The prospect of deregulation has induced a wave of mergers among electric utilities. Most of these mergers would fail an antitrust review because, by combining generation assets of interconnected utilities, they have substantially reduced potential competition in generation. In fact, one can predict that most mergers of utilities that operate within the same power pool or reliability region will be anticompetitive, even if they are not interconnected.
Mergers of interconnected utilities can, and generally will, create or exacerbate undue concentration of ownership in the market for the generation and sale of power, which will dampen competition upon deregulation.
The Federal Energy Regulatory Commission (FERC) so far has focused its review primarily on static cost savings. It has addressed competitive concerns only by imposing as a condition of approval that the merged utility file an open-access transmission tariff with a single-system rate for all companies under its direct or indirect control.
This approach fails to prevent undue concentration of generating assets, given an industry structure in which electric power transmission will be "unbundled," at least functionally, from power production and local distribution. It stands at odds with the policy objectives that underlie the FERC's recently issued rule (Order No. 888) on open-access transmission service, and with the proposals of federal legislators and a number of states.
Using an antitrust analysis, this article illustrates the potential anticompetitive effects of mergers between interconnected electric utilities. It concludes that the relevant geographic market will be an area in which a single, area-wide transmission price is charged. Moreover, it concludes that this area and, hence, the relevant market will likely span an area no larger than the Mid-American Interconnected Network (MAIN), or the Virginia/Carolina (VACAR) subregion of the Southeast Regional Reliability Council. Assuming markets of this size, the data on resulting concentration will show severe consequences for mergers of the sort that were announced in 1995 and 1996.
In fact, given these conclusions regarding the size of the relevant market for antitrust analysis, none of the recent mergers of sizable interconnected utilities could survive serious scrutiny.
The Horizontal Merger Guidelines
The Merger Guidelines1 used by the Department of Justice (DOJ) and the Federal Trade Commission (FTC) focus primarily on the pre-merger concentration of relevant markets and the extent to which a proposed merger would increase that concentration.
The DOJ and FTC first define the relevant product and geographic markets, then measure concentration within those markets to determine the proposed merger's effect on competition.
The Guidelines define the relevant geographic market by isolating the area to which consumers may turn for alternative supplies if subjected to a permanent price increase of 5 percent. For electric power consumers, the delivered cost typically will rise by more than 5 percent if even a single additional transmission charge is incurred to bring in power from more distant generators. For example, when each transmitting utility charges a "postage-stamp" rate for transmission,2 a buyer purchasing from a distant market must absorb the transmission charges imposed by more than one transmitting utility. These so-called "pancaked" transmission rates form a barrier to competition because the added cost of transmission limits the number of alternate suppliers to which the buyer can turn without additional significant cost.
How Transmission Rate Pancaking Constrains the Relevant Geographic Market
Given the structure of the transmission grid today, characterized by many utilities and unconsolidated transmission pricing, the cost of transmission often constitutes a significant percentage of the delivered cost of power, thereby affecting the size of the relevant geographic market.
This effect can be illustrated by considering what a distributor will pay in additional transmission charges to three selected utilities that are members of VACAR. Wheeling power through any of these utilities to access a distant supplier would increase a distribution company's total delivered cost by 5 to 13 percent.3
Analyzing the transmission rates of selected utilities that belong to MAIN yields similar results, even though this region boasts average transmission rates 25 percent lower than VACAR. A distributor using any of these utilities to wheel power from an alternative source would face an increase in total cost of 4 to 11 percent.4
These illustrations show that, with pancaked pricing, the additional cost to move power across
a single additional utility
transmission system would in many cases add more than the 5-percent additional cost imposed by the Merger Guidelines to determine whether supplies outside the first transmitting utility's reach lie within the relevant market.5
Why Even Region-Wide, Postage-Stamp Pricing Will Result in Markets No Larger than Areas
such as VACAR or MAIN
One proposed solution to the problem of "pancaked" transmission rates would create regional pools with a single transmission rate for service between any two points on the transmission systems of all participating utilities. This solution could help create a competitive market. To create competition, however, the pool will require at least five, and preferably more, equally sized generating companies, each operating on a sufficient scale to provide diversity and economy in meeting consumer demand and reliability requirements.6 The larger the
geographic area, the larger the number of generating units, the greater the number of companies that could generate, and the more robust the competition in generation.
