden, retired; Judge Richard M. Silver, retired; and Attorney Martin Quinn.

PG&E sought a declaration that the PEA (1) “addresses GHG compliance costs” and “assigns responsibility for those costs to Panoche,” and (2) “at the time the PPA was signed, Panoche understood that, under the PPA, if there was a future change in law that imposed a cost on the facility because of its GHG emissions, Panoche would be responsible for paying that cost.” PG&E sought a definitive interpretation of the PPA in the hope of convincing the regulators that Panoche should not be entitled to “legacy contract” status or to transitional relief.

Panoche filed a counterclaim for declaratory relief that (1) the PPA does not “provide for recovery of GHG costs, either explicitly or by virtue of a payment mechanism” (based on the language of the CPUC ALJs’ August 2012 proposed eligibility criteria, and (2) “under section 3.1(b) of the PPA, [Panoche is not] required to bear AB 32 GHG compliance costs that exceed an annual average of the greater of $100,000 per year or $.50 per kW year.”

2. Panoche’s motion to dismiss or stay the arbitration

On January 15, 2013, Panoche filed a motion to dismiss or stay the arbitration pending further proceedings by the CARB and the CPUC. It argued PG&E’s declaratory relief claim was not “ripe” because of the pending regulatory proceedings. In Panoche’s view, the real dispute between the parties was in relation to how the regulatory bodies would allocate costs for allowances. According to Panoche’s theory, the action taken by the CARB and the CPUC would trump any contractual provision related to allocation of costs, and it was a waste of time and resources to arbitrate the contractual issues before the regulatory bodies had adopted a definite policy governing legacy contracts. Without the expected regulatory rules or criteria—rules or criteria that the CPUC and/or the CARB anticipated would issue by the end of August 2013—Panoche contended that it was impossible for the arbitration panel to reach a decision that would dispose of the controversy between Panoche and PG&E over GHG costs. The sole basis Panoche gave for requesting a stay or dismissal was the claim of unripeness.

PG&E argued the arbitration concerned a simple matter of contract interpretation based on an analysis of the PPA’s terms and the course of negotiations that occurred in 2005 and 2006. According to PG&E, this was not the same broad policy issue relating to overall GHG cost allocation that the CARB and the CPUC were considering, and the regulatory bodies had no intention of delving into the details of individual PPAs. Moreover, PG&E claimed, the CPUC had directed PG&E to attempt to renegotiate its PPA with Panoche, which included the question whether “the existing contract may have taken the passage of AB 32 into consideration.” (Cal.P.U.C. Dec. No. 12-04-046, supra, 2012 Cal.P.U.C. Lexis 192 at p. *94.) And, of course, PG&E argued that an arbitration award settling the parties’ contractual dispute would not be simply an “advisory” opinion, but rather would be useful to the regulators in determining public policy.

The arbitrators found the dispute was ripe for adjudication and denied Panoche’s motion. They reasoned: “Panoche has failed to demonstrate how proceeding with this arbitration would either replicate, interfere or conflict with, or provide an advisory opinion to the ongoing CPUC and CARB proceedings. Indeed, by Panoche’s own admission, these public agencies are merely deciding how to handle power purchase agreements that were executed prior to AB 32 that lack terms and conditions specifically designating responsibility for GHG costs. . . . They are not deciding whether any individual contracts, such as the parties’ PPA, actually lacked such terms and conditions—the sole and exact issue before the Panel here. [¶] Thus, because PG&E has presented a real controversy that is appropriate for immediate judicial resolution because it concerns an issue that will not be resolved by either of the public agencies, this contractually-agreed-to forum is the appropriate venue for the parties to resolve their claims.” After significant discovery was conducted, a five-day arbitration was held in April 2013.

3. The arbitrators’ decision on the merits

On May 2, 2013, the panel reached its decision, ruling in favor of PG&E. As quoted above, the PPA included section 3.6(a), a change in law provision, under which PG&E claimed the costs of compliance with Assembly Bill 32 had been assumed by Panoche. (See fn. 3, ante.) That provision required Panoche to “comply with all applicable requirements of Law . . . relating to the Facility” and to “be responsible for procuring and maintaining, at its expense, all Governmental Approvals and emissions credits required for operation of the Units throughout the Service Term . . . .” “Law” was also defined in the PPA to include a “statute, law, . . . [or] enactment,” including one “enacted, amended, or issued after the Execution Date [of the PPA] and which becomes effective during the Contract term,” and it also included “regulation[s].” Thus, the arbitrators ruled that both Assembly Bill 32 and the CARB’s cap-and-trade regulations were part of the “Law,” as defined in the PPA, and by committing to comply with the “Law” within the meaning of the PPA, Panoche had contractually agreed to bear the costs of compliance. The arbitrators specifically concluded that “[o]ne such ‘Law’—the cap-and-trade regulations—requires entities such as Panoche to pay for and acquire sufficient GHG allowances to cover their carbon emissions. Panoche, therefore, agreed to comply with this requirement of the cap-and-trade regulations.”

