By Randy Elliott, APPA Regulatory Counsel
Since 2007, the regional transmission organization PJM Interconnection has held auctions to pay for capacity to meet the region’s yearly load and reserve requirements, a tariff construct PJM calls the “reliability pricing mechanism” (RPM). APPA has long questioned whether the RPM and similar mandatory capacity markets in parts of New York and in New England facilitate — or rather frustrate — market entry by new generators. APPA analyses in 2012 and 2014 strongly suggest that the key to financing and building a new power plant is a long-term wholesale power contract or other steady revenue stream, not RTO capacity auctions. “Money for Nothing in the Power Supply Business” is how APPA has described the RPM in a series of issue briefs issued since 2012.
That title now seems especially apt. During the peak of the polar vortex in the winter of 2014, 22% of PJM’s generation capacity was out of service. The ensuing scandal was not that this behavior violated PJM’s tariff, but that that it did not violate the tariff. In its recent 180-page order approving PJM’s “Capacity Performance” proposal, the Federal Energy Regulatory Commission observes that this gap in the tariff construct “can threaten the reliable operation of PJM’s system and force consumers to pay for capacity without receiving commensurate reliability benefits.”
FERC’s order maintains — with no real evidence — that RPM “has successfully provided an incentive for the construction of new generation to both meet load growth and replace retiring resources.” But the order also concludes that more is required of PJM: “[I]t is not enough simply to ensure that ‘capacity,’ whether in the form of existing or new resources, is procured to meet reserve targets; rather, that capacity must carry with it meaningful performance obligations, and corresponding incentives and penalties, to ensure that those resources actually deliver when needed.”
The Capacity Performance proposal was intended to provide the missing obligations, incentives and penalties. PJM modeled it after the “Pay for Performance” proposal by ISO New England approved last year.
FERC’s approval of the Capacity Performance proposal illustrates the staying power of a bad idea. FERC excuses the RPM’s failures and requires further sacrifices from consumers.
Thus, generators clearing PJM’s capacity auctions will face hefty penalties for not performing when needed; but consumers must pay generators a hefty premium for shouldering that additional risk and for the additional costs incurred to ensure their availability. So that consumers pay that premium, FERC has let PJM raise the offer price cap in the future capacity auctions and reduce its scrutiny of generator costs, with the goal of permitting substantially higher auction prices in what FERC concedes is a “structurally noncompetitive market.” (FERC does not linger on that finding or ask whether it should also re-examine RPM in light of the persistent market power of incumbent suppliers.)
And if that were not enough, just before they filed it, PJM’s Board of Managers tweaked the Capacity Performance proposal to award performing suppliers the penalty revenue PJM collects from non-performing suppliers — rather than crediting a portion of the penalty revenue against the capacity costs in consumers’ power bills. FERC approved this extra incentive for generators, taking the money directly from consumers’ pockets without any evidence this reallocation would improve grid reliability.
Indeed, FERC’s order makes no pretense of quantifying the expected costs and benefits of the Capacity Performance proposal, claiming that a cost-benefit analysis is not required.
FERC chairman Norman Bay dissented from the order, citing numerous analytic flaws and lamenting that “despite the potential multi-billion dollar burden consumers will be asked to bear, there is no analysis, however rudimentary, indicating whether the benefits are at least roughly commensurate with the costs.”
Bay has the better part of the argument. Indeed, just twenty days later, in Michigan v. EPA, the Supreme Court ruled that the Environmental Protection Agency acted unlawfully by ignoring costs and benefits when it determined that it was “appropriate and necessary” to regulate the emissions of hazardous air pollutants from power plants under the Clean Air Act. A cost-benefit calculus is even more central under the Federal Power Act, which requires that wholesale rates be “just and reasonable.” Yet FERC did not assess what benefits consumers would be obtaining, or what additional costs they would be paying, before approving the Capacity Performance construct.
The order gives consumers no way to escape this additional burden. This was not always so. The RPM was conceived as a supplement to the long-term resource planning and contracting undertaken by states and load-serving entities — i.e., PJM would procure capacity as needed after parties had made their traditional bilateral arrangements. The annual capacity auction under the RPM is still called the “base residual auction.” But today the term ‘residual’ is unintentionally ironic, as FERC and PJM have steadily sought to limit the ability of state regulators, public power, and cooperatives to obtain capacity in any other way.
Thus, the RPM formerly allowed states and load-serving entities to develop and pay for generation resources with the assurance that they would automatically clear the RPM auction and count toward meeting a share of PJM’s capacity requirements. Citing the potential for buyer-side market power—an economic theory with no basis in fact in PJM — FERC eliminated automatic clearing and approved a more stringent version of PJM’s “minimum offer price rule” to prevent alleged capacity price suppression by load-serving entities. The Capacity Performance construct retains this lamentable rule, which is nothing less than an administrative barrier to market entry. The new construct is more costly and risky but still mandatory.
State regulators have discovered that PJM’s capacity-procurement construct may pose an entry barrier even when a new resource clears the auction in accordance with the minimum offer price rule. Regulators in Maryland and New Jersey are now before the Supreme Court, fighting lawsuits by generators that have stopped both states’ efforts to facilitate new generation development (in New Jersey’s case, pursuant to a special statute). Both state commissions issued a request for proposals to build new generation and enter into a long-term “contract for differences” with the state’s electric distribution companies; such a contract would provide a level revenue stream while still requiring the generator to comply with PJM’s rules and clear the RPM auctions. The commissions awarded contracts, and the winning generation developers then bid — and cleared — the PJM auction for a future delivery year.
Lower federal courts nonetheless invalidated the Maryland and New Jersey actions, deeming them preempted by the Federal Power Act. That act, the courts held, gives FERC exclusive jurisdiction over wholesale capacity prices, and the RPM auction prices are the only capacity prices FERC has approved for the PJM region. State regulators could not approve a long-term contract for differences, because that would effectively set a different price and term for sales of capacity in PJM.
Call this the “roach motel” theory of the capacity market: a state can check in (by deregulating its retail utilities), but it cannot check out.
The Supreme Court has invited an amicus brief from the solicitor general on whether the court should review the Maryland and New Jersey decisions. There are good reasons to support further review.
The lower court decisions are flatly wrong. The Federal Power Act and FERC policy allow, and even encourage, long-term contacting for resources to promote price stability within wholesale markets. FERC approved the RPM with that understanding.
The lower court decisions threaten the ability of any state — and potentially public power utilities and cooperatives — to use requests for proposals and long-term contracts or asset ownership to secure wholesale power supplies and develop new generation resources (or even retain existing ones). Far from supporting “markets,” the lower court decisions allow PJM’s administrative rules for residual capacity procurement to interfere with normal market operations.
Moreover, federal courts should not be deciding, independently of FERC, which capacity prices and contracts are lawful or unlawful under the Federal Power Act. Under a 1951 Supreme Court opinion, such matters are entrusted to FERC in the first instance; courts get involved only when reviewing FERC’s orders. These two cases show why that rule makes eminent sense.
