Doubts About State-Mandated Power Contracts
Two recent federal district court decisions, one in Maryland and one in New Jersey, found that state programs directing local utilities to sign long-term contracts with independent power producers were unconstitutional.
The decisions raise questions about the authority of states in general to direct utilities to purchase capacity and energy at wholesale under specific state mandates, including renewable portfolio standards.
These decisions were at the trial court level and are subject to appellate review. Both decisions were appealed to US courts of appeal in late November.
Both decisions involved constitutional challenges to state programs that tried to encourage the construction of new gas-fired capacity in the portion of the PJM region where generating capacity was considered insufficient by the state. The New Jersey program was initiated pursuant to a specific state statute directing action by the New Jersey regulatory agency, the Board of Public Utilities, or BPU. The Maryland program was initiated by the Maryland Public Service Commission itself, without a specific statutory directive.
Topping Up Revenue
In both cases, the state had conducted a competitive solicitation for the construction of new generating capacity. The winning bidders received their fixed bid price from the local utility under a long-term capacity-only contract using a “contract for differences” pricing scheme. Bidders were required to bid into and sell their capacity in the PJM market, and any revenues from that capacity sale would offset the fixed bid price. If the PJM capacity price was higher than the fixed price, then the bidder would refund the difference to the local utility. If the PJM capacity price was lower than the fixed contract price, then the utility would pay the bidder the difference. In each program, the bidder was free to sell the energy from the project (as opposed to the separate capacity) to third parties in the PJM market. The solicitation, and the contract-for-differences pricing scheme, only applied to capacity.
The state programs that obligated regulated utilities to sign the capacity contracts for differences were challenged on two constitutional grounds in both Maryland and New Jersey federal courts.
One claim was that the pricing that resulted constituted wholesale ratemaking by the state in violation of the supremacy clause of the US Constitution. The Federal Energy Regulatory Commission has been given exclusive jurisdiction over wholesale ratemaking under the Federal Power Act.
The other claim was that the state bidding requirements unfairly discriminated against out-of-state power producers in violation of the commerce clause of the US Constitution. The commerce clause gives the federal government the right to regulate interstate commerce. The courts have also interpreted this constitutional provision in the “negative,” holding that the US Constitution therefore does not allow states to interfere with interstate commerce.
Both the Maryland trial court, and two weeks later, the New Jersey trial court, found that the state requirements that utilities sign capacity contracts under the contract-for-differences pricing conflicted with FERC’s exclusive right to set wholesale power rates and thus violated the supremacy clause. However, both courts found that the commerce clause was not violated.
The finding of a supremacy clause violation for these state-mandated contracts is significant in light of similar state mandates for long-term energy resources that have been implemented in many states. For example, several years ago, Connecticut implemented solicitations resulting in contracts for differences in the New England power markets. Twenty nine states and the District of Columbia have adopted renewable portfolio standards that require competitive solicitations and require regulated utilities to sign long-term contracts for wholesale power purchases.
It is unclear whether the specific solicitations are sufficiently different in those cases to warrant a different result. For example, it is unclear how much the court relied on the contract-for-differences requirement that the bidder make sales into the PJM market as a basis for its holdings, which could distinguish the New Jersey and Maryland state mandates from other state solicitations. It should also be noted that the Maryland and New Jersey court decisions are not binding in other states and are themselves being challenged in the US courts of appeal.
New Jersey and Maryland had argued that they were not in fact setting a price for energy. The states argued that they were only establishing and promoting a legitimate state policy in favor of construction of new gas-fired generating facilities. The states claimed that the contracts for differences were not wholesale power contracts at all, but only a financial mechanism. Although the bidder would be making wholesale sales in the PJM market, there would be no actual sales of capacity or energy to the utility counterparty. Under the contract for differences, according to the states, the local utility only had a financial obligation to make a payment to the bidder if that market price was lower than the contract price. In addition, the states argued that the PJM price was not set by the state, but by the PJM auction process that was regulated and approved by FERC, and that the bidder had market-based rate authority under FERC regulation. But the courts viewed the contracts for differences as wholesale power contracts, and even if they were not, the courts said that the state directive established the ultimate price received by the bidder for wholesale capacity sales.
Although the Maryland and New Jersey decisions acknowledged that the Federal Power Act did not prevent a state from having a say over the siting and construction of generating facilities within its borders, both courts said that a state cannot secure development of a new power plant in a manner that would intrude on FERC’s jurisdiction by effectively setting wholesale prices. According to both courts, by approving the bid price in a contract for differences that would require the bidder to sell capacity in the PJM market and require the local utility to pay any shortfall between the PJM price received by the bidder and the bid price, the state was establishing the ultimate price received for wholesale capacity sales. Once the courts reached this conclusion, then it was clear that only FERC could do this under the Federal Power Act.
It is important to note that both court decisions relied heavily on the testimony at trial. Other independent power producers who either lost the bids or were barred from bidding due to the restrictive bidding requirements challenged the programs.
Both courts found persuasive the claims of a number of such independent power producers that the contracts for differences will undermine their ability to use the capacity auction price signal to make business decisions in the PJM market. Both decisions ignored the arguments by the proponents of the state mandates that other states have conducted similar capacity programs that required sales into the power market in a contract for differences (like Connecticut) and have otherwise required solicitations for long-term energy purchases at wholesale. In reaching the conclusion that each of the state programs resulted in an unlawful state government-imposed price, the courts seemed to ignore the arguments about actions of other states as well as FERC’s own statements about similar state-mandated programs, thus essentially ignoring the larger implications of their decisions.