However, a single transmission price for a large geographic area sends inaccurate price signals of the cost of transmission, thereby encouraging inefficient siting of generating facilities.7 The larger the area in which postage-stamp pricing prevails, the greater its potential to induce inefficient use and construction of transmission. Imagine the inefficiency arising from adding generation in Maine to serve load in Florida, made possible because the price for transmission (including losses) is assessed on a postage-stamp basis for all transmission east of the Mississippi.
It therefore seems likely that the FERC will create power pools that charge a single "postage-stamp" rate across the entire pool, but which span a geographic area no larger than necessary to create effective competition in generation.
How large will these areas be? Predicting the exact size of the areas within which single-system pricing will prevail, and thus the size of the geographic market, requires an assessment of the minimum quantity and diversity of generation assets that each competitor will require to be effective. Without attempting such a precise analysis, we illustrate the approximate size by examining VACAR and MAIN, two areas in which more than five utilities, albeit of unequal size, now operate. Assuming that as part of the restructuring, the generation assets of the companies will be more evenly distributed and that the FERC will designate each area for a single poolwide transmission rate, effective competition in generation and resulting productive efficiency should be possible. Enlarging this area would increase the inefficiency of single-system pricing without efficiency benefits of corresponding size from greater competition. These areas are thus used as a projection of the approximate size in which single-system rates will prevail and hence the maximum size of the relevant geographic market. A more precise analysis might show that utilities could effectively compete with fewer generating resources and that a smaller area could be used to constitute a power pool. Because this area now supports more than five utilities, it is doubtful, however, that such an analysis could support a larger area as the minimum size necessary for effective competition.
Based on this paradigm of the future industry structure, the effect of mergers between interconnected utilities in VACAR and MAIN can be analyzed to demonstrate the probable effect on competition of mergers of interconnected utilities.
Why Many Mergers of Utilities Operating in the Same Region will be Anticompetitive
To illustrate the effect of transmission cost on market shares, and the impact on competition of mergers of typical size, consider a hypothetical merger of Duke Power Co. with South Carolina Electric & Gas Co. (SCE&G), both of which belong to VACAR. Assume that FERC has established a single-system transmission rate within VACAR and that VACAR is therefore considered the relevant geographic market.8 An analysis of market concentration within VACAR before and after the proposed merger illustrates that such a merger would trigger strict antitrust scrutiny under the Merger Guidelines.
DOJ and FTC evaluate competition using the Hirfindahl-Hirschman Index (HHI), a statistical technique that quantifies concentration of market shares in a given industry. The HHI reflects the idea that possession of large shares of concentrated markets creates opportunities for price leadership and for unilateral reductions in output that boost prices above competitive levels.
Under the Merger Guidelines, an HHI below 1,000 is considered unconcentrated and normally creates no obstacles to mergers. A market with an HHI of 1,000 to 1,800 is considered moderately concentrated; a merger within that market will likely be challenged if the merging companies have a significant share (em depending upon other factors, such as ease of entry. Markets with an HHI over 1,800 are considered highly concentrated; a proposed merger producing an HHI of that level typically raises challenges, particularly where it would significantly increase concentration, and particularly in the presence of the kind of barriers to entry that characterize power generation.
The total annual sales of each utility are used to determine market shares, and it is assumed that there are no long-term contracts removing the capacity for these sales from the market. This reflects a conclusion that the restructuring will create a commodity market in which all power is sold at a single price that fluctuates in hourly blocks, and that current long-term contracts will be revamped as they were in the gas industry upon deregulation of the pipeline's merchant function.9 The use of each utility's annual sales data as the measure of productive capacity and ability to respond to market demand is a simplification that, if anything, understates concentration compared to examining each utility's capabilities in 8,760 hourly blocks or at the time of the region's coincident peak demand.
