Fortnightly
Is Competition Lacking In Generation? (And Why It Should Not Matter)
January 01, 1997
By Judah Rose, Shanthi Muthiah, and Maria Fusco
Incumbent monopolists won't command high premiums
if newcomers can rebuild capacity from scratch at a cheaper price.
At first glance, many of the nation's regional markets for wholesale electric generation appear monopolistic. In some of the 18 regional power markets we have identified, the leading companies account for 75 to 90 percent of the area's generating assets. In other markets, where the concentration problem does not yet seem as pressing, mergers and acquisitions threaten to raise levels of concentration of ownership in generation.
State regulators have not lost sight of these facts. They do not appear fully satisfied by attempts at the Federal Energy Regulatory Commission (FERC) in Order 888 to mitigate market power in transmission, and its affect in electric commodity markets, even though wholesale deregulation is already fairly advanced and blatant signs of market power are rarely seen, even in markets that show a high degree of concentration. California, for example, has required electric utilities to sell 50 percent of their fossil generation as part of the golden state's restructuring plan.
Perhaps regulators see the current situation (few concrete examples of market manipulation) as a temporary phenomenon. Today, few buyers can participate in the wholesale market; enough sellers can usually be found to create competition. But once retail customers can choose power supply directly and independently, regulators might see a huge demand chasing a dearth of suppliers.
When private companies asked us to factor monopoly power into market assessments, we sought economic approaches that avoid pinning the answer in whole or in part on regulatory and legislative action, which can prove difficult to predict and which can vary among states and regions, or among state and federal jurisdictions.
Thus, we have taken a practical angle: How bad can it be? How high would prices climb (long-run, wholesale prices) without any regulatory action in the generating sector?
Our analysis focuses on the economic incentives and cost barriers that affect the behavior of incumbents and market entry by newcomers.
We have developed an approach for estimating limits on monopoly prices1 and have found very little potential for higher monopoly prices to prevail. In fact, we have found that the cost of rebuilding the entire generation system \(em a key factor constraining monopolistic behavior by incumbents \(em is actually lower (by about 15 percent) than the predicted long-run, wholesale equilibrium price in a largely competitive generation market. This paradox occurs largely because of the low current cost of building gas-fired generation. Stated in a different way, incumbent power producers cannot likely sustain any price level for more than one to three years that would be a significant monopoly premium above long-run competitive levels, even if deregulation adopts a laissez-faire attitude toward concentration in generating markets.
This conclusion assumes that new natural gas-fired plants can be built (i.e., permitting, financing and operation is feasible), and that the FERC eliminates transmission market power, as promised by Order 888. This conclusion remains less sensitive than one might expect to assumptions about natural gas prices and the willingness of customers to sign long-term contracts with power producers.
The Effective Price Ceiling
Market power has limits, even when let loose by deregulation.
In the case of electric generation, even with deregulation and a head-start for incumbent power producers, we can expect to find a ceiling on the price of wholesale power as it evolves in a competitive market, owing to the cost advantage afforded by newly built, gas-fired, simple-cycle combustion turbines and combined-cycle generating plants. We can refer to this limit as the "equilibrium price ceiling," the "monopoly price ceiling," the "contestable price," or even the "rebuild price."2
This price ceiling lies one to three years out \(em the time it takes to bring new plants on line \(em which limits even unfettered generation market power. The ceiling equals the cost to new entrants of meeting customer demand for wholesale electricity with a mix of new gas-fired powerplants.
Observers have long argued that the future market for generation can be competitive since independents can build new gas-fired powerplants based on jet engine technology with low costs for capital investment. This claim rests several factors:
• Obtaining permits for new gas-fired plants has proven feasible throughout the country
• Transmission access is increasingly assured by deregulation
• Little technological sophistication is required for gas-fired operations, relative to older plant designs
• Electric demand is growing, raising the likelihood of capital recovery, even in a competitive market.
In effect, the price ceiling marks the cost of a rebuilt system. But the exact ceiling price is something of a paradox, for, as we have found, the cost of rebuilding the generation system \(em the key constraint to a monopolist \(em is actually lower (by about 15 percent), than the expected competitive price at long-run market equilibrium. This paradox occurs partly because new gas-fired powerplants carry a lower cost than older plants, and partly
because of the effect of capacity value.3 Figure 1 reveals how this "contestable" (or "rebuild") price lies below the expected competitive price for generation.
