Courts and FERC Consider Challenges to State Efforts to Determine Electric Capacity Resources and Prices

The federal courts and FERC are wrestling with complex issues arising from the “organized” capacity markets for electricity created in the “restructured” states — where local utilities sold off their power plants and now purchase electricity for their customers in wholesale markets under FERC jurisdiction.   Retail utilities are required to have enough “capacity” lined up from sellers to meet their needs on a peak usage day.   Before “restructuring” capacity needs were met by the utilities’ own plants, supplemented by bilateral contract purchases and short term purchases through voluntary power pools, at cost based prices.  As stated in a recent FERC staff paper:

“Under traditional utility regulation, resource adequacy is met by load-serving entities obtaining regulatory approval to hold a portfolio of resources, the costs of which (including a reasonable return on investment) are recovered from captive customers. In areas of the country that have restructured their electricity markets, many load-serving entities compete for retail customers with other suppliers, creating financial risk for long-term resource commitments, and in many cases have divested generation to new owners that compete for sales and thus have no guarantee of cost recovery.”  Centralized Capacity Market Design Elements, Commission Staff Report in Case AD13-7, Aug. 23, 2013, at 1.

With the “restructuring” of utilities and more emphasis on wholesale purchasing at market rates rather than self-production or purchases at cost based rates, power pools in the Northeast morphed into RTO and ISO utilities (PJM, NYISO, and NE-ISO).  In addition to operating the bulk power grids in their regions, the RTO/ISOs replaced their power pools with new spot markets for energy and capacity and ancillary services, where uniform clearing prices paid to all sellers are based on market-based bids of sellers rather than their costs.

After restructuring, local utilities necessarily had to buy far more capacity and energy.  The track record of the NYISO capacity markets is that they have added significantly to the cost of electricity without achieving much in the way of meeting future needs. See Cornell Professor Gives Low Marks to NYISO Electricity Markets. According to Cornell Professor Timothy Mount,

the [NYISO] LICAP market has been an expensive and an ineffective way to maintain generation adequacy. In 2005 and 2006, customers paid over $1 billion/year in the LICAP market in NYC and merchant investors were still reluctant to commit to specific in-service dates for new generating units that have already received licenses for construction. This amount of money is enough to finance over 12,000 MW of new peaking capacity at a capital cost of $80/kW/Year (from Table A1 in the Appendix), and this amount of additional capacity would more than double the installed generating capacity in NYC. At this point, it is likely that New York City or state agencies will need to be more proactive before it is too late and reliability is sacrificed

A 2007 New York City Bar Committee Report on Electricity Regulation in New York acknowledged the failure of the NYISO capacity markets to induce adequate supplies of power at a time when new power plants are generally considered to be necessary for reliability and reasonable prices, particularly in downstate areas:

the only truly merchant plant built in New York City since 1999 has been KeySpan-Ravenswood’s 250 megawatt (“MW”) project. Orion Power also invested approximately $25 million in restarting a retired unit at the Astoria Generating Station. Otherwise, all major new plants have been either built by the New York Power Authority (“NYPA”) or under long-term contract to the Consolidated Edison Company of New York, Inc. (“Con Edison”) or the Long Island Power Authority. Outside New York City, however, plants have been constructed on a merchant basis.

See City Bar Committee Issues Report on Electricity Regulation in New York. To that, one might add, the owner of the largest merchant power plant constructed outside of New York City went bankrupt, and other merchant power plants have been shut down by owners who deny having any obligation to serve. Over the past decade, the Power Authority of the State of New York became the de facto builder or financier of last resort due to the failed reliance on NYISO capacity markets and the private merchant power sector.

Despite large amounts – billions of dollars – paid for capacity in areas where power or transmission was scarce or constrained, however, the “market” did not respond to the price with new supply.  The main beneficiaries of the capacity market auctions are the incumbent generators and traders.  Also, the NYISO capacity markets have been susceptible to market gaming strategies, for example, sellers using financial derivatives to backstop a withholding strategy to drive prices to the ceiling for all sellers.  FERC did not object to that strategy and  federal antitrust cases were settled with no admission of wrongdoing and disgorgement of only 20 – 25% of profits.  See United States v. Morgan Stanley, 881 F.Supp.2d 563 (2012) and United States v. Keyspan, 763 F.Supp.2d 633 (2011).

