Some Types of Government-Supported Power Contracts Hit Headwinds

Some Types of Government-Supported Power Contracts Hit Headwinds

November 20, 2014 | By Robert Shapiro in Washington, DC

Two federal court decisions in September will affect some types of government-supported power contracts that independent generators sign with utilities.

A US appeals court in New Jersey ruled in mid-September that a New Jersey program under which the state public utilities commission solicited bids for gas-fired capacity and required the New Jersey utilities to sign long-term power purchase agreements with the winning bidders was unconstitutional under the supremacy clause of the US constitution.

The decision is consistent with a similar opinion by another US appeals court in June 2014 that invalidated a similar directive by Maryland requiring utilities to sign long-term contracts for gas-fired capacity following a state-mandated solicitation.

Both courts found that the state directives infringed on the exclusive jurisdiction given to the Federal Energy Regulatory Commission over wholesale electric rates.

Meanwhile, a US appeals court in Texas ruled in September that a state regulatory commission can decline to require utilities to enter into power contracts with wind (and by analogy solar) generators – notwithstanding a 1978 federal law called the Public Utility Regulatory Policies Act, or PURPA, that requires utilities to buy electricity from small power producers whose projects are up to 80 megawatts in size — because wind projects do not produce “firm power.” The Texas decision is at odds with the Federal Energy Regulatory Commission interpretation of the PURPA rules on this point.

State-Mandated Contracts

The parties in the New Jersey litigation have 90 days to ask the US Supreme Court to review the decision. Review by the Supreme Court is discretionary, and the fact that two appeals courts have each unanimously reached the same legal conclusion makes it less likely that the Supreme Court will take the case. Maryland already announced that it will seek Supreme Court review of the June appeals court decision involving the Maryland program, and it received an extension from the Supreme Court until November to file its appeal.

Although each of the courts emphasized that its holding applies only to the state-specific program at issue in each case, the holdings have broader implications for other state programs that require regulated utilities to sign wholesale electricity contracts.

As a general matter, the Federal Power Act gives FERC the exclusive jurisdiction over wholesale electric rates in interstate commerce in the lower 48 states.

There are exceptions. Rates of “qualifying facilities” under the PURPA can be established under state rules that must follow FERC implementation requirements. ERCOT in Texas is electrically isolated from the rest of the country and is outside the Federal Power Act. Finally, municipal utilities and most electric cooperatives are not subject to FERC rate jurisdiction.

States have jurisdiction over the retail rates charged by utilities, utility resource plans and generating facility and transmission facility construction matters.

The issue in the New Jersey and Maryland cases concerns the extent to which a state program can encourage the construction of generating plants by providing incentives that implicate wholesale rates.

What New Jersey Did

The state mandate in the New Jersey case required utilities to sign a “contract for differences” for generating capacity under a state program known as the long-term capacity pilot program or “LCAPP.” Each selected winning bidder under the contract for differences had to bid its capacity into the PJM capacity auction, which occurs every year, to supply capacity for a year three years in the future. FERC had approved the capacity auction mechanism that PJM used to set a specific capacity price for all projects that are selected in the auction. If the bidder was selected by PJM, then the bidder would receive from or pay to the electric utility counterparty the difference between the PJM auction capacity price and the fixed price in the contract for differences. Thus, the contract for differences in essence fixed the capacity price for a long term, in this case 15 years, regardless of the capacity price that the bidder receives in the annual PJM capacity auction.

New Jersey argued, among other things, that it did not set a wholesale price by contract, but rather conducted a bidding program that resulted in a contract with a bidder’s own price. In addition, it argued that the contract for differences was not a wholesale contract at all, but rather a financial hedge because it only provided a pricing hedge and the offtakers did not actually purchase anything. In addition, New Jersey argued that the FERC-approved PJM auction price was not disturbed by the contract for differences mechanism, as the bidders had to follow the PJM bidding rules and the PJM capacity results and rules if selected. The bidder continues to receive the established auction price in the PJM market, but the contract adjusts the payments to the bidder if the market price is higher or lower than the fixed contract price.

What the Court Said

The appeals court asked FERC to give its views to the court in anamicus or “friend-of-the-court” brief. FERC told the court that it believed that the New Jersey program was preempted under the supremacy clause of the US constitution because it “directly affects wholesale rates, and, to that extent, is a preempted intrusion upon the Commission’s exclusive jurisdiction to regulate wholesale rates” and “the state subsidy is directly and explicitly tied to the wholesale rate.”

The court did not view the argument that the New Jersey program had only an incidental effect on the interstate wholesale price of electric capacity to be a legitimate basis for finding preemption. In fact, it said that a decision that New Jersey was impermissibly affecting the wholesale electricity price through its program would leave the states “with no authority whatsoever to regulate power plants because every conceivable regulation would have some effect on operating costs or available supply.” However, the court said that, in approving bid prices for capacity and requiring utilities to pay those prices in the long-term contracts, the state was regulating wholesale capacity rates, the “same subject matter that FERC has regulated through” the PJM capacity auction and, therefore, had a direct conflict.

The court, like the appeals court before it that reviewed the Maryland program, found that the New Jersey contracts for differences were more than mere financial hedges created to remove the risk of market volatility. It said the contracts “provide for the supply and sale of capacity as well” by requiring the seller to sell into PJM markets and, in exchange, requiring that the seller receive a price that is not tied to the PJM capacity auction price. According to the court, this directive “essentially sets a price for wholesale energy sales” in violation of the Federal Power Act and is, therefore, preempted by federal law.