Both the term “Law” and the term “Governmental Approval” as used in the PPA were also defined to include an “authorization.” Because an “allowance” is defined by statute as “an authorization to emit, during a specified year, up to one ton of carbon dioxide equivalent” (Health & Saf. Code, § 38505, subd. (a)), the emission allowances required under Assembly Bill 32 and its implementing regulations constituted “Governmental Approvals” within the meaning of the PPA, and “Panoche, therefore, contractually agreed to procure AB 32 allowances at its expense.” Despite the fact that GHG emissions were never mentioned by name in the PPA, the arbitrators concluded the PPA’s “change in law” provision required Panoche to assume the costs of GHG compliance.

The arbitrators found support for this conclusion in the testimony of Panoche’s lead negotiator, Keith Derman, one of Panoche’s key witnesses in the arbitration. Derman was a partner at Energy Investors Funds (EIF), a private equity fund based in Boston, Massachusetts, that owns the Firebaugh plant. He admitted in a deposition that he understood when the PPA was signed that the “four corners of the contract” made Panoche responsible for the costs “if a government law changed and imposed a cost on Panoche relating to the facility’s carbon emissions.” His follow-up observation that “there was no specific language in the agreement to deal with greenhouse gases” struck the arbitrators as “unpersuasive.”

As further support for their decision, the arbitrators noted that during contract negotiations, in response to PG&E’s proposed change in law amendments, Panoche suggested that it should receive higher compensation in the event of a change in the law that imposed higher costs of performance on Panoche, but this change was never incorporated into later revisions. Panoche also proposed that both parties share responsibility for compliance with all applicable requirements of law; that the PPA should eliminate the language specifying that Panoche would have to pay for all “Governmental Approvals”; that Panoche could not be declared in default if it was unable to (or simply failed to) obtain necessary Governmental Approvals; that the PPA should eliminate the requirement that Panoche obtain all needed “emissions credits”; and that the force majeure clause should be modified to include Panoche’s “inability to obtain and maintain any governmental Approvals required The markups of the PPA also show a note by Panoche requesting that the parties “[djiscuss change in law issues.”

PG&E also sent a letter to Panoche explaining that Panoche’s proposed changes to the amended PPA “would make major changes to the benefits and burdens of PG&E’s form PPA, significantly affecting the value of your Final Offers to PG&E.” PG&E insisted that Panoche’s offer “needs improvement in order to be further considered.” Despite Panoche’s early resistance to the changes, negotiations continued and Panoche eventually accepted PG&E’s proposed amendments to the PPA so that section 3.6(a) now reads as quoted in footnote 3, ante.

Documents generated by Panoche outside of the direct negotiations confirmed Panoche’s contemporaneous understanding that it bore the risk of costs to comply with future GHG legislation. For instance, in a memorandum in March 2006 (before the PPA was signed), Derman advised EIF’s investment committee of the benefits and risks of the Panoche project, noting as a risk that “there is remaining fear that [California] is monitoring carbon emissions” and that there was “no current mitigation in place” to address this risk. He testified in his deposition it was “true” that he understood that “California might impose a cost on carbon emissions.” The arbitrators found Derman’s admissions “telling” in reaching their conclusions.

EIF also issued a bond offering memorandum some two years after the PPA was signed (but before the present dispute arose), which discussed Assembly Bill 32, including that its “regulatory program may include a trading market for greenhouse gas emissions credits” and “the Facility [in Firebaugh] . . . likely will be required to comply with these AB 32 regulations” and “likely . . . will participate in the greenhouse gas emissions credit market, and will be required to make certain expenditures from time to time to purchase such credits.” The arbitrators also considered this document to be “proof of Panoche’s understanding and consideration of the impact that AB 32 could have on the [Firebaugh] Facility and its bottom line

Panoche argued that it would never have accepted the cost risk associated with GHG emissions because it would have viewed this risk as too “unknown, unlimited, unquantifiable.” The arbitrators, however, found “overwhelming evidence” to the contrary. The arbitrators tracked the drafting changes proposed to the PPA during negotiations, which (as outlined above) showed that Panoche had initially resisted taking responsibility for costs of implementing Assembly Bill 32, but eventually agreed.

