Editor’s note: The following is the final article in a three-part series that examined the restructuring of the electricity industry in the United States. The first article (EL&P July/August 2005) focused on the drivers behind restructuring and its current state; the second article (EL&P September/October 2005) looked at jurisdictional issues that often result in the divergence of state and federal regulatory frameworks.
The vision of a competitive electric power sector depends upon market-determined prices as its fundamental driving force. In principle, like any markets, restructured electricity markets can be poor performers according to criteria of fairness, competitiveness and political feasibility.
The first two criteria, fairness and competitiveness, are amenable to policy remedies that do not throw the baby of market forces out with the bath water. But our experience to date should leave us wondering whether the vision of the restructured electric power sector is a sustainable political equilibrium.
FERC has a legislative mandate to ensure that wholesale market prices are “just and reasonable.” Under restructuring, this has appropriately led FERC and other regulators to tie the concept of “just and reasonable,” at least in part, to whether markets are performing competitively. The more challenging question for regulators is whether “just and reasonable” in a restructured world should go beyond criteria for limiting the exercise of market power. The concomitant question for policy is whether political realities are such that regulators can avoid being pushed beyond this point even if the overall public’s interest lies in not doing so.
regulatory muddles: when are prices too high?
Regulatory intervention to set prices in otherwise competitively performing restructured power markets is anathema to the positive motivating vision of restructuring and, ultimately, the public’s overall interest in an efficient and fair electric power sector. Yet, both federal and state regulators have imposed various forms of price controls on their restructured electricity markets. For example, California coupled restructuring of its state-regulated utilities with arguably a politically necessary retail rate freeze. When other causal factors drove wholesale prices past the point where capped retail prices could cover wholesale costs, the consequences came right out of an economics textbook: price caps yielded shortages and non-market, political rationing.
Relying on the market to provide generation and transmission capacity investment requires efficient price signals and investment incentives. This means showing buyers and sellers accurate signals regarding resource scarcity, and providing willing buyers and sellers with confidence that regulatory and legal authorities will uphold the terms of their transactions. Certain FERC policies, however, are adding to uncertainty and signal distortion. While there has been much investment in generation, for the most part this investment was undertaken in response to expectations that future prices would be allowed to reflect scarcity. Now there is substantial evidence that markets will not be allowed to clear at levels reflecting scarcity, and it is rational for investors to incorporate this evidence into their risk assessments and future planning.
price regulation in ISO markets
FERC typically uses standard market concentration measures to assess whether an Independent System Operator (ISO) market is likely to operate competitively. Nevertheless, FERC has imposed price caps and bid “mitigation” measures on all of the ISO markets it has approved.
Pursuant to bid mitigation protocols, individual generating unit bids are monitored and “mitigated” when they exceed by a specified amount (typically $25 per 100/MWh) a reference measure based on that unit’s prior bidding history. This approach is notionally based on the theory (albeit economically incorrect) that price bids in well-functioning markets will reflect that unit’s short-run marginal costs to produce electricity. Particularly with production facilities (like much of the nation’s electric generating capacity) that operate most efficiently at full capacity, well-functioning competitive markets yield prices that reflect what is needed to cover the short run marginal costs of attracting the highest cost marginal units of supply into operation, thereby bringing total supply up to the level where supply and demand are in balance. By tying allowed pricing to periods of low bids and prices, bid mitigation targets periods of especially scarce supply (relative to demand) for distorting the market’s ability to perform its function of pricing to limit demand and encourage supply.
ISOs use other mechanisms to prevent prices from being “too high.” For example, ISOs at times render some generating units ineligible to set the market-clearing price by essentially removing the unit from the supply curve that is guiding the determination of market-clearing prices hour-by-hour. In other instances, there are non-transparent adjustments to dispatch that affect market-clearing prices. For example, ISOs employ operating procedures that can result in a high-cost generating unit becoming unavailable to set the market-clearing price, as when a high-cost unit is dispatched by the ISO out of bid-based merit order for system reliability purposes.