Regional Examples
We have selected three anonymous regions to illustrate the relationship between the competitive and rebuild prices. In each case, the rebuild price reflects the average cost for essentially rebuilding the generation system using a mix of gas-fired plants: 1) simple-cycle combustion turbines used for peaking and reserve back-up, and 2) combined-cycles plants for "heavier" operations. (See Tables 1, 2, 3.)
Surprisingly, the average rebuild price for the three regions is slightly lower than the expected competitive price \(em by about 5 percent, or $1.50 per megawatt-hour (MWh). This quantitative result also highlights several important factors in electric generation: First, electric demand growth has wrung out some of the industry's excess capacity over the last few years, which should raise the expected competitive price. Second, the improvement in rebuild technology (gas plants) produces lower short-run variable costs. Third, available gas supplies plus an adequate selection of construction sites for new gas-fired plants in most regions makes the rebuild technology a viable competitor against incumbent producers.
How reliable are these estimates?
As shown in the tables, our analysis includes estimates of the uncertainty in the form of standard deviations). In short, we conclude that the likelihood could run as low as one tenth of one percent that the ceiling price (the rebuild price) would run as much as $10/MWh (one cent/kWh) higher than the long-run equilibrium competitive price.4
Gas Price Uncertainty
The idea of a price ceiling for a rebuilt system depends in part on estimates of natural gas prices, since over half the costs will represent fuel costs from operations.
Recognizing that natural gas prices were particularly volatile during the 1970s, and that increased demand for gas-fired plants might drive gas prices upward, some observers might shy away from making any conclusions about a theoretical price ceiling. However, one should not go too far in allowing gas price uncertainty to discourage attempts to use economic analysis to predict future prices in electric generation.
In fact, the gas supply curve appears to be fairly flat, and for several reasons. First, long-run gas prices available in the market are not much higher than recent average prices. Suppliers do not anticipate major price increases. Second, over the last several years, annual average gas prices have remained relatively low and stable (with the Henry Hub running $2/MMBtu in 1996 dollars). Third, and most important, our own forecasts (developed from exhaustive analysis of gas demand and of North American gas supply reservoir by reservoir) indicate that gas prices are likely to remain stable, as expressed in real terms (inflation adjusted) on an annual average basis.
Moreover, as the futures and forward markets appear well developed for natural gas, independent power producers (IPPs) can contract for natural gas at known prices for extended periods \(em up to fifteen years or longer. IPPs can sign contracts simultaneously with different gas suppliers and electricity customers facing the monopolist and lock up all components of a deal, eliminating uncertainty.
Nevertheless, to the extent the price ceiling remains sensitive to gas prices, the premium (i.e., the ceiling minus the long-run competitive price) is considerably less so. This distinction arises because one can expect the ceiling price and the competitive price to move in tandem, especially in the future. Today, many regions already exhibit a strong correlation between power and gas prices. The competitive price is not set by the average, but by the marginal fuel source. Over time, even those regions marked by a heavy reliance on coal, hydro, or nuclear resources will burn natural gas on the margin for most of the year.
Barriers to Entry
New power producers face one particularly serious entry barrier \(em the need to sign contracts with customers.5
Private power developers have achieved a fair degree of success in recent years in permitting, financing, building, and operating new gas-fired combustion turbine and combined-cycle powerplants. However, this success has leaned heavily on long-term purchased power contracts \(em either with host industrial customers or with electric utilities. These contracts protect entrants from a drop in prices following entry \(em particularly from a fall in prices that might occur if too many entrants create excess capacity.6
Suppose the entrant is obliged to risk its own capital. That would allow the monopolist to charge more than the competitive price.
This situation can be visualized as a monopolist facing a somewhat flattened but stepped demand curve (see Figure 2). The curve is flatter than the previous demand curve in Figure 1 since all customers enjoy access to a close substitute \(em power from a new company that differs only for want of a contract. From the monopolist's perspective, there is some premium that maximizes his profits (see Figure 2). Some large customers might be willing to sign contracts, while others might prove unwilling to commit to long-term contracts with the new entrants.