After weighing the evidence bearing on the parties’ contracting intent, the arbitration panel found “clearly, Panoche was aware that it would be responsible for paying the cost of any change in law that imposed a cost on the Plant because of its GHG emission.” The arbitrators concluded Panoche’s failure to raise its price for electricity after PG&E insisted on the change in law provision reflected its “own evaluation of the risks”—which some of its witnesses considered “minimal”—rather than any misunderstanding that it was assuming the cost of changes in the law. Though they did not use the term “business judgment,” the arbitrators found in essence that Panoche appreciated the risk involved in its decision not to raise the price of electricity in its bid after being forewarned by PG&E that it would be required to cover Assembly Bill 32 compliance costs. Evidently, though, Panoche wanted to be awarded the contract with PG&E badly enough that it took a gamble that those risks would not prove too onerous. The arbitrators found that the contract price in the PPA took into account the costs associated with Assembly Bill 32’s impending GHG regime. And the panel concluded there is no danger that Panoche will lose money on the contract, specifically finding that “Panoche’s projected profit margins were of such a substantial size . . . that there was still ample room for profit even with GHG compliance costs being considered.”

In light of their findings, the arbitrators granted PG&E’s request for declaratory relief on both of its issues, as follows: (1) “It is hereby declared that the PPA addresses greenhouse gas emissions . . . compliance costs and assigns responsibility for those costs to Panoche” and (2) “It is hereby declared that at the time the PPA was signed, Panoche understood that, under the PPA, if there was a future change in the law that imposed a cost on the facility because of its GHG emissions, Panoche would be responsible for paying that cost.” The arbitrators emphasized they were “not rendering an advisory decision on an issue of great policy importance,” but rather were concerned solely with “contract interpretation” and “what, exactly, the [p]arties understood.”

With respect to Panoche’s first counterclaim for declaratory relief, the panel was not swayed by the fact that the PPA does not specifically mention cost recovery for Assembly Bill 32 allowances or GHG emissions by name and found that fact was “not dispositive.” The arbitrators found there was a “payment mechanism” in place under the PPA that allowed Panoche to recover GHG costs in that PG&E was required under section 4.3 of the PPA to make “full payment” for the electrical power produced by Panoche, in accordance with formulas set forth in the PPA. The arbitrators therefore denied Panoche’s first counterclaim for declaratory relief. Panoche’s second counterclaim for declaratory relief sought to establish limits on Panoche’s liability for GHG costs based on section 3.1 of the PPA, which covered “Resource Adequacy Requirement.” The arbitrators found that section inapplicable to GHG costs and denied the requested relief. Finally, the arbitrators postponed decision on attorney fees and costs under the PPA, section 12.4(c).

Eight days after the arbitrators’ decision, PG&E advised the CPUC of the arbitrators’ decision, apparently sending it a copy of the arbitration award. Shortly thereafter, on June 25, 2013, Panoche petitioned the superior court for an order vacating the award under section 1286.2, subdivision (a)(5). The award remained in effect from its inception until vacated by the superior court in late September 2013.

G. Additional Regulatory Developments While the Arbitration Award Was in Effect

Even as the arbitration proceeded and afterwards, the regulators continued attempting to decide how to deal with legacy contracts. On May 1, 2013, the CARB held a workshop to discuss the issue of legacy contracts with stakeholders, at which it was suggested that contracts involving IOUs and contracts involving other utilities should all be dealt with by the CARB, not the CPUC, and should be subject to the same rules. Beginning in late June 2013, the CPUC began expressing a willingness to cede authority to the CARB over contracts involving IOUs, so that all parties in legacy contracts would be treated the same; ultimately, in March 2014, the CPUC did cede authority to the CARB. (Decision Clarifying Commission Policy on Greenhouse Gas Cost Responsibility for Contracts Executed Prior to the Passage of Assembly Bill 32 (Mar. 13, 2014) Cal.P.U.C. Dec. No. 14-03-003 [2014 Cal.P.U.C. Lexis 145, p. *1] (Decision Clarifying CPUC Policy).)