The court was careful to point out that states retain a legitimate role in the regulation of energy markets.

In particular, it gave examples of other permissible state action to encourage the development of new generation to meet state energy goals, including the use of tax-exempt borrowing authority, the granting of property tax relief, the ability to enter into favorable site lease agreements on public lands, the gifting of environmentally-damaged properties for brownfield development, and the relaxing or acceleration of permit approvals. However, it should be noted that none of these alternative state actions involves a state program that directs utilities to sign contracts with specific wholesale rates.

Potentially Broader Implications

Although several state commissions intervened in support of the New Jersey program and argued that an adverse decision on constitutionality could have an adverse impact on other types of state programs, the appeals court refused to consider the implications of its holding on those other programs, which was also the case with the appeals court that reviewed the Maryland program.

The court said the defenders of the New Jersey LCAPP “fret that a decision in favor of preemption will hamstring state-led efforts to develop renewable and reliable electric energy resources.” It responded that it was only deciding that the particular LCAPP program improperly occupied the field of capacity prices left exclusively to FERC.

But the difficulty with the appeals court decisions about both the New Jersey and Maryland programs is that their attempts to limit the holdings of unconstitutionality to state actions to fix wholesale capacity prices for a long term pursuant to state programs also arguably applies to state action to fix wholesale energy prices for a long term pursuant to state programs. Except for the previously noted exceptions not applicable here, FERC has exclusive wholesale ratemaking jurisdiction over energy prices as well as capacity prices.

Neither appeals court provided any indication whether there could be an acceptable state program that would involve a directive to a regulated utility to sign a long-term wholesale power contract to purchase capacity or energy.

A majority of states now have renewable portfolio standard laws that require regulated utilities to purchase a minimum percentage of their energy needs from renewable sources, and many of those states require competitive bidding or bilateral contracting for those resources with the result that the utilities must sign long-term power contracts with fixed energy prices. The courts have not provided guidance about the constitutionality of these programs, nor has FERC offered, or been asked to offer in court, its view about the consistency of such programs and contracts with FERC’s Federal Power Act jurisdiction.

There may well be sufficient factual distinctions between the LCAPP program and other state programs for RPS projects and other generating resources that set long-term wholesale purchase rates that are sufficient for both the courts and FERC to conclude that these state programs are compatible with the dictates of the Federal Power Act. But the two appeals courts have provided no roadmap for the states from their recent decisions.

Because the courts have refused to provide guidance for other state programs, it is not possible to predict whether such programs will be vulnerable to similar constitutional challenges or, if such challenges are successful, whether existing contracts signed pursuant to such programs would be vulnerable to challenge as well. Courts have broad discretion in fashioning remedies in cases of invalidation of state action on constitutional grounds and would probably take into account the impact on parties that have detrimentally relied on the lawfulness of the affected state program, particularly if the program has been in existence unchallenged for a period of years. While there can be no assurance that existing contracts would be “grandfathered” from change following a successful constitutional challenge to a state program, the equities would weigh heavily in favor of such a result.

PURPA Contracts in Texas

The Federal Energy Regulatory Commission issued regulations under PURPA that required utilities to purchase electricity produced by independent generators known as “qualifying facilities” or “QFs” at the utility’s “avoided cost”, meaning the cost the utility would have spent to generate the electricity itself or to purchase it from another source. QFs are small renewable power projects up to 80 megawatts in size as well as cogeneration projects of any size. When it issued rules to implement PURPA, FERC said that a QF could require the utility to purchase the QF’s output pursuant to a “legally enforceable obligation,” typically a long-term contract.

This federal program is wholly independent from state RPS programs that may involve the same or different types of renewable projects, may cover smaller or larger sized projects, and may have different pricing parameters. However, under the PURPA program, the states must follow the federal rules.

In the Texas case, Exelon Wind, which owned several wind projects, challenged a Texas Public Utility Commission regulation, issued in response to PURPA, that says that only QFs with “firm power” can require a utility to enter into a legally enforceable obligation. According to the Texas PUC, since wind is an intermittent resource, it is not “firm” and, therefore, under the PUC rule is not entitled to a legally enforceable obligation. After losing before the PUC, Exelon Wind asked FERC to enforce its PURPA rules against the PUC. Although FERC declined to take enforcement action against the PUC, it issued a declaratory order finding that FERC’s PURPA rules, which the state was required to implement, were not limited to “firm” power, Exelon Wind has the “right to choose to sell pursuant to a legally enforceable obligation, and, in turn, has the right to choose to have rates calculated at avoided costs calculated at the time that obligation is incurred,” and the PUC order was inconsistent with federal regulations implementing PURPA.

In a 2-1 decision, a US appeals court in Texas refused to give deference to FERC’s declaratory order interpreting its PURPA rules. It concluded that, under its own interpretation of the federal PURPA rules, FERC’s PURPA rules gave discretion to the PUC “to determine the specific parameters for when a wind farm can form a legally enforceable obligation.” The court went on to defer to the PUC’s interpretation of the PUC rules implementing PURPA.

It should be noted that this court holding applies only with respect to Texas rules implementing PURPA. Its impact may be limited even in Texas, since few long-term QF contracts have been signed with Texas utilities in recent years and wind projects have relied more on federal tax credits for support. In addition, the decision does not require any other state to modify its PURPA rules. However, it remains to be seen whether any other state may wish to revisit its rules based on the decision and, if so, whether the Federal Energy Regulatory Commission might decide to take a more active role in defending its PURPA rules in future court proceedings.

by Bob Shapiro, in Washington