Monday June 12 2006


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Federal task force finds flaws
in wholesale markets

Lots and lots of them

Bias grows favoring rate-base generation

Many wholesale power buyers have had trouble signing long-term contracts, a federal task force found in a draft report on the state of competition (RT, 6/6).
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Click here to register early and save!         The task force -- composed of FERC, DOE, the Justice Dept, Federal Trade Commission and Agriculture Dept's Rural Utility Service -- could not come up with conclusive data but found that most buyers in New York, the Midwest and the Southeast have bought power on less than one-year agreements (http://elibrary.ferc.gov/idmws/File_list.asp?document_id=4410239).
        Buyers think that generators in RTOs don't want to sign long-term deals because they can get higher prices in the spot market -- taking advantage when high-priced gas-fired generation sets the price.
        Market-clearing prices in RTOs set "by a subset of generators depending on demand and transmission congestion" raises competitive concerns, the feds argued.
        A lack of liquidity -- especially beyond three years -- may be hindering long-term pacts, the task force added.
        Hedging products for that length of risk just aren't available.
        Long-term pacts have been discouraged by grid congestion and the inability of customers to get long-term rights at known prices -- particularly in RTOs, the task fore discovered.
        That has hurt financing of new generation -- especially more expensive baseload plants -- the feds found.
        The team found that contracts are tough to sign outside of RTOs because buyers can't easily get transparent information about prices and ATC.
        Grid owners are in the dark too, the feds added, because they don't have centralized data on bilateral deals -- making it tough to deal with congestion.
        Contracts for new generation are prone to regulatory risk too, the task force reminded.
        Buyers, the feds said, have tried to void pacts signed during the California energy crisis.
        Contracts' integrity has been harmed too by IPPs' bankruptcies, the task force added.
        IPPs have sought to break pacts due to insolvency.
        That can make buyers think twice before signing future deals with IPPs.

        That risk could prompt state regulators to favor utility-built generation over merchant generation, the feds warned.


        Investors have favored utilities over IPPs recently, the task forced added, because of IPPs' credit challenges and reduced profitability.
        Higher volatility in organized power markets favors utility-built generation too, the feds observed.
        Volatility means uncertain revenue streams for IPPs while utilities can show investors a consistent cash flow from rate-base generation, the team wrote.
        Price mitigation in RTOs, the task force found, have hurt the chances for new merchant plants to recover investments.
        Price caps during scarcity create a "chicken-and-egg conundrum," the feds reported.
        Caps discourage investment because generators fear not being able to recoup costs.
        But the need for high scarcity prices wouldn't exist if more generation was built and supplies didn't dwindle, the task force discovered.
        Capacity payments could, in theory, support new generation investment because they assure builders and investors a certain level of return, suggested the feds.
        "Capacity credits might allow merchant plants to be sufficiently profitable to survive even in competition with the generation of formerly integrated local utilities that may have already recovered their fixed costs," the task force argued.
        But the experience with capacity payments is mixed, the feds found.
Two regions-- the Southeast and Midwest -- have seen big generation investments without capacity payments while Northeast RTOs with capacity credits "continue to have some difficulty attracting entry, especially in major metropolitan areas," the task force reported.

        "Unfortunately, there is no conclusive result from any of these approaches -- no one model appears to be the perfect solution to the problem of how to spur efficient investment with acceptable levels of price volatility," the task force observed.

        The Midwest's generation was built because of uncapped price spikes (remember the $7,500/mwh) in the late 1990s while the Southeast saw a rash of merchant generation because of its proximity to natural gas fields, the task force noted.
        The New York ISO, the feds learned, has been successful in getting generation built in congested areas.
        About 1,000 mw of new capacity is to be added this year in New York City, the task force noted.
        The New York ISO is better able than ISO New England to match locational needs with investment because the New York ISO has clearer price signals in energy and capacity markets.
        The New York ISO includes the costs of running generators in load pockets when calculating locational prices, the team explained.
        It sets too a more generous "reference price" for generators less than three years old to help them recover costs.
        Regulation is interfering with the efficient exit of old plants, the task force noted, citing reliability must-run deals in RTOs.
        Those are the worst kind of deals, the team wrote.
        They're outside of the market and don't permit competition from -- or send price signals to -- cheaper alternatives such as new generation or demand response.
        Graduated capacity payments that favor new entry of efficient plants may help get inefficient plants retired, suggested the feds.
        The task force doubted whether a pay-as-bid market would produce lower prices than the uniform clearing price used by RTOs now (RT, 3/31).
        Generators are paid what they bid into the market under pay-as-bid pricing.
        That's different from uniform clearing pricing where all generators get the same price -- the marginal clearing price of the last and thus most expensive generator that's dispatched.
        Pay-as-bid pricing should not theoretically lower market-clearing prices -- and may even raise prices -- because generators will be encouraged to bid based on their forecasts of clearing prices rather than on marginal costs.
        Pay-as-bid pricing can harm dispatch efficiency too, the feds noted.
        Uniform clearing prices will let low-cost generators get big profits when expensive units set the clearing price, the task force conceded.
        But inefficient units will get smaller returns than what they would get under cost pricing, it added.
        That encourages units to cut costs and prompts investors to build more efficient generation -- lowering prices down the road.
        The feds' draft report at first glance "appears to be a well-constructed, balanced look at competition that highlights the successes we've seen with restructuring as well as some areas where improvement is needed," EPSA CEO John Shelk said.
        EPSA "certainly" agrees with the task force's views on grid access that point to a need for reform, he added.
        Originally published in Restructuring Today on June 7, 2006

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