“Corrosive.” “Seriously flawed.” On the “brink of market failure.”That’s what critics say about New England’s forward capacity market (FCM), whereby ISO New England conducts auctions to solicit offers from project developers to make electric capacity available three years into the future to meet anticipated regional demand.
The reason? Too many offers—way more than New England needs to meet its ICR, or installed capacity requirement. All that excess capacity has forced prices down to the market floor—to $2.95 per kilowatt-month in the third forward capacity auction (FCA-3), held last October for delivery in June 2012—with surplus capacity left over, apparently willing to offer at even lower prices, if auction rules had so permitted.
And no one today expects the surplus or the low prices will disappear any time soon.
Dr. Miles Bidwell, a consultant and critic of New England’s auction market who represents Boston Generating LLC in the FERC proceeding now pending on FCM reform, argues that excess supply “will hang over the FCAs for at least the next seven years and will continue to keep the FCA price at much less than the competitive market outcome.”
NRG and PSEG, also filing comments on the FCM reforms, suggest it might take 10 years to work off the surplus, as nearly 37,000 MW cleared FCA-3 at the floor price, representing a surplus over 5,000 MW, whereas the year-to-year increase in regional needs “is typically on the order of ±500MW or less, less than 10 percent of the current surplus.”
Even consultant James F. Wilson (Wilson Energy Economics, an affiliate of LECG) representing Connecticut’s state utility commission and testifying before FERC in support of FCM, concedes that “trends of slower load growth, and diverse capacity additions … and regulatory incentives … leads me to expect that excess capacity and the resulting low FCM prices should continue.”
Importantly, these twin regulatory problems—extreme excess capacity coupled with severely depressed auction prices—still appear largely in play, even following FERC’s recent decision of April 23, handed down just as this issue went to press.
In that decision FERC reviewed the ISO’s comprehensive package of FCM market reforms, proposed in late February. FERC accepted certain noncontroversial changes as proposed, but set a paper hearing to resolve the more difficult questions. (See, Docket ER10-787, April 23, 2010, 131 FERC ¶61,065.)
Among other things, FERC’s April 23 decision resolved the question of the price floor.
In February, the ISO had offered to help prop up prices by extend the life of the price floor past the first three auctions, as planned originally when FERC OK’d FCM in June 2006, in order to cover FCA 4 through 6, for the capacity delivery years from June 2013 through May 2016.
Now we learn from the April 23 order that FERC will cancel the price floor as an unnecessary intrusion on markets, but will suspend the move temporarily, thus allowing the floor to remain in effect anyway for FCA auction number 4, to be held in August of this year, for which buyers and sellers already have made extensive plans, so as not to cause untoward disruption in the short run.
FERC also now has OK’d the ISO’s proposal to reconcile the probabilistic engineering test employed for measuring the capacity needs for individual geographic zones (the local sourcing requirement, or LSR), with the deterministic engineering test used for measuring whether local resources are needed to satisfy reliability standards.
Previously, the two tests had been inconsistent, leading to situations in the first and third capacity auctions where the capacity requirements for a given local area were easily met, requiring no special locational zonal price premium to entice capacity into the local area, but where the ISO had found itself obliged to reject de-list bids filed on behalf of local resources, since removing the resources from the auction would impair local reliability.
That result had undermined the very reason that FERC had required New England to adopt a new capacity market in the first place—to reflect locational differences in resource costs, just as regional energy markets reflect geographic nodal differences in energy dispatch costs through locational marginal pricing.
The incompatibility was partly to blame also for the fact that with three capacity auctions having been conducted, the market had yet to see any zonal price separation. Each auction had cleared at a single price applicable over the entire region.
Thus we are left with two key issues that still haunt New England’s forward capacity market, directly linked to the twin evils of surplus capacity and depressed prices:
• CONE vs. Auction Price. First, should auction clearing prices track the value known as CONE, or cost of new entry, which represents a best guess at the price developers would likely demand to cover the long-term levelized average capital cost of their new power plant projects—projects assumed to be gas-fired turbines—or should the ISO take no special effort to ensure that CONE estimates and auction clearing prices remain closely linked, thus allowing prices to fall into a death spiral, if that is how the auction clears?
• Out-of-Market Offers. Second, when an owner of capacity resources secures a revenue stream outside the parameters of the ISO’s capacity market such that the owner need no longer depend upon auction proceeds to cover its fixed costs, and so becomes indifferent to the rise or fall of the auction clearing price, how should the ISO review FCM low-ball price offers from such “out-of-market” (OOM) resources, to ensure that such offers don’t distort the market outcome, either by depressing the clearing price, or by injecting excess uneconomic capacity into the auction?
Robert Stoddard, vice president and leader of the Energy and Environment Practice at CRA International (formerly Charles River Associates), argues that whatever is being tried now to answer these questions is clearly not enough:
“At least 1,400 MW of new capacity, and perhaps twice that figure “has been injected into the new England market ahead of demonstrated need with the express or tacit intention of driving down prices in the FCM.”
The most important of the new FCM market proposals—one that will pose questions to be decided in the upcoming paper hearing—involves changes to the ISO’s alternative price rule.
