To what extent should regulation yield to market forces in setting wholesale electric prices? The Federal Energy Regulatory Commission (FERC) posed this question when it sought comments on whether open transmission access would eliminate the need for anything like traditional rate regulation. But when the comments came back, the Department of Justice and others answered, "not necessarily."
Surely that is the correct answer. Transmission constraints and other factors can combine to produce pockets of substantial market power. The question is how to identify these pockets when they arise.
Market power on the part of sellers is the ability profitably to maintain prices above competitive levels by restricting output below competitive levels. This definition applies both to a single seller and to the collective market power exercised by a group of sellers.1 In this definition, the term "competitive price" means the equilibrium price in a competitive market (em i.e, the marginal cost of the most costly unit necessary to satisfy industry demand.
Which costs are marginal depends on the timeframe of a transaction. For a short-term sale of energy, marginal cost would be principally fuel costs, which would vary according to the type of generating unit (em from gas turbine and diesels units at the high end, to nuclear and hydro units at the low end. For a long-term sale of capacity, all costs would be marginal.
Some Basic Tenets
No firm or group of firms can possess substantial market power if industry demand for their product is highly elastic due to the availability of good substitutes.
The degree of market power depends upon factors that affect the costs and benefits of restricting output. Of the greatest importance is industry demand, which economists characterize by its "elasticity." The elasticity of demand indicates how quantity responds to a change in price. Elasticity of demand also indicates how the price would respond to a change in output, if output were restricted to drive up price.
If demand is very elastic, the benefit from a given reduction in output is relatively quite small; no firm or group of firms can possess significant market power. What makes demand for a product very elastic is the availability of good substitutes. For example, the demand for red bowling balls is probably very elastic, because blue and black bowling balls offer very good substitutes.
The demand for electric power, however, is surely not so elastic that no group of firms could collectively exercise significant market power. Thus, we should consider what factors might affect the market power of a single firm when all firms, acting collectively, might exercise market power. Take the hypothetical example in Figure 1 of an electric industry containing only seven generating units, each having a constant marginal cost over its entire range of possible output, with no two units having the same marginal cost.
Figure 2 (see page 18) adds an industry demand curve and illustrates the competitive equilibrium. Competitive price and quantity are determined by the intersection of the industry demand curve with the industry marginal cost schedule. The competitive equilibrium serves as a baseline from which to consider the exercise of market power.
The greater a competitor's share of output in the competitive equilibrium, the greater its market power, because its output share governs its share of benefits from output restriction.
The cost-benefit tradeoff of restricting output yields several important insights on market power. Given the industry demand elasticity, two factors determine the benefit side of the market power tradeoff for a particular firm: 1) its share of industry output, and 2) how supply from other firms responds to a price increase.
As one firm restricts output and drives up price, the higher price confers benefits on all industry firms that make sales. A given firm's conduct, however, is motivated by its share of those benefits (em i.e., its share of the remaining industry output. This simple point explains why market share forms a central focus of market power inquiries.
A competitor's market power grows as the supply of product offered by rivals (in the neighborhood of the
competitive price) becomes less
As any one firm restricts output, its rivals typically find it profitable to boost production. If rivals make up for the restricted output using resources with the same marginal cost as those from which supply was restricted, then the firm restricting output would have no market power, because the output restriction would not drive up price. If Figures 1 and 2 were modified so that all units carried the same marginal cost, then the owner of even several units would enjoy no market power. As Figures 1 and 2 are drawn, however, the owner of a single unit can exert significant market power because an output restriction could not be made up for by a unit with a marginal cost very close to the competitive price.
Owning resources not used in competitive equilibrium may enhance market power if those resources would become economical when market power was exercised.
It is important to note here that no market power is conferred by owning a resource that is not used in equilibrium. The owners of units 6 or 7 alone would have no market power, since they sell nothing in the competitive equilibrium and thus cannot restrict
output below the competitive level. Nevertheless, this fact does not make units 6 or 7 irrelevant. If a firm owned both units 5 and 6, it would possess more market power than if it owned unit 5 alone, because unit 6 represents the next-best source of supply once output from unit 5 is restricted.
