It is naive to think that energy services can be obtained for free. But the recent withdrawal of Duquesne Light Co. from PJM, along with market-reform proposals presented by industrial consumers and public power utilities to address what they believe is an absence of just and reasonable prices in wholesale energy markets, are nothing more than attempts to obtain free electric services—especially generating capacity needed to ensure reliability.
Not all industrial consumers are dissatisfied with organized competitive markets. FERC has received numerous comments in support of the current market-based approach, including one submitted by the COMPETE coalition together with 81 other parties—which included industry experts, Nobel laureates and such large customers as Wal-Mart.
Nevertheless, to the degree policymakers begin accepting proposals from parties opposing competitive market constructs like PJM’s, wholesale electricity markets might turn down a perilous path of reduced reliability and higher costs. The end result would be a return to the old and onerous paradigm of vertically integrated utilities that these same customer groups so vigorously wished to escape in the early 1990s.
Last November, Duquesne filed with FERC an application requesting termination of its membership as a transmission owner and load-serving entity (LSE) in PJM. FERC conditionally approved the withdrawal on January 17, 2008. The request explicitly was predicated on Duquesne’s desire to avoid capacity charges under PJM’s new reliability pricing model (RPM).
Duquesne is located on the seam between the Midwest ISO (MISO) and PJM and, therefore, can transition to the MISO—whose capacity market is under development, and its future structure is unknown. MISO requires LSEs to satisfy capacity requirements through owned generation and bilateral arrangements—including short-term capacity purchases currently available at low prices.
In a different FERC proceeding focused on potential reforms to organized wholesale electric markets, some industrial groups called for radical changes to the structure of current wholesale markets. In some cases, consumer groups have presented proposals that attempt to micromanage both energy and capacity markets. While not necessarily intentional, the inevitable result of such proposals would be a return to full re-regulation of electricity markets. For example, under the sophistry of a “forward resource commitment auction process,” a group of industrial consumers proposed a cost-based mechanism in which generating units would be eligible for unit-specific revenue recovery over the long term—through a FERC tariff—and energy bids would be subject to must-offer requirements under the old-fashioned cost-plus approach.
Other market participants have presented more innovative market design alternatives. The American Forest & Paper Association (AF&PA), which embodies some of the largest consumers of electricity in the country, submitted an innovative—albeit fundamentally flawed—proposal called “financial performance obligations” (FPOs). Similar positions have been hotly contested during the development of virtually every RTO/ISO in which representatives of consumers and LSEs have rejected any sort of capacity payment or demanded that energy markets be capped in exchange for such payments.
The economic fallacy in these proposals stems from an underlying assumption that consumers will obtain lower rates if investors are forced to sell some power services at competitive rates while supplying other services for free.
Economist George Stigler once wrote that economic logic is encapsulated in the phrase, “There’s no such thing as a free lunch.” As the only person who won a Nobel Prize for analyzing causes and effects of public regulation, Stigler found as early as 1962 that state regulation had no important effect on electricity prices during the early twentieth century. Stigler’s observation seems to be borne out by recent events that suggest factors other than economic policy are prime movers when it comes to public utility regulation.
Duquesne’s decision to withdraw from PJM probably won’t lead to a slippery slope in which members increasingly withdraw from their RTOs. However, its departure does raise a more fundamental policy challenge for RTOs that plan to address long-term reliability through a market-based approach.
Just as suppliers can offer capacity in different markets, LSEs should have, in principle, the same right to shop for RTOs that best represent their ratepayers’ interests. However, the long-term nature of resource adequacy and capacity markets presents a set of more complex challenges.
For example, to exploit economies of scale, base-load plants tend to be large. In a transmission-constrained region, this creates a problem, because large plants may have a disproportionate impact on market-clearing prices and overall system reliability. They also require investors to commit more capital in a single facility with a long construction time. Capacity markets are meant to provide potential investors with a stable and predictable stream of revenues. Forward auctions go a step further and create a contractual agreement that allows investors to obtain financing for the development or renovation of generation capacity.
A forward commitment is necessary to secure demand-response programs and generation resources sufficient to maintain a reliable system in the future. So when LSEs opt out from a market construct in order to avoid capacity charges, they leave investors stranded. Suppliers are less likely to invest in projects for the long term if they feel the rules of the market will change or key customers will stay only if prices turn out to be sufficiently low.