Nevertheless, we still conclude that significant premiums are very unlikely.
First, as stated, relative to other industries, there is relatively very little room to raise prices because the rebuild price is below the likely competitive price. Second, many buyers will be ready to commit a portion of their supply to contracts of somewhat longer terms (e.g., 3-7 years), if only to hedge risk or balance portfolios. Third, the low capital intensity of the new gas-based power industry allows entrants to jump in, even without long-term contracts, as soon as the monopolist raises prices too high. A premium of $5/MWh (about 15% above the typical competitive price) would allow an entrant to recover capital costs within about 5 years.
Finally, the possibility of the monopolist mismanaging his position by excessively raising prices creates the potential for the opposite result \(em i.e., entry by new competitors, producing excess capacity and lower prices at less than competitive equilibrium levels.
Regional Exceptions
The regions of the country most commonly considered to be at risk for monopoly (or oligopoly) price premiums all exhibit one or more of several key characteristics. First, one or two companies produce a very large portion of the power. Second, transmission constraints limit competitive sources of power.
Examples would include:
• South. The Southern Company system strongly dominates generation in Alabama, Georgia, eastern Mississippi, and the Florida Panhandle. It would be the only supplier capable of immediately supplying power to retail customers.
• Texas. In the Electric Reliability Council of Texas (ERCOT), two companies, Houston Lighting and Power and Texas Utilities account for 75 percent of generation. Further, this region has assiduously pursued a policy of relative transmission isolation.
• South Central. Like The Southern Company, Entergy almost entirely controls generation in the Louisiana, Arkansas, western Mississippi areas.
For reasons discussed above, even though their regions are more at risk, the overall risk is very low. Rather, the risk is primarily focused on exceptional cases with barrier to entry (e.g., lack of sites, costly sites). For instance, in micro-markets ("load pockets") that created by transmission constraints, and pockets of excess capacity where the competitive price is depressed. While we have not examined every market, we expect nearly all markets to be in balance within 3 to 6 years.
Implications for Would-be Competitors
This analysis predicts that monopolists in the wholesale generation sector should count on only a very small premium above the competitive price that would prevail in a wholesale power market in equilibrium. This prediction assumes that the FERC will succeed in eliminating the exercise of market power that large companies might exercise via their control of transmission.
Moreover, this lack of premium potential, attributable largely to supply alternatives offered by simple-cycle, gas-fired combustion turbines and combined-cycle plants, exists despite alleged uncertainties in natural gas prices, and remains independent of regulatory action aimed at limiting or controlling market power in generation.
Thus, would-be competitors in generation markets should concentrate their focus on market power in transmission \(em not generation \(em and on barriers to entry, such as permitting obstacles or factors that might discourage long-term contracts. t
1This approach applies "the contestable market approach" to the power sector. See, Baumol, Parzar, and Willig, Contestable Markets and the Theory of Industry Structure, Harcourt, Brace, Jovanovich, New York, 1982.
2In the literature, the contestable price is the average cost of producing electricity combined with the lack of fixed cost. In our paper, we use the term contestable price because a developer could enter the business with very little commitment of his own funds. He could sign up customers, power equipment and fuel suppliers and project finance with little of his own capital. Later in this paper, we relax this assumption \(em i.e., he does need a small amount of his own capital \(em but do not change our basic conclusion.
3This paradox makes it appear that rebuilding the system generally and immediately makes sense. This is not the case. Under a competitive market, as the rebuilding proceeded, the capacity component of the competitive price would collapse and the builders would lose money. It is only under the circumstances in which the monopolist (or oligopolists) have raised prices that new entrants can offer consumers a contract for power and then rebuild. See note 5, infra.
4Assumes independence of the competitive and monopoly price; this is an overestimate in some markets where independence is low.
5Our argument, thus far, can be seen as a pure contestable price argument. Entrants can enter without risking their own capital since they can project finance based on contracts with ultimate customers and plant and fuel suppliers.
6The maximum magnitude of this price drop can be approximately estimated, on the theory that this excess capacity would erode the value of the "pure" capacity component of the competitive price for bulk power. If that would occur, and if and the capacity price would fall to zero, the power price would fall about 25% from the expected value, dropping the long-run equilibrium competitive price below the contestable (rebuild) price by about 25 percent, or about $7/mWh.