The CARB proposed a new regulation on July 15, 2013, that would provide transition assistance to energy producers in legacy contracts through the year 2014. The essence of that regulation, as will be discussed more fully below, was that energy producers who were party to a PPA in which the “price . . . does not provide for recovery of the costs associated with compliance with” the cap-and-trade program would be entitled to free “direct allocation” of allowances by the CARB through 2014. (Cal. Code Regs., tit. 17, §§ 95802, subd. (a)(204), 95890, subd. (e), 95894.)

In recommending the new regulations, the CARB staff identified 19 contracts in dispute statewide and said: “In all cases, [the CARB] has encouraged resolution through contract renegotiation between the parties. In several cases, renegotiation has resolved the legacy contract concern. [The CARB] understands the approximately 19 remaining contracts to be in various stages of renegotiation. [The CARB] continues to encourage private resolution.” The regulation the CARB proposed, staff believed, “maintain[ed] a strong incentive to continue renegotiation.”

Stakeholder commentary on the proposed regulations continued through the summer, including commentary from PG&E and Panoche. Generally speaking, Panoche supported the new CARB regulation, while PG&E recommended changes. Among other things, PG&E suggested that “transition assistance” be provided only to those energy producers who signed contracts before August 15, 2005, when PG&E claimed the prospect of GHG-related costs was already clear. PG&E also suggested that the definition of legacy contracts should exclude contracts of energy producers against whom an arbitrator had ruled on the contract dispute with the utility. PG&E also suggested that the CARB incorporate into its definition of “legacy contracts” language designed around its own second claim for declaratory relief: namely, that a power purchase agreement would not be considered a legacy contract if, “at the time the agreement was executed, the [energy generator] understood that if there were a future change in the law that imposed a cost on the facility because of its greenhouse gas emissions, the [energy generator] would be responsible for paying that cost.” These changes were not adopted by the CARB.

On September 4, 2013, while Panoche’s petition to vacate the arbitration award was still pending, the CARB issued an initial statement of reasons (ISOR) for its proposed regulations, including proposing to add a definition of “legacy contracts” that in substance is identical to the definition ultimately adopted some nine months later. (Compare CARB, Proposed Amendments to the California Cap on Greenhouse Gas Emissions and Market-Based Compliance Mechanisms, ISOR, appendix E (Sept. 4, 2013) Proposed Regulation Order, § 95802, subd. (a)(195) at [as of July 1, 2016] with current Cal. Code Regs., tit. 17, § 95802, subd. (a)(204).)

With respect to consideration of individual contracts, the ISOR explained: “[The CARB] is not in a position to have full knowledge of the original negotiation and how GHG costs were discussed during these contract negotiations. In comments that [the CARB] received, there was apparent disagreement during the various discussions among parties as to how to consider the inclusion of such costs. It is not appropriate for [the CARB] to interject itself into the interactions between parties in private contract discussions where [the CARB] cannot possibly know what both sides intended when they executed the contract.”

The ISOR did not, however, abandon the notion that the parties should continue trying to resolve their differences independently: “While [the CARB’s] preferred approach to resolving the situation is for the parties to renegotiate the contracts, [the CARB] recognizes that renegotiation takes time.” In the meantime, the ISOR explained, transitional relief for generators in legacy contracts would be provided under section 95894 of title 17 of the Code of Regulations.

H. The Court Order Vacating the Arbitration Award

Panoche brought its petition to vacate the arbitration awards under section 1286.2, subdivision (a)(5), which authorizes a court to vacate an arbitration award if the “rights of the [petitioning] party were substantially prejudiced by the refusal of the arbitrators to postpone the hearing upon sufficient cause being shown . . . .” Under that section, if the statutory requirements are met, the court “shall” vacate the arbitration award. PG&E opposed the petition and requested that the court instead confirm the arbitrators’ interim award and enter judgment accordingly pursuant to section 1287.4. Again, Panoche’s briefing focused exclusively on the concept of ripeness, but this time it attempted to mold its arguments to fit within the linguistic frame established by section 1286.2, subdivision (a)(5) by arguing that the lack of ripeness constituted “sufficient cause” to “postpone” the arbitration.

On September 20, 2013, the trial court, having been kept up to date on the regulatory developments, granted Panoche’s petition. The court ruled that Panoche’s ripeness motion before the arbitration panel could be reviewed under section 1286.2, subdivision (a)(5) because (1) it amounted to a request to “postpone” the arbitration within the meaning of the statute; (2) it was supported by “sufficient cause”; and (3) Panoche was “substantially prejudiced” by the arbitrators’ refusal to grant a delay in the proceedings while the CPUC and the CARB completed their regulatory proceedings. PG&E filed a timely notice of appeal from the court’s order.