Duquesne is leaving the world’s largest competitive wholesale market and one of the most reliable grids to join a market that is under development. The main advantage of doing this is that MISO is operating at a high reserve margin and thus capacity can be secured at bargain prices. However, Duquesne’s comparison of short-term capacity prices between PJM and MISO may turn out to be myopic and against ratepayers’ interests. Although politically tempting (because it might keep rates low for a while), Duquesne’s strategy postpones proper long-term resource planning and might expose ratepayers to volatile energy markets.
But even if Duquesne’s departure proves beneficial to ratepayers, there is still a free-rider problem that threatens the RTO’s resource-adequacy construct.
Reliability is a public good. LSEs should not be able to capture the benefits of increased RTO reliability and then opportunistically withdraw when there is excess local capacity. Reliability for one is reliability for all, and decisions made by individuals affect others. Left on their own, market participants won’t provide enough system reliability, because they can’t reap the full economic benefits of doing so and would rather free-ride on the investments made by their neighbors.
Markets for adequacy won’t deliver the expected services in the absence of a long-term commitment by LSEs—either through long-term capacity purchases or, at the very least, a commitment to stay in the RTO and buy capacity in the future at spot market prices.
To guarantee the sustainability of complex and ever-changing electric grids, RTOs engage in long-term regional planning and force LSEs to secure the capacity in support of their load—similar to the way governments force workers to contribute toward their retirement so their lack of savings doesn’t later turn into a social problem. Because of the public-good nature of system reliability, RTOs must impose obligations on LSEs to prevent behaviors that negatively affect the entire system.
But RTOs’ planning efforts will be futile if they must design rules intended to keep all parties happy all the time—i.e., so no one is ever tempted to leave to capture short-term profits in neighboring areas. Through iron-in-the-ground facilities, investors make long-term commitments to RTOs, even as they are able to sell power into different markets. LSEs, on the other hand, can opt for different market rules by withdrawing from regional systems. The result is an unpredictable market for investment.
A more subtle, but equally detrimental market outcome arises when, after reliability markets are designed, LSEs exercise buyer-side power (also known as monopsony power) to depress competitive prices. Although FERC is addressing this problem in an investigation into NYISO’s installed capacity (ICAP) market rules for the New York City zone, to date there has not been a fundamental analysis of buyer-side market power in reliability markets.
Buyer-side market power works like this: Typically, capacity markets have only a handful of buyers, mostly local LSEs. Thus if LSEs can manage to depress capacity prices, even at a high cost, they will capture a large share of the benefits. For example, by repowering an obsolete plant or building facilities where they are not needed (or justified by their own revenues), LSEs can lower the price they pay for all their capacity purchases. Just as dominant suppliers profitably can increase prices by withholding capacity, large buyers artificially can depress prices by overbuilding (or over-contracting).
An example clarifies this point. Suppose a hypothetical capacity market clears at $10 per kW-month, but the replacement cost of a peaking plant, after incorporating a fair return on investment, taxes, etc., is perceived by investors to be $20/kW-mo. A merchant supplier almost certainly would not undertake the project. However, a utility that has to purchase 1,000 MW of capacity in the market at $10/kW-mo might find it profitable to build a 100-MW facility, even though its construction cost is $20/kW-mo, if, by doing so it reduces capacity prices to $5/kW-mo. The $10/kW-mo losses for the 100-MW plant pale in comparison to the $5/kW-mo of savings for the remaining 900 MW the utility had to purchase in the market (see Figure 1).
The irony is that such an LSE actually might get unconditional support from policymakers because it appears to be making sacrifices to build new capacity, lower rates and, of course, create new jobs. One such proposal—explicitly aimed at reducing capacity charges—was passed by the Connecticut state legislature in July 2005. This proposal authorized and encouraged utilities that previously divested their generation assets to purchase and own new generation. However, capacity isn’t being built because of its own merits. As shown in the example above, the utility might have the incentive to build a plant that costs more than what it’s worth in the market, because it artificially lowers market clearing prices. In this situation, prospective investors will perceive market rules as unfair, and no investments will be made—apart from those of vertically integrated utilities.
The AF&PA proposal for financial performance obligations (FPOs) contains some innovative features that—if properly implemented—have the potential to contribute to the liquidity of energy markets.
