Remember the story of Procrustes from Greek mythology? He had an iron bed on which he invited passers by to spend the night. If his guest was shorter than the bed, he stretched them by hammering or racking the body to fit. If the guest was longer than the bed, he cut off the legs to make the body fit the bed’s length. In either event the guest died. Ultimately Procrustes was slain by his own method to end his reign of terror.
For too long now, consumer-owned electric utilities in the East have been forced to lie in the Procrustean bed of mandatory capacity markets operated by the Eastern regional transmission organizations — PJM, ISO New England, and the New York ISO. These markets are not working — the impact is evident in higher than necessary consumer prices and a damper on new generation required to meet changing needs.
RTO-administered capacity constructs have not been able to attain a mature, or even stable, state. The basic construct of mandatory capacity markets is flawed — these are not even “markets” in any meaningful sense of the word. They are a form of centralized procurement based on a heavily mitigated pricing structure, and we should not fool ourselves into thinking they are anything else.
The American Public Power Association has had doubts about capacity markets from their inception, primarily because we thought consumers would end up paying too much for capacity. Eight years later, we think that consumers have felt the adverse impacts. We also know that these capacity constructs are not incenting much new generation.
The electric utility industry is capital intensive. New wholesale electric generation capacity of almost every sort requires some type of cost recovery over a period of years to support financing and construction. Even demand response (encouraging customers to use less electricity to reduce peak demand) and energy efficiency measures require some level of capital investment and cost recovery. Yet the current RTO-administered capacity constructs are shorter-term in nature — and are subject to the economics existing at each auction interval, such as low natural gas prices and locational boundaries, which create substantial price volatility. Capacity constructs are not well suited to support longer-term investments. And given coming changes in the regulations applicable to fossil-fueled power plants, new investments are definitely needed.
Our industry has taken what I call the biblical approach to generation planning (see Genesis 41:26-27). We’ve been in the seven fat years, where we have lived off of generation investments built under the prior regulated model. Now we’re going into the seven lean years, where we’re going to have to make some hard choices. We’re now playing for keeps. We have to change out old resources. We have to pick new resources. We have to deal with the unhappy operational characteristics of some of those resources, and we need maximum flexibility to do that. We’re going to need to make long‑term investments and when we do, we should not be penalized by arbitrary capacity market rules.
The “classic” way to finance capital intensive investments is through long-term bilateral contracts (or self builds) that support financing by providing assured cost recovery. But such contracts and arrangements have now been labeled “out-of-market subsidies” and have become grounds for “mitigating” the bids associated with such resources under applicable Minimum Offer Price Rules. Such bid mitigation exposes the bidder to potential double cost exposure, making it much more difficult to finance such resources in the first place.
This issue is now receiving increased attention, from not only the electric utility industry and regulators, but also members of Congress and the media. A recent article in the Baltimore Sun describes Maryland’s difficulties in obtaining new generation within the capacity market framework and the adverse impacts on consumers. Questions have been raised about the behavior of generators in recent PJM and ISO New England capacity auctions.
In PJM’s most recent auction, three of Exelon’s plants, equal to more than 4,000 megawatts of capacity, did not “clear” the auction after having apparently submitted offers at the highest allowable amount. Prices in the unconstrained region doubled, likely producing financial benefits for Exelon’s remaining plants.
New England’s latest auction saw a tripling of the capacity costs, partly due to the retirement of the Brayton Point coal plant. The greater revenues earned by other plants under the same ownership has led to calls for an investigation by the Federal Energy Regulatory Commission. On June 27, FERC sent a “deficiency letter” to ISO New England regarding the results of the capacity auction, requesting additional information on the conduct of the auction, including the retirements and withdrawals of capacity.
FERC still has open dockets on the structure of capacity markets of the Eastern RTOs and on the operation of these markets during last winter’s Polar Vortex. A significant portion of the generation receiving capacity payments was not available during the Polar Vortex, partly due to limited access to natural gas and partly due to mechanical difficulties. Meanwhile, in PJM, FERC has issued orders in six different dockets in the first half of this year alone making various tweaks to specific capacity market rules.
The newly created capacity zone in the New York’s Lower Hudson Valley, and the resulting price increases, has drawn the ire of New York’s Senators and Representatives. A Wall Street Journal editorial from July 14 asserts, “the capacity zone merely creates a short-term windfall for incumbent utilities.” And last week, Representatives Sean Patrick Maloney (D-NY) and Chris Gibson (R-NY) introduced an amendment to the House Energy and Water Appropriations bill to prevent FERC from using funds to implement the new capacity zone in New York. In addition, language in the bill itself states “when the Federal Energy Regulatory Commission considers a request for approval of a new capacity zone, the Committee expects the views of local and state officials, regulators, and business leaders to be taken into account during the process. Further, the Committee also expects that the process will include considerations such as costs to ratepayers in addition to electrical reliability and availability.” And if the editorial in the July 16 issue of the Wall Street Journal is to be believed, the New York capacity zone issue even figured into Tuesday’s confirmation of Norman Bay and Cheryl LaFleur to seats on the FERC.
APPA has two primary recommendations for changing RTO-administered centralized capacity constructs going forward. First, FERC should restore the ability of consumer-owned utilities in the three Eastern RTOs to self-supply their own loads with their own resources if they wish to do so.
Second, the RTO-administered capacity markets should be made voluntary, not mandatory. In this scenario, the markets could be one way to obtain capacity (especially on the margin, or close to the resource year in question). But capacity could also be procured bilaterally, in a real marketplace where willing buyers and willing sellers negotiate contractual arrangements tailored to meet their individual projects and needs, including term, fuel type and flexibility, location on the transmission grid, and financial provisions.
As a recent study by the Electric Markets Research Foundation points out, “The restructured markets are still trying to prove the workability of their model for assuring resource adequacy. By contrast, capacity reserves have been successfully maintained in almost all regions that have not restructured and that continue to rely on franchised electric utilities that take direct responsibility for resource adequacy under an obligation to serve.”
Public power systems are committed to providing electric power at reasonable cost with reliable service and good environmental stewardship. Not only do public power (as well as cooperative) load-serving entities in all three Eastern RTOs continue to provide service under the “traditional” model, they do so on a not-for-profit basis, because they are owned by the consumers they serve. Public power utilities are willing and able to make substantial long-term generation infrastructure investments to support new resources. It’s (past) time to release us from the Procrustean bed of mandatory capacity markets. Our consumer-owners deserve better.