Turncoat Turbines

Merchant plants snub the market, using native load to create their own private rate base.

You've read those stories about distressed assets-how the collapse of energy prices has sent firms scurrying to sell off plant to raise cash, buy down debt, and shore up the balance sheet. But that's just window-dressing. It tells you nothing about how to make money in a $40 power market with a high-cost gas turbine peaker bought during the height of the California power crisis, when prices were $300, $400, $800/megawatt-hour (MWh).

Until now, that is. Lately, some clever folks have found ways to divorce their overbuilt and overpriced gas turbines from the wiles and whims of commodity prices, and instead to remarry their assets to the girl next door-to the same captive native load that they disdained only a few short years ago.

The result is a guaranteed stream of payments, allowing the plant owner to recover fixed costs at no risk. The generator can then afford to bid and sell into any regional spot market, no matter how low the price, or simply to operate as a plant dedicated to native load.

Doesn't that distort markets? You bet. But it's already happening, with aid and comfort from the regulators, and even with help from a regional independent system operator (ISO)-the one player that you would think would want to preserve the integrity of a standard market design (SMD) with locational marginal pricing (LMP).

In February, the Federal Energy Regulatory Commission (FERC) allowed Cinergy's merchant generation subsidiaries CinCap Madison and CinCap VII to sell the unprofitable Madison (576 megawatt [MW]) and Henry County (136 MW) plants in Ohio and Indiana to PSI Energy Inc. for a proposed book-value price above $630/kilowatt (kW). The deal would take market-contestable generation capacity and put it under control of a Cinergy utility subsidiary operating in a regulated state, with a native load obligation. (See 102 FERC 61,128.)

According to the Electric Power Supply Association (EPSA), Arizona Public Service Co. recently asked the state utility commission (PUC) to help it meet native load obligations by approving a $500 million load guarantee to its merchant generation affiliate. And now come two more deals pending approval at FERC.

First, Ameren's merchant generation subsidiary, AEG, proposes to sell two gas turbine plants in Illinois (Pickneyville - 216 MW; Kinmundy - 232 MW) to Union Electric, its Missouri utility subsidiary, to help UE meet a requirement imposed by Missouri regulators to boost the utility's reserve margin in that state.

Second, NRG has asked the New England ISO to approve cost-of-service contracts for its Devon, Montville, Middletown, and Norwalk Harbor merchant plants, totaling 1,728 MW and located in the ISO's Southwest Connecticut congestion zone. The request falls under a recognized ISO program to sign reliability-must-run (RMR) contracts to aid out-of-merit units that wield market power because they are essential for local grid support. The plan would give NRG a guaranteed payment of $178 million, representing a capacity payment of $8.11/kW-month, or $97 per year, compared with a total balance sheet plant value of $257/kW. It would essentially guarantee recovery to NRG of all fixed costs, including back-payment of outages for ordinary maintenance that NRG said it had deferred over the past year or so because it could not afford the cost.

As you might expect, the power producers that still have faith in markets are up in arms.

Describing the Ameren deal, EPSA Policy Vice President Julie Simon says clearly: "The transfer would allow Ameren's … independent merchant generation facilities to be subsumed into a regulated entity and thereby shielded from market forces by virtue of their presumed future inclusion in the affiliated utility's rate base."

In Connecticut, the consumer counsel warns of the possibility ("hardly remote or fanciful," he says) that the state's entire wholesale energy market could soon consist entirely of generation plants subsidized by RMR contracts: "It may be that some units … merit RMR status … but the company's entire fleet?"

And lawyer Stephen Teichler, a veteran of ISO/SMD wars in the Midwest and New England, says NRG's ploy would reverse our ordinary notions of New England Market Rule 1, designed to mitigate market power:

"The applicants [NRG] would stand that purpose on its head: If a generator has market power, it is entitled to a price floor while retaining the right to collect higher market prices."

This Trend Is Especially Troubling Because Regulators-Federal And State-Seem So Willing To Comply.

In the Midwest, Richard Voytas, Ameren's manager of corporate analysis, said his company was only looking for the least-cost way of satisfying the demand of Missouri regulators to bolster the generation infrastructure available to Missouri's electric utility ratepayers. Forget, for the moment, that you could characterize the Ameren deal as a regulated utility using subsidized ratepayer money to bail out a corporate affiliate that invested too heavily in speculative assets, when instead the utility could have just signed a limited-term purchased power contract.

Voytas says the Missouri commission staff "expressed a concern with power purchases and showed a preference toward AmerenUE owning hard assets." But Voytas adds that Ameren issued a request for proposals and discovered that its transfer prices for Pinkneyville ($511/kW) and Kinmundy ($415/kW) fell within the same range of other recent, nearby plant transfers. But his data included the questionable Cinergy-PSI Henry plant deal, at $637/kW. Without that figure, the Ameren price would have compared unfavorably to prices like $353/kW (for the Neenan plant sold by Mirant to Alliant), or $465/kW (for the DePere plant sold by Calpine to Wisconsin Pub. Service).

EPSA counters that if FERC were to treat these unit sales as long-term purchased power contracts, the prices would fail the strict just-and-reasonable test traditionally applied to transactions between affiliates.

What's More, These Deals Are Bad For Markets.

NRG justified its cost-recovery contract in New England by showing that historical prices would not allow it to cover costs, but intervenors in that case complain that we should wait for new price data. After all, it's been just six weeks since ISO New England launched its SMD on March 1, complete with locational marginal pricing, which changes everything.

In a report to clients issued March 19, Lehman Brothers noted the ISO's March 1 shift to a PJM-style market, with LMP:

"In a nutshell, this transforms the New England wholesale market. … The new rules provide better price signals and eliminate subsidies."

Also, NRG's calculation of its own fixed costs includes a return on equity of 14 percent (much higher than regulated Connecticut utilities), plus an outrageous depreciation rate (remaining life of 6.6 years), with an allowance for net negative salvage, which implies that brownfields have no value.

"This is clearly wrong," say Connecticut state regulators, who oppose the NRG deal. Connecticut is now considering a proposal by Northeast Utilities to build a 345-kilovolt transmission line that would relieve congestion and make this kind of subsidy unnecessary. .

National Grid argues that transmission upgrades offer a better answer than these RMR subsidies: "Their existence can serve to entrench the very transmission constraints giving rise to the need for the locational requirements in the first place."

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