FPOs would require suppliers that receive capacity payments to financially guarantee the delivery of energy at or below a specified strike price. The strike price would equal the variable cost of the peaking unit used as a benchmark for the capacity payments. The FPO basically has two components: 1) the capacity payment as seen in some organized RTOs; and 2) a mandatory contract to sell energy at or below a strike price. The free-lunch component of the FPO is that it does not incorporate any direct compensation for the energy contract and its associated risk. But this can be corrected by pricing such a contract in the capacity auction. Then, long-term energy contracts could be jointly negotiated with capacity commitments in an organized market with standardized products, rather than through bilateral contracts. Creating markets, however, is difficult. Ill-defined contracts create perverse incentives, because returns are not commensurate with the risks imposed on participants—e.g., because of apparent free lunches.
Rather than creating a mechanism that encourages long-term contracting, the proposed FPO would impose those contracts without also providing any direct compensation for the associated risk. Thus, the FPO will discourage generators from bidding their capacity into the market. The FPO also will encourage suppliers to delist their capacity resources, especially in constrained areas where new capacity is most needed. This perverse incentive is embedded in the obligation to sell energy at the strike price which, everything else being the same, represents a greater financial risk in high-LMP areas. Mandatory long-term contracts also might turn LSEs away from capacity markets, because the contracts force LSEs into long energy positions that are not welcomed by rating agencies and capital markets. In addition, the focus on end results from state prudence reviews can expose utilities to rate disallowances if subsequent price changes make the contracts unattractive.
Unless LSEs compensate generators for the financial obligations they incur, the FPO effectively will impose a price cap on LSEs equal to the generation cost of a peaking unit. Those price caps suppress legitimate price signals—specifically, the price signals that LMPs are meant to provide. To make matters worse, these price caps lead to asymmetric regulation. Like a “heads I win, tails you lose” proposition, high prices are capped at generation costs, but there is no downside protection.
In sum, long-term contracts attached to capacity payments might foster the development of wholesale markets. But if sellers and customers consider such contracts to be disadvantageous, they may instead turn to the spot energy market and avoid them altogether. This only will exacerbate reliability problems.
The fate of installed-capacity markets will define the long-term viability of competitive wholesale electricity markets in the United States. Capacity markets are instrumental in reducing the risks from volatile energy markets. New generation investments, spurred by capacity revenues, also will increase competition in energy markets. Furthermore, when prices are high, capacity markets have the potential to hedge against the inevitable regulatory and political pressures for energy market intervention. The result will be lower energy prices and improved reliability.
Despite some headlines, regional integration of competitive wholesale markets has been successful, especially in markets in the eastern United States. Regional integration is, however, a work in progress and may not be delivering benefits as fast as customers expected. Even so, returning to traditional utility regulation, either by leaving well-functioning RTOs or by imposing cost-of-service style rate obligations on suppliers, carries the risk of impeding a rational resolution of reliability problems. Even worse, the continuous threat that comes from ignoring long-term commitments and working the political process for transitory benefits deters new generation investors. The result will be higher electric prices and reduced reliability.
2. Notice of Proposed Rulemaking, “Wholesale Competition in Regions with Organized Electric Markets,” 122 FERC ¶ 61,167.
3. Consumers’ Supplemental Comments and Proposed Alternative Market Model, Docket Nos. RM07-19-000 and AD07-7-000, January 11, 2008.
4. Stigler, George J., Memoirs of an Unregulated Economist, University of Chicago Press, 2003.
5. Stigler, George J. and Friedland, Claire, “What Can Regulators Regulate? The Case of Electricity,” Journal of Law and Economics 5 (1962): 1–16.
6. For a broader discussion of the public good aspect of reliability, see Lesser, Jonathan A. and Israilevich, Guillermo, “The Capacity Market Enigma,” Public Utilities Fortnightly, December 2005: 38-42.
7. FERC Docket No. EL07-39-000.
8. See “An Act Concerning Energy Independence,” Conn. Public Act 05-01 (H.B. No. 7501), 2005.
9. For a discussion of the prudent investment standard in energy regulation, see Lesser, Jonathan A. and Giacchino, Leonardo R., “Cost Measurement,” in Fundamentals of Energy Regulation, ch. 5, Public Utilities Reports Inc., Vienna, Va., 2007.
10. The benefits of capacity markets are not just a theoretical construct. Early restructured markets in South America have seen suppliers bidding below their variable generation costs in order to capture capacity payments.