Capacity Markets and Energy-Only Alternative should spur Construction…Theoretically

Alan Kovski, Managing Editor, Power Markets Week

As demand gains on capacity, power markets are leaving no stone unturned when it comes to encouraging the construction of new generation assets.

IF THE PLANS FOR REVISED CAPACITY markets in organized power markets work as intended, they should—in anticipation of capacity payments three or four years down the road—kick off the planning of investment in new generation very soon.

At the same time, if the "energy-only" approach to a power market in Texas works as intended, that too should ignite construction plans, in the expectation of higher energy prices in 2009.

"If"—it is the big word that goes with capacity markets and their alternatives. The revenue streams in the PJM Interconnection and ISO New England (ISO-NE) have been inadequate to compensate companies for new construction, the result is a lagging of capacity behind demand growth while older plants are kept operating under costly reliability must-run (RMR) contracts. In the region of the Electric Reliability Council of Texas (ERCOT), the concern is more specifically with the need for construction of new peaking plants to meet demand in the not-too-distant future.

Because construction plans are developed about three years in advance of expected in-service dates, it could be that such plans will emerge in the fourth quarter of this year and the first half of next year—if the planned incentives work.

Anecdotally, there have been comments from companies saying that they will bid new generation into the PJM and ISO-NE capacity auctions. There have also been the announced tentative plans of NRG Energy and TXU Energy to build plants, mostly in Texas, PJM and New England, but it remains to be seen whether auctions can get started in 2007 or 2008 with commitments of new capacity for the 2010-2011 time frame.

The final details of the revised PJM Interconnection capacity market, called the reliability pricing model, remain the subject of confidential negotiations, but an administrative law judge at the Federal Energy Regulatory Commission has set a schedule to resolve the RPM discussions and file the results with FERC by September 27. For ISO NE, the die is already cast, barring revisions through rehearing at FERC.

At the same time, the Public Utility Commission of Texas is moving ahead with its plan to rely not on a capacity market but on an energy-only market for real-time transactions in the ERCOT region.

Each market is trying to solve the problem of new construction incentives in a different way, although there are numerous similarities between the PJM and ISO-NE capacity markets. Each market would assure companies of greater revenues, over the complaints of some people who either say it isn't needed, or who are disenchanted with the whole idea of competitive wholesale markets.

Moving a few steps behind those markets is the Midwest Independent Transmission System Operator (MISO), which is exploring the idea of an energy-only market while also looking into possible capacity market ideas.

"I think they're still in a lot of pretty intense negotiations," a power company executive said of MISO's stakeholders.

The existing capacity markets in PJM and ISO-NE do not work, according to almost everyone involved in the arguments over new markets. During 2005, New England added only 11 MW of new generation while its peak demand rose by 2,700 MW, as FERC Chairman Joseph Kelliher has pointed out.

In markets where price volatility has been dampened by regulations, capacity markets can, in theory, provide the additional revenue to allow for recovery of long-term average costs, including fixed costs, for new generation. The additional revenue can be estimated by looking at the record of revenues earned by a generator in the energy and ancillary services markets and subtracting those revenues from the levelized annualized costs of a generator. What's left is the money that a capacity market can provide to spark new construction.

A capacity market should not be expected to provide most of the money needed to spur construction of new generators, one industry analyst said. A capacity market is designed to be an extra element at a tipping point—the additional revenue stream that allows a company to decide to go ahead with a project that might otherwise be delayed.

New England has decided that the additional revenues will come through a descending-clock reverse auction, while PJM has chosen to construct an administered "demand curve." Either method can provide the money, but a power company executive noted that the reverse auction stops cold when it produces enough commitments to hit the reserve capacity target, say 15%, while a demand curve creates a downward-sloping pattern of additional payments, though less and less, for additional capacity. In other words, the demand curve recognizes that additional capacity has some value, the executive said. That extra capacity provides some extra reliability and puts a little extra downward pressure on energy prices, to the benefit of consumers.

PJM officials have said they would like to see companies arrange for most of their resource obligations through long-term bilateral contracts, rather than relying on the auctions. Such contracts are generally considered a good way to stabilize a market and finance new plants. The auction then would serve as the backstop, making sure that all market players meet their resource obligations.

And PJM will let load-serving entities opt out of the RPM system as long as they can assure the regional transmission organization that they are providing for their own resource obligations somehow. FERC created the opt-out provision as an act of deference to state officials, who in many cases are doubtful about market changes and often jealous of their jurisdiction over utilities, including the companies' power-purchasing practices.

Self-supply and bilateral contracts of all lengths, long or short, together account for roughly 70% of the transactions in PJM.

New England will use a transitional system during December 2006 through May 2010, before the first auction commitment year starts. Capacity payments will be made to generators during the transition; RMR contracts also will continue in effect, but to prevent double payments, there will be no transition payments for capacity already covered by RMR contracts.

The auctions are designed to have a locational factor determined by zones of constraint, but transmission projects may resolve that problem, according to a recent report.

"For example, with the completion of transmission projects undertaken by NSTAR and due online soon, it looks to be nearly a foregone conclusion that the Northeastern Mass/Boston (NEMA/Boston) zone will not be needed when the auctions first get underway," says the August 23 report from Stanford Group.