As a consequence of dissatisfaction with the prices in capacity markets and the failure of the market price signal to stimulate new resources to meet the need, local utilities and states began to seek ways to arrange for capacity to be increased, through contracts with developers to bring new plants on line.  For example, Con Edison did this with the SCS  500MW Astoria plant completed in 2006, under an RFP process, with a contract to buy capacity for ten years.  Problems have arisen, however, with NYISO “Minimum Offer” rules setting a higher pricing floor for capacity from that plant than the contract price, with the result that high prices are being maintained despite the addition of new supply. NYISO then exempted two new New York City area plants from the rule, and FERC disallowed that, with the effect that consumers may have to pay twice for the same capacity, once under the contract and once under the NYISO rule.  Litigation is pending over that issue.  See Astoria Generating Co., L.P. and TC Ravenswood, L.L.C. v. New York Indep. Sys. Operator, Inc., FERC Docket No. EL11-50, at 3 (2011).  See also, Richard B. Miller, Neil H. Butterklee, and Margaret Comes, “Buyer-Side” Mitigation In Organized Capacity Markets: Time For A Change?, 33 Energy Law Journal 449 (2012), discussing the NYISO litigation at 463-464. It is unclear whether the Con Edison contract was filed under FPA Section 205.

Maryland and New Jersey took a different approach, requiring local utilities to enter into a financial derivative “contracts for differences” (“CFDs”) with power plant developers  The CFDs assured the developers a long term stream of revenue, by supplementing capacity market auction prices if they fall below the target price.

FERC established rules for minimum bids that set a floor price in the capacity markets, frustrating efforts of the states and retail utilities to acquire capacity at lower prices.  Power companies sued in federal court to halt the financial derivative contracts that were supporting the building of new power plants that were intended to meet demand, make supply less scarce and lower prices.  The federal courts ruled that the derivative contracts based on the FERC-jurisdictional spot market prices were unconstitutional under the Supremacy Clause under the federal preemption doctrine, based on a finding that FERC had occupied the field of interstate wholesale power pricing.  See PPL Energyplus v. Nazarian (finding MD derivative contract preempted) and PPL Energyplus v. Solomon (denying motion to dismiss preemption claim).

There should be no need for all capacity to be gotten via the capacity spot markets, or at the spot market price. Depending on state law, utilities should be able to self supply with their own power plants, or to buy wholesale power in bilateral contracts.  Also, many states acting out of environmental concerns, began to require set percentages of energy and capacity to be obtained from “green” or renewable resource portfolios.  The statutory scheme established by the Federal Power Act contemplates that wholesale power arrangements will be made by negotiated contracts, which must be filed in advance subject to review.  Once filed and in force, they can be the filed rate and not changed by, for example, fluctuations in the prices set by the short term capacity auction markets.

It should be noted that the court cases, now on appeal, do not involve traditional filed bilateral contracts to purchase power/capacity from new plants built to satisfy unmet needs. Rather, they were financial derivative contracts which assure revenue to power plant developers by guaranteeing to supplement whatever they get in the spot market up to a designated price point. So if the developer bids low, it could reduce the market clearing price, but the developer will be compensated outside the spot market by the derivative contract for differences, which tops up the price gotten in the capacity spot market. The courts found that those derivative contracts riding on the outcome of the capacity spot market auctions affected the wholesale spot market price which was a rate under FERC jurisdiction.

The buyer who needs to line up capacity to meet peak needs of its retail customers should be able to shop outside the “organized” capacity markets of the ISO/RTO utilities.   A traditional filed bilateral contract to purchase energy/capacity at a set price, or with a fuel cost adjustment clause for energy, would not be based on the capacity spot market price. It should not really be in the spot market at all, since the buyer has already purchased it outside the market.  Nothing in the Federal Power Act gives FERC the power, directly or indirectly, to dictate that all capacity be bought through one utility or at the price set by that utility.