I. Further Regulatory Developments After the Appeal Was Filed

In response to a request by Panoche, we take judicial notice of the following developments in the regulatory proceedings after the notice of appeal was filed. On November 8, 2013, the CARB proposed the amendments to the cap-and-trade regulation from the September 2013 ISOR, discussed above. Those amendments were adopted by the CARB in April 2014, and went into effect July 1, 2014. (CARB, Amendments to California Cap on Greenhouse Gas Emissions and Market-Based Compliance Mechanisms, Resolution 14-4 (Apr. 25, 2014) (CARB Resolution 14-4) at [as of July 1, 2016]; history foil. Cal. Code Regs., tit. 17, § 95894.)

Meanwhile, at the CPUC, by February 10, 2014, an ALJ had also addressed the issue of legacy contracts in a proposed decision (Proposed CPUC Clarification Decision) setting forth a policy statement of the CPUC with respect to legacy contracts: “It is the policy of the [CPUC] that greenhouse gas costs and responsibility for such costs should be clearly articulated in Legacy Contracts in order to account for greenhouse gas costs in generation dispatch decisions. The [CPUC] reiterates this policy and orders the utilities to continue renegotiating contracts to include provisions to ensure that generators party to Legacy Contracts receive compensation for their greenhouse gas costs.” The proposed decision again expressed the CPUC’s disinclination to address the issue by interpreting individual contracts: ‘“[The CPUC] does not find it appropriate to address issues of greenhouse gas cost responsibility at the individual contract level.” We do not read that statement to mean that issues concerning contractual interpretation were to be ignored. Instead, the ALJ said, ‘“The [CPUC] has consistently encouraged parties to resolve disputes over GHG cost responsibility in Legacy Contracts through negotiation and settlements or (if necessary) through the dispute resolution processes articulated in existing contracts.” These observations were retained in the CPUC’s Decision Clarifying CPUC Policy, supra, 2014 Cal.P.U.C. Lexis 145 at p. *1.

In the Proposed CPUC Clarification Decision, the CPUC also made the following observation: “Most of the contracts raised in this proceeding, including the Panoche contract, were negotiated and signed at a time when it was reasonably foreseeable that there would be costs for GHG compliance in the future, but the extent to which such costs were accounted for in the contracts may not be clear. To the extent that these Legacy Contracts do not contain terms that explicitly allocate responsibility for GHG compliance costs, it may not be clear which party, if any, bears responsibility for those costs under the contract. It would be inappropriate to amend a contract to require utilities and their ratepayers to pay those compliance costs a second time if they were accounted for in the original contract. At the same time, the [CPUC] is not in a position to know whether GHG costs are already embedded in existing contracts; that is a factual question that is beyond the scope of this proceeding. To make these factual determinations, Legacy Contracts must be examined individually, and avenues exist, such as a contract’s explicit dispute resolution process, that are more appropriate than this proceeding for resolving questions of the presence or absence of specific GHG cost compensation terms and conditions in Legacy Contracts.” (Italics added & fn. omitted.) The final decision omitted the first sentence of the quoted paragraph at Panoche’s request. (See Decision Clarifying CPUC Policy, supra, 2014 Cal.P.U.C. Lexis 145 at pp. *14-*15, *19-*20.)

At the same time, however, the CPUC decided to defer to the developing CARB regulations on the issue of legacy contracts. Essentially, the CPUC decided that energy producers in contracts with IOUs should be treated the same as producers under contract with other utilities. The regulations now in force include the definition of ‘“Legacy Contract” adopted by the CARB: “ ‘Legacy Contract’ means a written contract or tolling agreement, originally executed prior to September 1, 2006, governing the sale of electricity and/or legacy contract qualified thermal output at a price, determined by either a fixed price or price formula, that does not provide for recovery of the costs associated with compliance with this regulation; the originally executed contract or agreement must have remained in effect and must not have been amended since September 1, 2006 to change or affect the terms governing the California greenhouse gas emissions responsibility, price, or amount of electricity or legacy contract qualified thermal output sold, or the expiration date. . . .” (Cal. Code Regs., tit. 17, § 95802, subd. (a)(204), italics added.) Energy producers who are parties to legacy contracts are granted “direct allocation” of allowances from the CARB, at no cost to the producers, under the new regulations. (Id., § 95894.)