ISO policies such as these can lead to perverse outcomes. Two constrained areas in the ISO-New England region, Boston and southwest Connecticut, currently operate at reduced reserve margins during many hours of the year. In recent years, new investment has been undertaken in these regions, with new and re-powered stations built by multiple parties. These units have entered service only to be claimed for purposes of system reliability and face depressed prices for both the energy and capacity they provide during the many hours when imports into their respective load pockets are limited and market-clearing prices are high. The impact of these depressed revenue streams caused the plants’ owners to make requests to ISO New England to deactivate their generating units given inadequate cost recovery; and, in at least one case, the owner elected to turn its assets over to its lenders due to its inability to service the debt associated with its plants. Such outcomes imply chilling effects on investment and supply.
ISOs recognize that the markets as they stand will limit the ability of price signals to provide undistorted incentives for new resource construction. The ISOs have tried to address this concern, most commonly through the introduction of capacity markets that specify a reliability level and then require load-serving entities to purchase capacity credits in proportion to the load they serve. A well-functioning capacity market would signal the value of capacity to investors and would attract efficient levels of investment-if the capacity market were allowed to clear at a level reflecting scarcity value. However, FERC has approved price caps in capacity markets, calling into question how well they will be allowed to function going forward.
price regulation in bilateral markets
To prevent the exercise of market power in bilateral transactions entered into outside of ISO markets, the FERC grants market-based ratemaking (MBR) authority only if applicants demonstrate that they are unable to exercise market power. Even after MBR is granted to a seller, however, the seller’s prices may be subject to ex post evaluation to determine whether the prices are “just and reasonable.” FERC’s MBR authority has not provided market participants with assurance that a freely negotiated price will be final.
FERC review of the justness and reasonableness of market-based prices is guided in large part by the federal court decision in Farmers Union. The Farmers Union court held that market-based pricing must fall into a “zone of reasonableness” and that non-cost factors can be considered when setting rates, but that a reasoned explanation must be offered to support non-cost factors. FERC articulates in several market-based rate orders that its standard for finding rates to be “just and reasonable” is not necessarily cost-based, but must fall into a zone of reasonableness “bounded at one end by the investor interest against confiscation and at the other end by the consumer interest against exorbitant rates.”
The exercise of market power gives clear meaning to “exorbitant” but political pressures and litigators seek either inherently ill-defined and looser standards or accounting cost standards, particularly when electricity supplies are scarce and competitive market prices are high. Of course, capping the upper end of a zone of reasonableness at some measure of accounting cost would merely hearken the return to old-style regulation. For the most part, FERC and the courts have avoided going down this path. Still, the vexing problem of defining “exorbitant” remains.
Sound policy will turn to antitrust principles. Adjudging a seller’s price as “exorbitant” or otherwise “unjust and/or unreasonable” because it is just “too high” (as opposed to being too high because it was established by that seller’s exercise of market power) is a recipe for the politicization of critical economic policies. Standards of “exorbitant” and “just and reasonable” must come to grips with the fact that “just too high” criteria are destructively incompatible with market-driven electricity pricing. In particular, as our antitrust principles recognize, if a dominant seller, A, unlawfully exercises market power, its prices can properly be judged to be unjust and/or unreasonable.
At the same time, however, these principles recognize that A’s exercise of market power will generally pull up the prices of otherwise faultless sellers B, C, D…Z, and will induce expansions in those sellers’ supplies. In market-driven price regimes, this is desirable: The responses of B, C, D…Z dampen the impact of A’s conduct and hold overall price levels lower than they would be if these other sellers did not respond. B, C, D…Z’s prices may be “high” but B, C, D…Z’s responses help consumers.
“Just and reasonable” must become a standard that assesses how a price was set, not the level at which it was set.
Joseph Cavicchi is a vice president at Lexecon, an FTI Company. He provides wholesale and retail electricity market regulatory economic analyses related to the restructuring of the U.S. electricity industry. Charles Augustine is a managing consultant with Lexecon. He specializes in the analysis of regulated markets, particularly natural gas and electricity. Joseph Kalt is a senior economist with Lexecon. Dr. Kalt is the Ford Foundation Professor of International Political Economy at the John F. Kennedy School of Government at Harvard University. All three authors can be reached by phone at 617-520-0200.