FERC did not file a brief in either court proceeding. None of the litigants appears to have thought to ask FERC for its views on the issue, nor did the courts seek any guidance from FERC on their own. The courts may have benefited from the view of the agency charged with administering the Federal Power Act, the statute that opponents of the New Jersey and Maryland programs argued preempted the state actions.
Over the years, FERC has been careful to distinguish between a state’s action that directly establishes a wholesale rate and an action either to hold a solicitation or direct a regulated utility to hold a solicitation that leads to a wholesale rate under a long-term contract. For example, FERC has been aware for many years that that many states have required regulated utilities under state renewable portfolio standard or RPS legislation to purchase renewable energy. Under many state RPS programs, utilities, through solicitations, bilateral contracts or tariffs, are required to sign long-term contracts with generating companies for the purchase of renewable electricity at wholesale.
For projects that are small enough to be eligible to be qualifying small power production facilities under the Public Utility Regulatory Policies Act or PURPA, the PURPA rules expressly provide that the state can set the wholesale power price, also known as the utility’s avoided cost. But for projects that are too large to be qualifying facilities or for programs that are not based on PURPA rules, or in regions like California, New York, New England and the areas served by the PJM and MISO regional transmission organizations, where FERC has allowed utilities to eliminate their purchase obligation under PURPA with QFs that are larger than 20 megawatts in size, the state does not have the authority directly to establish the wholesale rate. Nonetheless, FERC has never indicated that a state’s RPS program that includes a directive to utilities to acquire wholesale renewable energy under long-term contracts to be a violation of FERC’s exclusive jurisdiction under the Federal Power Act.
FERC appears to distinguish between a state’s action that actually sets a specific rate that a generator must charge and a state action that directs a competitive solicitation for specific types of preferred generating resources where generators set their own bid prices. This seemed to be the line drawn by FERC when FERC was asked three years ago to review California’s feed-in tariff that was imposed by state statute. In that case, the state legislature directed the California Public Utilities Commission to establish prices for small cogeneration facilities, called combined heat and power or CHP facilities, that might or might not qualify as qualifying facilities under PURPA. After a challenge by the regulated utilities in California, FERC found that, “to the extent a CHP generator is not a QF, the [CPUC’s decisions under the state statute] are not preempted by the [Federal Power Act] only to the extent that the [California Public Utilities Commission] is ordering the utilities to purchase capacity and energy from certain resources, but are preempted to the extent that the CPUC is setting wholesale rates for such transactions.”
Thus, it appears that FERC’s concern was that the CPUC was directing the generator to charge a specific rate that a purchasing utility must use in a long-term contract. At the time of the FERC’s decision, in 2010, FERC was well aware of California’s RPS law and wholesale contracts that resulted from CPUC-ordered solicitations under the state RPS law. In those solicitations, as with the Maryland and New Jersey programs, the CPUC did not directly set the rate. Rather the CPUC reviewed the rates resulting from the solicitation that the utilities conducted pursuant to a state mandate, and it approved or disapproved the pass through to the utility’s customers of the rates that resulted from the solicitations. The Maryland and New Jersey district court decisions failed fully to grasp the distinction between direct establishment of wholesale rates and “ordering the utilities to purchase capacity and energy from certain resources.”
It is also noteworthy that, in a series of FERC orders addressing the impact of state-mandated contracts for new generating facilities on PJM capacity markets, FERC did not at any time indicate that state mandates would violate the Federal Power Act. In fact, FERC had originally approved a proposal by PJM to exempt state-mandated resources from its minimum-offer-price rule.
Under the minimum-offer-price rule, in order for a new power plant to bid into a PJM capacity futures market, that owner had to bid at least a specified minimum price in order to avoid distorting the market price for capacity. FERC had approved certain exceptions to this requirement for certain power plants, including state-mandated capacity. But PJM later changed its mind and asked FERC to take away the exception for state-mandated gas-fired power plants, and FERC agreed. That decision is now on appeal.
However, the FERC decisions regarding the PJM capacity market strongly suggest that FERC viewed its jurisdiction to review how state-mandated resources can be offered in the PJM market as sufficient to maintain its exclusive jurisdiction over pricing and sales in the wholesale markets. For example, FERC said in the last order approving the requirement that state-mandated gas-fired power plants be subject to the minimum-offer-price rule: “We believe that the [minimum-offer-price rule] that we accept, subject to modification in this proceeding, including the unit-specific review process proposed in PJM’s compliance filing, serves to reconcile the tension that has arisen between the policies enacted by states and localities that seek to construct specific resources, and our statutory obligation to ensure the justness and reasonableness of the price determined in [PJM’s capacity pricing model for selecting capacity].” FERC went on to state that its order would ensure “that the wholesale capacity market prices remain at just and reasonable levels.”
Moreover, FERC in that PJM order had no trouble affirming the PJM’s exemption for a different category of power plants, renewable wind and solar projects, from the minimum-offer-price requirement, regardless of whether they are QF or non-QF projects or are or are not encouraged under state-mandated solicitations and long-term contracts. This also suggests that FERC believes that its control over PJM’s rates and procedures is sufficient to maintain its exclusive federal jurisdiction over PJM wholesale rates without otherwise disturbing the states’ efforts to promote preferred generating resources.
It is not possible to predict the outcome of the federal appeals of these Maryland and New Jersey federal district court decisions. The issues may well turn on the appellate courts’ assessments of the distinction between a price that the wholesale generator ultimately receives under a state-mandated contract for differences and the price that the generator receives from the PJM market and whether this is a distinction that makes a difference under the supremacy clause.
It is also not possible to predict the spillover effect of these decisions in the event that the district court decisions are affirmed on appeal. However, the mere existence of these decisions casts a shadow on existing state programs and similar programs that states might seek to introduce in the future.