The market power of a particular firm may vary over time as demand conditions vary.
Industry demand may be greater at certain times than it is at the time illustrated by Figure 2. If so, ownership of units 6 and 7 could confer market power at such times.
The smaller the difference between the price and the marginal cost at a particular resource, the greater the market power conferred on the owner, provided that the resource operates in the competitive equilibrium.
On the cost side of the market power tradeoff lies the profit that must be foregone if output is restricted (em i.e., the difference between price and marginal cost for each unit of output restricted. In our example, with no difference between the two measures for unit 5, owning that unit alone would confer significant market power. The difference between price and marginal cost is quite large for unit 1, however, so owning unit 1 alone might not confer significant market power.
Defining Relevant Markets
Antitrust principles supply a well-developed theory with which to delineate markets within which to identify competitors.2
A group of products and geographic areas constitute a market if, and only if, a monopolist could exercise significant market power over them. The market power of a monopolist would be largely determined by the elasticity of demand it faces; thus, market delineation is largely a process of measuring (em or intuiting (em the elasticity of demand for groups of products and areas. The process is applied to groups of products and areas of increasing scope until one is found in which a monopolist would have significant market power.3
Product Dimensions. In the wholesale electric power industry, a host of different products are traded; competitive conditions might differ significantly from one product to the next. Potentially important product distinctions include (a) energy vs. capacity, (b) firm vs. nonfirm, (c) peak vs. offpeak, (d) long-term vs. short-term, and (e) present time vs. future time.
Since electricity is not stored to any great extent, it is theoretically appropriate to delineate at least 8,760 separate hourly markets for short-term power within a year. From a practical perspective, however, competitive conditions are not likely to vary systematically from one hour to the next, although they might vary significantly seasonally, or from on- to offpeak.
In light of current market institutions and the possibilities for substitution among various types of supply arrangements, it might be reasonable to delineate three major products: 1) short-term energy or capacity, 2) intermediate-term capacity, and 3) long-term capacity. The distinction between the latter two comes from the lead time for the transaction (em the long run entails sufficient lead time so that newly constructed capacity can compete. The distinction between the former two lies in the duration of the transaction; and, hence, its role in system planning.
The process of market delineation naturally depends on existing market institutions. A PoolCo would vastly reduce the number of products that must be considered, leaving only short-term energy.
Geographic Dimensions. If markets are large enough geographically, they will likely include a large number of competitors; markets that are very small will include very few. In principle, the geographic scope of a market depends upon the sources of available supply, the likely prices at those sources, and the transmission costs that a wholesale
customer would likely pay. Unfortunately, transmission pricing now appears in a state of flux, making it difficult to readily determine what transmission costs might be.
The examination of existing trading patterns and the identification of significant transmission bottlenecks should provide a rough approximation of geographic market boundaries. However, such an approximation would likely understate the scope of markets, for two reasons: 1) Existing patterns of trade are not premised on open-access transmission; and 2) The attempt to exercise market power could promote substitution to more distant sources of supply than are currently relied upon.
A far more refined analysis would combine existing
transmission models with information on loads, generating capacities, and unit marginal cost schedules, at all relevant points within the transmission network. All this information should be readily available, and could be used within a computer program that minimizes the cost of satisfying the specified loads, given generation capacity and costs, as well transmission costs and constraints.
Delineating markets would involve restricting output from the generating units in a region and determining the effect on prices and profits. If power from other regions makes a significant price increase either impossible or unprofitable, the selected region is too small to constitute a market. Some years ago, the Justice Department used such a model to delineate markets for coal and obtained satisfactory results.4
This approach offers two tremendous advantages. First, it is almost entirely objective. Second, this approach would simplify an investigation into how markets might change with additions of transmission or generating capacity, or changes in transmission pricing.
Assigning Market Shares
The market for long-term capacity presents little need to assign shares: All those capable of building plants should be considered competitors in markets for long-term capacity, which generally should assure markets that are dramatically unconcentrated.
But for short-term energy and intermediate-term capacity, shares should be assigned on the basis of existing generation capacity.