As shown in Table 1, the total HHI for the VACAR market is 2,279 (em well above the 1,800 threshold. Table 2 shows further how a merger of Duke with SCE&G would boost the HHI by over 527 points (em 10 times the increase of 50 that will cause a merger in such a market to be challenged under the Merger Guidelines. Even a merger between the two investor-owned utilities with the smallest market shares, SCE&G and Carolina Power & Light Co., would increase the HHI by 306.
The MAIN region holds a larger number of competitors. Even so, it carries an initial HHI of 1,896 (see Table 3). That level is still so highly concentrated that few mergers could escape challenge. A merger between Central Illinois Public Service Co. and Illinois Power Co., two utilities with average market shares, would increase the HHI by 108 (see Table 4).
The only permissible mergers between investor-owned utilities within MAIN would involve very small utilities. Almost 90 percent of those permissible mergers would include one of the three smallest utilities, which have individual market shares of between 0.3 and 2 percent.10
Thus, even a market defined to encompass a region the size of MAIN, arguably the largest area that could be designated a market in light of the effect of single-system transmission prices on efficiency, could not bear mergers between any utilities that are not unusually small. With this definition of a relevant geographic market, none of the recent mergers of sizable interconnected electric utilities could survive serious antitrust scrutiny.
The Merger of the Future
Regardless of the policy that FERC adopts with respect to merger approval, insouciance on the part of the antitrust agencies will not likely persist for long. The FTC and DOJ are already investigating how the industry will be structured after deregulation. Having studied the transition to deregulation in other industries (em
notably natural gas, telecommunications, and banking (em the DOJ can be expected soon to challenge mergers that increase concentration in already highly concentrated markets. Furthermore, before the industry restructuring is completed, regulators or legislators may subject recently merged utilities to significant divestiture of generation assets.11
Does this mean that the consolidation is over in the electric utility industry? Not necessarily. Further consolidation of transmission and distribution assets appears necessary and desirable. Because transmission and distribution assets will continue to be regulated as to access and price, mergers to consolidate them will not create the same potential for anticompetitive harm (em nor will the acquisition by generation companies of generation assets in markets remote from the geographic markets in which they now operate.12 The merger of the future, therefore, will likely involve the acquisition of generation assets in distinct geographic markets (em for example, a generating utility in New England acquiring a generating company in the Southeast.13 Once the new blueprint for the industry is better established as a model for policymaking, regulators may well condition the merger of vertically integrated utilities in the same region upon a requirement to divest the vertical components into separate transmission, distribution, and generation companies, and upon a further requirement that the generation company divest a significant portion of its generating assets.14 t
Carmen D. Legato is a partner and head of the energy practice of the law firm White & Case in Washington, DC, and a member of its worldwide Energy & Project Finance Group. He also counsels a number of stakeholders on the restructuring of the electric utility industry. Mr. Legato played a pivotal role in the restructuring of the natural gas industry, arguing the landmark Maryland People's Counsel and AGD cases that resulted in FERC's issuance of Order 436, and in 1986 he predicted the commoditization of the natural gas market in Drawing The Line on Regulation, The Harvard Study For The Future of Natural Gas. He is a former law clerk to the Hon. William J. Brennan, Jr., Associate Justice Supreme Court of the U.S. (1977 Term). Mr. Legato is grateful for the valuable assistance of Lisa A. Cottle, an associate at White & Case, in preparing this article.
1. Horizontal Merger Guidelines of 1992 (Merger Guidelines), Department of Justice and the Federal Trade Commission, 4 Trade Reg. Rep. (CCH) (pp 13,104 (1992).
2. A postage-stamp rate establishes a single price for delivery between any points of supply and delivery on the transmission system, regardless of mileage.
3. This range was calculated using the rates for point-to-point transmission service filed with the FERC by Duke ($15.89/Kw/year), Southern ($21.72/Kw/year), and Santee Cooper ($22.48/Kw/year). Assuming a load factor of 50 to 75 percent and a total cost of delivered power to a distribution utility of between 4 and 5 cent/Kwh, the cost of transmission will be between 4.8 and 12.8 percent of the total cost of delivered power. Although these rates are subject to investigation and possible reduction by the FERC, such reductions would only marginally reduce the transmission cost as a percentage of the delivered cost of power.