APR allows the ISO to boost the price artificially above the clearing level when certain “trigger” conditions are satisfied, to offset the assumed price-distorting effects of OOM offers. The APR was on the books for the first three FCAs, but was never triggered—a sore point with the generating sector, especially since NEPOOL stakeholders approved the ISO’s new FCM reform package entirely without generator support. No generator voted in favor of the reform package. The gen sector cites that fact in arguing that New England’s ISO governance structure is “skewed,” and remains convinced that the proposed FCM reforms won’t go nearly far enough.
Consider comments filed with FERC by the New England Power Generators Association (NEPGA), reacting to the FCM reforms:
“Here we have load contracting for capacity,” writes NEGPA, “when there already is surplus existing supply, and then offering that capacity in well below its actual cost (even at zero), for the express purpose of reducing the price paid for all other capacity suppliers.”
The ISO’s internal market monitor had issued warnings over on the OOM problem in a report last summer:
“Because the annual new capacity requirement is small relative to the size of existing generating capacity, buyers may have the ability and incentive to exploit the market’s price sensitivity by building or contracting for a large amount of new capacity bilaterally and then offering such capacity into the FCA at an uncompetitively low price. (See, Internal Market Monitoring Unit Review of the Forward Capacity Market Auction, FERC Docket ER09-1282, filed June 5, 2009.)
The New England generators entreat FERC to view OOM offers as the flip side of capacity withholding and seller market power, deserving of just as much attention from regulators:
“If … prices were being distorted upward by suppliers exercising market power and possibly manipulating the market, those concerns would never face the protracted delay we face in seeking badly needed modifications to the APR.
“We would never see the issue punted … to an open-ended and lengthy stakeholder process destined to fail.”
Back in 2006, when FERC OK’d the FCM settlement, regional stakeholders had picked out a figure of $7.50/kW-month as a starting benchmark for CONE, with the descending clock FCM auction opening at 2 x CONE, or $15. But they also designed FCM to be technology neutral. If auction prices diverged under pressure of new capacity entering the market and employing a cheaper or more efficient technology, the ISO would reset CONE for the next auction to reflect the lower cost of the new technology.
Yet FCM’s architects weren’t altogether prescient. What they failed to foresee was a massive wave of new offers from projects with a capital cost revenue stream coming from outside organized capacity market—projects sponsored by utilities, load-serving entities, local governments, and state regulators anchored by long-term bilateral purchased power contracts, often with 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, Connecticut regulators asked consulting firms such as London Economics to help it design RFPs to solicit capacity for Connecticut utilities using a master agreement for purchased power contracts drafted specifically to minimize liability for FCM auction payments.
The result was a structure that featured contracts for differences (CfDs) that would leave capacity sellers indifferent as to whether the contract sales prices would fall either above or below clearing prices in New England’s centralized capacity auction market. Either way, the RFP sellers would be made whole, as the DPUC explained:
“For the CfDs that settle against the ISO-NE markets, the contract will have a variable payment structure …
“If the annual contract price is above the actual market clearing price in the FCM … the Buyer will true up the Supplier … If the annual contract price is lower than actual market clearing prices, the supplier will make payments to the Buyer.” (See, Energy Independence Act Capacity Contracts, Conn. DPUC Docket No. 07-04-24, p. 30, Aug. 22, 2007, published at 2007 WL 24150067.)
Connecticut has defended the program as mandated by state legislation, and protected by the state action exemption to federal antitrust law. (See, Answer of Connecticut DPUC et al., FERC Docket ER10-787, filed March 30, 2010.) Generators, however, see it as state-sponsored price manipulation:
“It should be emphasized that the DPUC designed its RFP to artificially suppress FCM clearing prices …
“First, the Master Agreement requires bidding in a manner designed to lower the market clearing price. Second, the legally mandate bidding strategy is intended to lower clearing prices across the board by means of the ‘multiplier effect’ that this otherwise uneconomic bidding strategy would have on the market as a whole.” (See, Comments of The Boston Generating Cos., pp. 15-18, FERC Docket ER10-787, filed March 15, 2010.)
Yet at the same time the generators concede that such efforts by state regulators are well-motivated, often reflecting a greater public purpose, such as the reduction of risk through long-term contracting, the promotion of energy efficiency and conservation through greater demand response efforts, or reduction of carbon air emissions through via development of renewable energy.
NEPGA recognizes the dilemma for regulators:
“While intentional price suppression obviously is inappropriate, states should be free to pursue their chosen policy objectives through, for example, long-term contracts or retail programs. Designating a resource out-of-market does not imply bad intent; all [it] means is that the resource is being subsidized …
“And we expect to continue to see examples of apparently benign OOM supply. Massachusetts has just launched a $2 billion energy efficiency program and several large renewable projects may soon sign long-term contracts with load in New England.”
“Regardless whether a particular OOM resource is part of a scheme to distort prices downward or a benign effort to accomplish some other, legitimate goal, such as reducing carbon emissions, the distorting effect on FCM prices is the same.”
The independent consultant and RTO market expert Roy Shaker fears that if markets continue to welcome capacity from out-of-market resources, the result will be a two-tiered market where some new players are paid a higher price and existing suppliers are paid a lower price—but with all offering the same service.
“No one will seek to enter the market other than by such OOM agreements,” Shanker explains, as a supplier without such protection would fall prey to buyer market power. Eventually, he warns, all favored “new suppliers” will become disfavored “existing suppliers.”
But is that a problem for ratepayers?
According to NEGPA, “if this problem is not solved, load will have to support all new entry through bilateral contracts, thus taking full ownership risk, including the risk of making mistakes.”