For examples of how to calculate the capacity component (as distinct from energy value) of a deregulated price for wholesale power, see, "Unbundling the Electric Capacity Price in a Deregulated Commodity Market," by Judah Rose and Charles Mann, PUBLIC UTILITIES FORTNIGHTLY, December 1995, p. 20.
APPENDIX
A. The Monopoly Price Ceiling
Some analysts have used a shorthand approach of assuming that the costs of rebuilding the system are the average costs of a new gas-fired combined cycle unit. This approach is inappropriate, however. Despite their low cost, simple-cycle combustion turbine powerplants are 40 to 50 percent less thermally efficient than combined cycles. The combined-cycle plant can save enough on fuel costs to more than pay for the higher capital cost. The model includes a mix of both plant types, which generally produces a lower price ceiling than that obtained by referring only to combined-cycle plants.
Thus, we present a modified approach that involves four steps in determining the appropriate mix of simple- and combined-cycle units:1
1. Break-even Point. Determine the capacity factor or annual service level at which the average levelized power costs of the two plants are equal (see Figure A1). This break-even point depends on gas prices and on the costs and performance of the two types of plants.
2. Capacity Mix. Review the system demand profile. For example, in the case in which the portion of demand to be served by simple-cycle plants is that portion with low load factors (10 percent or less),2 then the percentage of simple cycles in the mix is approximately 45 percent, as shown by the load duration curve (see Figure A2).
3. Plant Operations. Employ the load duration curve to determine specifically the relative utilization levels of peaking and baseload units. We expect low utilization of peaking units (simple-cycle turbines), but a high utilization rate for the baseload units (combined-cycle plants).
4. Average Costs. Determine average costs as the sum of the generation weighted average variable costs and the capacity-weighted fixed costs.
B. The Competitive Market Price
In the competitive market, prices are equal to marginal costs. In particular, firm wholesale competitive prices are determined as the sum of unbundled marginal costs of supplying electrical energy (system lambda or economy energy) and the costs of supplying pure or unbundled capacity.3
Figure B1 shows estimates of the competitive marginal costs of electrical energy, the first and largest component. These estimates are derived from recent historical statistics. In most regions, today's prices reflect primarily the marginal costs of producing electrical energy from existing powerplants. These figures are often low, reflecting the low operating cost of coal-fired generation. These low prices exist because of excess capacity, much of it in coal and nuclear resources that would not be built today.
Around 2000 to 2005 (note our estimates presented in Table 1 are for 2000), firm prices will reflect the combined costs of electric energy and pure capacity. The equilibrium marginal capacity cost is set by the cost of installing gas-fired combustion turbine capacity (see Figure B2). This figure can account for about 25 percent of the cost of meeting customer demand. As the excess capacity of low-cost coal powerplants is exhausted, prices increasingly reflect the marginal costs of higher-cost coal plants, gas-fired steam plants, and combustion turbines.4
Over twenty to thirty years, the price under a competitive market will equal the ceiling price under market power today. In other words, we can expect the premium between the two prices to decrease over time, and for the prices to converge, since in both cases prices will reflect a rebuilt system.
7. In this analysis, the costs of the rebuilt system do not depend on the costs of alternative sources of generation such as coal.
8. In our analysis, we assumed that the entrant would not have to meet the planning reserve margin of other utilities in the region. This is appropriate if reserve sharing is mandated, or if we can anticipate that there is the potential for excess capacity and competitive markets.
9. See, "Unbundling the Electric Capacity Price in a Deregulated Commodity Market," by Judah Rose and Charles Mann, Public Utilities Fortnightly, December 1995, p. 20. See also text, footnote 5, supra.
10. Engineering economic models were used to forecasts prices for 2000 under a range of potential future conditions, weighted by probability. The outputs include standard deviation of price, and correlation coefficient between electricity and natural gas prices. See, "Price Risk Management: Electric Power versus Natural Gas," by Judah Rose and Charles Mann, Public Utilities Fortnightly, Feb. 1, 1996, p. 24
Judah Rose is a Vice President at ICF Resources, Fairfax, VA, and directs support for power market research. Shanthi Muthiah is a Senior Associate and Maria Fusco is an Associate at ICF Resources.
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