4. This range was calculated in the same manner as the percentages for utilities in VACAR. The selected utilities within MAIN filed proposed transmission rates between $12.04/Kw-year and $19.20/Kw-year. Applying these rates, transmission costs will be 3.7 to 11 percent of the total cost of delivered power.
5. Note, however, that the conclusion regarding transmission costs does not necessarily apply to services like load-following or reserve requirements that are called upon infrequently. Because the additional transmission costs might not be incurred often (assuming a secondary market for transmission), their effect on total cost is less, and the affected area from which generation to meet these demands can be provided will be larger.
6. For a discussion of the structural conditions that affect the size and diversity of generation assets that may be necessary for each competitor, see, W. Brand, Public Utilities Fortnightly, Feb. 15, 1996, at 25 and 28.
7. The cost to provide transmission is distance-sensitive. Various methods to reflect distance-related costs in rates have been considered. An example is zonal rates, under which a transmitting utility charges a rate for each zone through which power is transmitted. A similar approach is to develop rates based on megawatt-miles of transmission. Although distance-based rates within a utility or power-pool system probably provide efficient transmission price signals, they also restrict the distance to which buyers can turn for alternate suppliers. Even if they were an improvement over postage-stamp rates, they would tend to maintain significant barriers to the entry of more distant suppliers.
8. Today, firm sales transactions that extend beyond VACAR (or similar areas) are not uncommon. This fact will not affect the analysis used by antitrust agencies because it reflects conditions that are distorted by regulation and the current industry structure. For example, the higher transmission costs of more distant transactions are not mitigated by the great differences in the cost of generation among utilities. These large differences arise from regulatory distortions that will be eliminated by deregulation and competition. The proper analysis will focus on long-run conditions under which differences in generation costs among competitors will be relatively slight. Similarly, today's market is characterized by excess capacity in some regions that permits transactions over greater distances, despite added transmission expense. Antitrust analysis focuses on structural conditions and, therefore, upon long-run equilibrium prices rather than the short-run supply imbalances that exist today and that often make it desirable for a seller to absorb additional transmission expense to sell excess capacity at a price that recovers at least some fixed costs.
9. Today the typical practice is to separate power into "capacity" and "energy" components similar in economic effect to the way that natural gas was once exclusively sold. A strong argument can be made that this separation is an artifact of regulation that will disappear upon deregulation. For a detailed analysis of the factors that influence whether, upon deregulation, an unregulated portion of a formerly bundled regulated service can trade as a commodity, see C. Legato, "The Role of Regulation in Risk Allocation," in Drawing the Line on Natural Gas Regulation, The Harvard Study on the Future of Natural Gas (J. Kalt, F. Schuller Eds. 1986) at 217-223.
10. Of the 22 potential mergers between investor owned utilities in MAIN that would not raise significant anticompetitive concerns, 19 include Upper Peninsula Power Co. (0.3-percent market share), Madison Gas & Electric (1-percent market share), or Central Illinois Light Co. (2-percent market share). The total annual megawatt-hour sales for each of these utilities range from 0.8 to 5.8 million. Upper Peninsula is the only utility that could merge with Commonwealth Edison, the largest utility, without raising competitive concerns or triggering the presumption that market power will be created or enhanced.
11. The California Public Utilities Commission (CPUC), for example, even at this early stage, has directed two utilities in California to prepare a feasibility study of the divestiture of 50 percent of their fossil-fueled generating assets. This requirement is not based on a prior merger or other anticompetitive conduct of those utilities, but simply reflects the CPUC's view of what is necessary to permit the deregulation of generation.
12. There are a number of significant procompetitive business needs that such mergers might serve, including the creation of economies of scale in administrative and general expenses and fuel procurement and geographic risk diversification.
13. Under section 10(c) of the Public Utility Holding Company Act of 1935 (PUHCA), interconnection and geographical contiguity traditionally have been prerequisites to approval under the Security and Exchange Commission's review of utility mergers. Enforcement of the statutory standards upon such review is waning, however, and this aspect of PUHCA doubtless will be repealed as part of the restructuring process.
14. This result is foreshadowed by the CPUC's proposal that two utilities divest 50 percent of their generating assets. See, note 10, supra.
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