Retail utilities should be able to limit its capacity purchases in the ISO/RTO utility markets to that which it cannot self-produce or has not purchased in a bilateral contract. When capacity is obtained bilaterally outside the spot market, it should mean that the price is determined by the bilateral contract, unaffected by the ISO/RTO market price.  Self-supply or bilateral purchases might affect the RTO/ISO  market prices, but it is harder for the marketeers to complain if there is a valid filed bilateral contract as anticipated by FPA § 205.  They would have a hard time pointing to any section of the Federal Power Act  that says sellers and buyers must obtain all capacity at spot market prices and cannot negotiate another reasonable price.

States and local utilities chafing at paying billions of dollars in capacity costs to incumbent generators without alleviating shortages or removing constraints should be able to enter into bilatereal capacity and energy purchase contracts at negotiated prices other than the prices in the “organized” markets.  Some of the problems that have arisen may be traceable to FERC’s re-pricing of capacity intended to be bought and sold under bilateral agreements at different prices established by the capacity market tariffs of the RTO/ISO utilities.  Part of the problem is that FERC told sellers with “Market Based Rates” not to file their contracts, even though the Federal Power Act requires filing. The Federal Power Act, 16 U.S.C. §§ 824 et seq., however, commands that “no change shall be made by any public utility in any such rate, charge, classification, or service, or in any rule, regulation, or contract relating thereto, except after sixty days’ notice to the Commission and to the public.  16 U.S.C. § 824d. (Emphasis added). If contracts are filed, they can bevcome part of the “filed rate”, and then “not even a court can authorize commerce in the [electric] commodity on other terms.”  Montana-Dakota Co. v. Northwestern Pub. Serv. Co., 341 U.S. 246, 251-252 (1951).  But when contracts are not filed, they can be revised by FERC, even after they have been performed.  See Joshua Z. Robach, FERC’s Jurisdiction Under Section 205 of the Federal Power Act.

Perhaps someday a bilateral electric capacity contract (not a financial derivative contract) will be filed and we will see a resolution of FERC’s power to re-price bilateral agreements based on its “organized” capacity market prices which are unfiled and functionally deregulated.  The filing of prices by a utility (MCI) with a regulator enamored of deregulation but lacking statutory authority to implement it it (the FCC) culminated in a seminal decision of the Supreme Court (MCI v AT&T) which curbed the agency effort to deregulate and paved the way for statutory reform in the Telecommunications Act of 1996.  In the process of that statutory reform which began to recognize a new competitive industry structure, consumers gained by obtaining Lifeline rates in all states, broadband for schools and libraries, protection of rural customers and other protections that the FCC either lacked the will or the power to adopt on its own.  The Supreme Court has noted, in a case involving the filed rate effect of energy contracts, that it has not ruled whether FERC’s “market-based rates” scheme is legal.  Morgan Stanley Capital Group Inc. v. Pub. Util. Dist. No. 1, 554 U.S. 527, 535 (2008).

Earlier this month, FERC  received a round of comments on issues involving the “organized” capacity markets in its Case AD13-7 and the efforts of retail utilities and states to obtain capacity outside those markets.  There is likely to be much more ink spilled, and more consumer money lost, before the capacity market issues are resolved by the courts.

Meanwhile, we note that New York received $10 million to support residential utility consumer advocacy on wholesale electric market issues, from a FERC fund created with a disgorgement by an alleged NYISO market manipulator.  The money is held by NYSERDA to be dispensed $1 million a year for ten years.  FERC approved this in October 2012.  Last year the state Legislature approved it in the 2013-14 budget beginning April 1, 2013, and the $10 million was disbursed by FERC to NYSERDA on April 30, 2013.  To date, however, the state program has not been implemented.

As a consequence, New York consumers are not represented in the FERC capacity market inquiry or in other FERC and court proceedings that involve billions of dollars of questionable capacity market charges.

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