The latest dispute over PJM’s bidding rules has raised the level of uncertainty in organized electricity markets. Efforts at reform have created a market structure so jumbled that it can’t produce...
When Markets Fail
New England grapples with excess capacity and rock-bottom prices.
rate base funding support, and so not dependent for their survival on the FCM revenues, and thus largely indifferent to the sharp fall in clearing prices.
In theory, any OOM resource can submit a low-ball, price-taker offer in the ISO auction, depressing the clearing price at the same time, since any added revenue it earns in the FCM is pure gravy.
The generating sector sees this outcome as a market failure: an a example of dreaded two-tiered pricing, such as when an employer locks out union employees and then hires scabs willing to work at half-scale. Buyers, on the other hand, praise the wisdom of a market design that frees customer load from the tyranny of a regional market with a fixed demand curve set by top-down central planners who claim to know what new capacity ought to cost.
In a separate exhibit attached to his affidavit cited previously, Stoddard presents results of a study he conducted of ISO-NE case data submitted by 11 New England generating units in 2006 through 2009, to justify special compensation for energy provided under reliability must-run (RMR) contracts. These data, according to Stoddard, show fixed O&M costs ranging from $3.16 to $7.45/kW-month, for a capacity weighted average of $4.11/kW-month.
“A price floor much higher than $2.95/kW-month is easily justified,” he notes.
State regulators from Connecticut and Vermont reject Stoddard’s argument that higher prices are justified:
“If existing generators ‘require’ $3.16 to $7.45/kW-month to cover their fixed O&M costs, but do not de-list [exit the auction] before the price reaches the FCA floor at $2.95/kW-month, the commission [FERC] can and should infer that they do not actually ‘require’ a higher capacity payment at all and are perfectly willing to accept capacity obligations for a much lower price.” ( See, Answer of Conn. DPUC, Vt. PSB, Vt. Dept. of Pub. Serv., & NE Utils., p. 20, FERC Docket ER10-787, filed March 30, 2010 .)
As Connecticut commission had stressed earlier, in comments filed March 15, FERC “did not guarantee generators that they would be paid in perpetuity at rates equivalent to this hypothetical cost of new entry.”
These suggestions of intentional price manipulation through capacity offers from out-of-market resources stem directly from a series of decisions issued by the Connecticut Department of Public Utility Control during the years 2006 through 2008, as the state commission attempted to carry out portfolio mandates imposed on it by the state legislature.
In Public Act 05-01, known as the EIA (“An Act Concerning Energy Independence”), the legislature instructed Connecticut’s state utility regulators to minimize the impact on retail ratepayers of what it called “federally mandated congestion charges,” a term the statute defined as any cost approved by FERC as part of the New England standard market design, including locational marginal prices, RMR contracts, and even locational capacity price premiums under a regime like new England’s FCM. ( See, DPUC Investigation of Measures to Reduce Federally Mandated Congestion Charges, Conn. DPUC docket No. 05-07-14PH02, Second Interim Decision, Nov. 16, 2006, published at 253 PUR4th 377 .)
To carry out that mandate,