In assigning shares, however, the use of total capacity is problematic because some utilities are net
buyers, while others are net sellers. Excluding capacity committed to serve native load addresses this problem. Under present market institutions, capacity committed to serve native load perhaps should be treated as off the market; additional output from such capacity could not prevent an exercise of market power. Thus, shares of excess capacity provide much better indicators of the likelihood of a significant exercise of market power than do shares of total capacity. This conclusion, however, is premised on present market institutions, and would not apply if all generation were sold through a PoolCo.
The proper treatment of long-term sales contracts presents
a similar issue. The share attributable to the contracted capacity should be assigned to the buyer under the contract. However, if the buyer is a distribution utility or end user, it may be best not to count the contracted capacity in assigning market shares.
Similarly, out-of-region capacity the sale of which is significantly constrained by lack of transmission capacity should also be discounted. Capacity constrained in such a way cannot take up any of the slack in the event of an output restriction, and cannot significantly constrain the exercise of market power.
The most important resources are those low enough in cost to be used in competitive equilibrium, yet high enough in cost to permit relatively small differences between price and marginal cost. Although these resources are the most profitable from which to restrict supply, they should not receive special weight in assigning market shares. All low-cost capacity is relevant to the benefit side of the market power tradeoff, and most high-cost capacity is marginal at some times. Moreover, any weighting scheme would be arbitrary.
An alternative to weighting is to compute a second set of market shares for mid-marginal cost
capacity, e.g., fossil-fueled units with relatively high average load factors. These market shares would not be used in place of those computed for all capacity, but could provide additional perspective as to whether market power could be exercised.
Having assigned market shares, it is highly useful to summarize those shares with an index of
market concentration. The most popular index today, the
Herfindahl-Hirschman Index (HHI), is computed by squaring each market share, then adding up the squared shares. For example, for three firms with shares of 20, 30, and 50 percent, respectively, the HHI would equal 3,800 (400 + 900 + 2,500). The HHI approaches zero when there are a large number of very small firms, and equals 10,000 when there is just one.
Five equal-sized firms yield an HHI of 2,000. An HHI of 2,000 or less would reflect a reasonably competitive electric power industry (see sidebar, "Market Concentration and Market Performance"). Market power sufficient to warrant price regulation would entail even greater concentration, given the social costs of regulation.
In the context of oil pipelines, the Department of Justice has suggested that markets should be presumed sufficiently competitive for market-based pricing if the HHI falls below 2,500.5 Paul Joskow recently proposed the same rule for electric power generation,6 and I would be inclined to accept this rule as well.7
The rule should state that an HHI below 2,500 establishes a rebuttable presumption that market-based pricing would produce just and reasonable rates. Importantly, however, this presumption would still allow an intervenor to prove substantial market power despite the HHI.8
Even if the market HHI is high, a small individual firm would probably find itself unable to exercise market power if larger firms were subject to price regulation. Thus, a presumption of no market power could arise from a demonstration that a firm's market share is no more than, say, 20 percent.
Mitigating Market Power, Securing
I strongly urge the FERC to establish some market share and/or market concentration screens that could be used to establish a presumption in favor of market-based pricing. [Absent such a presumption, utilities can, of course, make a case for market-based pricing. Where enormous excess capacity exists relative to demand, for example, the distribution of excess capacity among firms becomes unimportant, making the market share of a single firm inconsequential, despite a large HHI.]
Presumptions based on market share or market concentration screens would allow utilities that are so inclined to assure that they pass through the screens. And I would have no qualms about utilities agreeing among themselves to take such steps so that all can secure the blessings of market-based pricing. Such a concerted effort would not seem to create any significant antitrust exposure.
The most obvious step a utility could take would be to sell one or more generating units outright, to firms with little or no capacity. Short of outright sale of a unit, a utility could enter into long-term contracts that effectively transfer the rights to operate a unit and to sell the power that it generates. Similarly, a utility could enter into long-term, fixed-price contracts with distribution companies. If a utility with market power presells a large fraction of its competitive output, its market power is drastically reduced.9
The foregoing steps are designed to reduce a firm's market share. A utility, or group of utilities, might also enlarge the market by strengthening interconnections to permit out-of-region power to compete better. t
Gregory Werden is director of research, economic analysis group, in the Antitrust Division of the U.S. Department of Justice. The views expressed herein are not purported to be those of the U.S. Department of Justice.