However, before receiving the first such direct allocation, and for each year in which an energy producer seeks to renew its eligibility, it is required to make a “[djemonstration of [eligibility,” including an attestation under penalty of perjury that its PPA “does not allow the covered entity to recover the cost of legacy contract emissions from the legacy contract counterparty purchasing electricity and/or legacy contract qualified thermal output from the unit or facility.” (Cal. Code Regs., tit. 17, § 95894, subd. (a) & (a)(3)(A).) This requirement was included because it was “necessary to prove the information declared is true and to facilitate [the CARB] legal action against the entity requesting allowance allocation if the information submitted is false information.” We take judicial notice that Panoche was granted transition assistance for the years 2013, 2014 and 2015 after review of its application for the reporting period ending September 2, 2014.

III. DISCUSSION

A. Because the PPA Restricted the Arbitrators’ Power to That of a California Superior Court Judge, the Arbitrators Were Not Authorized to Entertain an Unripe Dispute.

Panoche structured its arguments both in the arbitration and before the trial court around a tenet of justiciability—ripeness—that is fundamental to judicial decisionmaking. But does the concept of ripeness apply in an arbitral setting to the same extent that it applies in court? After briefing in this appeal was completed, Division Four of the Second District Court of Appeal answered that question in the negative in Bunker Hill Park Ltd. v. U.S. Bank National Assn. (2014) 231 Cal.App.4th 1315 [180 Cal.Rptr.3d 714] (Bunker Hill). Absent an agreement by the parties to import the doctrine of ripeness into their arbitration contract, the panel explained in Bunker Hill, a dispute that might not be justiciable in court for lack of ripeness is nonetheless arbitrable if it otherwise falls within the scope of the governing arbitration clause. (Id. at pp. 1325-1330.)

Bunker Hill reasoned: “Arbitration is foremost a creature of contract. [Citation.] ‘Arbitration’s consensual nature allows the parties to structure their arbitration agreements as they see fit. They may limit the issues to be arbitrated, specify the rules and procedures under which they will arbitrate, designate who will serve as their arbitrator(s), and limit with whom they will arbitrate.’ [Citation.] Contracting parties also are free to negotiate and restrict the powers of an arbitrator and the universe of issues that he or she may resolve; ‘ “[t]he powers of an arbitrator derive from, and are limited by, the agreement to arbitrate.” ’ [Citation.] ‘As for the requirement that there exist a controversy, it is sufficient the parties contractually have agreed to resort to a third party to resolve a particular issue.’ [Citation.] ‘The limited function reserved to the courts in ruling on an application for arbitration is not whether the claim has merit, but whether on its face the claim is covered by the contract.’ [Citation.] Thus, we look to the terms of the parties’ contract to ascertain whether they agreed to arbitrate a particular disagreement or to restrict the arbitrator to resolving certain issues.” (Bunker Hill, supra, 231 Cal.App.4th at p. 1326.) Based on the foregoing considerations, the Court of Appeal in Bunker Hill ordered the superior court to compel the arbitration to proceed. (Id. at p. 1330.)

Bunker Hill recognized that parties may contractually limit arbitrators’ roles to the adjudication of justiciable controversies, and the present dispute is one in which they have done just that. The clause in question, part of the arbitration provision (section 12.4(c)), does not actually mention ripeness or justiciability, but simply provides: “The Parties are aware of the decision in Advanced Micro Devices, Inc. v. Intel Corp., 9 Cal.4th 362 [36 Cal.Rptr.2d 581, 885 P.2d 994] (1994), and, except as modified by this Agreement, intend to limit the power of the arbitrator to that of a Superior Court judge enforcing California Law.”

In Advanced Micro Devices, Inc. v. Intel Corp., supra, 9 Cal.4th 362 (Advanced Micro Devices), the Supreme Court upheld an arbitrator’s award that arguably exceeded the powers a superior court judge could have exercised in fashioning a remedy for breach of contract. (Id. at pp. 367, 390-391.) Specifically, the arbitrator fashioned a remedy for Intel’s breach of implied covenants of good faith and fair dealing that gave Advanced Micro Devices (AMD) a permanent, nonexclusive, royalty-free license to Intel’s 8086 generation of microprocessors. (Id. at pp. 385-386.) AMD petitioned to have the superior court confirm the award (§§ 1286, 1287.4), and Intel petitioned for it to correct the award (§ 1286.6) by striking two paragraphs, arguing that the remedy granted by the arbitrator exceeded the contractual remedies for breach. (Advanced Micro Devices, supra, at p. 371.) The trial court confi