Market Concentration and Market Performance: 5 Gencos Are Enough
Economic models predict how the number and size distribution of competitors affect output and the equilibrium price. These models fall into two classes, reflecting interaction among competitors:
. Competitors act independently, based on their own profits.
. Competitors coordinate their strategic decisions, or "collude" in some sense of the word.
Of the two classes, only the first allows for predictions reliable enough to warrant serious consideration. One very interesting model comes from Richard Green and David Newberry.* They consider a noncooperative interaction among generating companies using supply schedules as competitive strategies. These schedules indicate how much they are willing to sell at each price. The model predicts performance in the British-Welsh pool, which has only two substantial competitors.
Green and Newbery find competition lacking with only two sellers. Many commentators agree that actual performance in the British-Welsh pool is quite inadequate. On the other hand, Green and Newbery also find that the number of sellers need not be very large to achieve virtually all the benefits of competition; five equal-sized firms should do it. Their results are comparable to those from other models and reasonably representative of general economic thinking on the subject.
*Richard J. Green & David M. Newbery, "Competition in the British Electricity Spot Market," 100 Journal of Political Economy 929 (1992).
The Cost-Benefit Equation for Electric Power Regulation
Regulation of market power implies benefits and costs. In some cases, the direct administrative costs of regulation may approach or outweight the potential gain in social welfare. More frequently, however, the important social costs arise from distortions from improper price signals. Estimates run as high as $100 billion a year for the potential direct gains from more efficient pricing of electric power.*
Due to these inherent costs, significant market power is not currently viewed as sufficient to justify price regulation in any industry. If we did not already have wholesale electric price regulation, it seems unlikely we would get it now. But we do have it.
*Tabors Caramanis & Assoc., Unbundling the U.S. Electric Power Industry: A Blueprint for Change, pp. 44-51 (March 1995).
1. In the case of price-regulated industries, market power might manifest itself in other ways if regulation constrains prices to competitive levels. A proviso sometimes inserted in the definition of market power is the absence of price regulation. Thus, as a matter of definition, regulation can effect the ability to exercise market power, but not the existence of market power.
2. See, Gregory J. Werden, "Market Delineation under the Merger Guidelines: A Tenth Anniversary Retrospective," 38 Antitrust Bulletin 517 (1993); Gregory J. Werden, "The History of Antitrust Market Delineation," 76 Marquette L. Rev. 123 (1992); Gregory J. Werden, "Market Delineation under the Justice Department's Merger Guidelines," 1983 Duke L. Journal 514.
3. Significant market power is generally defined in this context in terms of the price increase that a monopolist would impose. In the merger antitrust context, a five-percent price increase typically is used. The social costs of regulation suggest the use of a significantly larger threshold in determining whether to engage in price regulation.
4. Antitrust Division, U.S. Department of Justice, Competition in the Coal Industry, pp. 20-47 (December 1982).
5. Antitrust Division, U.S. Dept. of Justice, Oil Pipeline Deregulation, pp. 29-30 (May 1986).
6. Paul L. Joskow, Horizontal Market Power in Wholesale Power Markets, Appendix A to Initial Comments of Edison Electric Institute, FERC Dkt. Nos. RM94-7-001, RM-95-8-000 (August 1995).
7. One very large firm could be in a position to exercise significant market power, even if the market HHI was below 2,500. Thus, it might be appropriate to add an additional proviso that no firm have a share of more than, say, 35 percent. This would be appropriate, however, only if the supply from other firms were not very elastic.
8. In antitrust cases and prior adjudications before the FERC, the focus typically has been on market delineation analysis I sketched out earlier could short-circuit fruitless battles of experts on market delineation. If so, I would expect that the presumption would rarely, if ever, be overcome.
9. See, Richard Green, "Britain's Unregulated Electricity Pool," in Michael A. Einhorn, From Regulation to Competition: New Frontiers in Electricity Markets, ch. 4 (1994).
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