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In March 1998, the Clinton Administration released its Comprehensive Electricity Competition Plan [22], and in June 1998 the Secretary of Energy submitted the Administration's proposed legislation to implement the plan. Section 302 of the proposed Comprehensive Electricity Competition Act [23] calls for the establishment of a Federal RPS. Beginning in 2000, each retail electricity supplier would be required to submit to the Secretary of Energy renewable energy credits in an amount equal to the required percentage. Credits would be earned for each kilowatthour generated from solar, wind, geothermal, or biomass plants. The proposed percentage reaches 5.5 percent in 2010 and remains there through 2015. Between 2000 and 2010 the required percentage is to be determined by the Secretary of Energy, but it would be less than 5.5 percent. The following analysis illustrates the potential effects of the proposed RPS. For purposes of the analysis, it is assumed that the required share would grow linearly from 0 to 5.5 percent between 2000 and 2010 and remain at 5.5 percent through 2015, at which time the requirement would be eliminated [24].

The RPS would have an impact on the types of plants built to meet the growing demand for electricity. New wind and biomass plants, and geothermal to a lesser extent, are expected to make key contributions in meeting the RPS (Figure 11). In the reference case, only 9 gigawatts of new renewable plants are expected to be built, because in most situations they are not competitive with fossil alternatives. Under the proposed Federal RPS, however, renewable technologies would play a larger role. In the Federal RPS sensitivity case, more new wind plants are expected to be built in

Issues in Focus

some regions of the country, particularly in the Northwest, Southwest, and Upper Midwest.

The United States has vast wind resources in some areas, but many are in regions of low demand, and there is some uncertainty about the costs of developing them and delivering their power. For example, some of the best wind resources are located far from transmission lines and load centers, in environmentally sensitive areas, or on terrain that it is not suitable for economical construction.

In terms of biomass, there are significant supplies of relatively low-cost biomass that, for the most part, are not currently being used for energy production. The low cost of fossil fuels, particularly coal, makes them unattractive. For example, there are large amounts of urban wood waste, tree trimmings, construction and demolition debris, and discards such as crates and pallets that could be burned to produce energy, rather than disposed of in landfills. These materials can be burned in standalone facilities, but a less expensive alternative may be to use them as a secondary fuel in existing coal-fired plants. Many existing coal plants may be able to consume up to 5 percent of their total fuel input as biomass with relatively minor modifications, and even higher levels are possible with more significant modifications. In this analysis, coal-fired plants are permitted to meet up to 5 percent of their fuel needs with biomass if it is economical; however, use of the biomass option is limited by the projected low cost of coal.

Although the required share for renewables is relatively low in the Federal RPS sensitivity case, it would nevertheless have an impact on electricity prices (Figure 12), which are projected to be almost 2 percent higher in 2010 and 2015 than they are in Figure 12. Change in average U.S. electricity prices in the Federal RPS sensitivity case from the reference case, 2000-2020 (percent)

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Issues in Focus

the reference case. The impact is less in the later years because renewable technologies are expected to become more economical over time, with costs declining once they begin to penetrate the market. The price impact almost disappears in 2020, when the RPS has ended. The projected price differences are relatively small, but they do amount to an added cost to consumers. The annual impact varies between $1.4 billion and $3.7 billion a year between 2005 and 2015, with the average residential electricity bill projected to be about $1 a month higher than in the reference case in 2010 (Figure 13). After 2015 the impact declines sharply.

Figure 13. Variation from reference case national electricity costs in the Federal RPS sensitivity case, 2005-2020 (billion 1997 dollars)

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The imposition of the RPS would have a positive effect in reducing emissions. Because the new renewable facilities built to comply with the RPS would displace output from fossil plants, total emissions would be lower. For example, the 5.5 percent RPS reduces electricity sector carbon emissions by approximately 23 million metric tons a year between 2010 and 2020 (Figure 14). Emissions of nitrogen oxides (NO) and sulfur dioxide (SO2) are

Figure 14. Projected U.S. electricity-related carbon emissions in two cases, 1996-2020 (million metric tons)

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not significantly reduced, because their levels are explicitly capped, and implementing the RPS would not lead to further reductions. The imposition of the RPS is projected to reduce slightly the incremental cost of meeting the NO, and SO2 caps.

Electricity Pricing in a Competitive
Environment

Electricity markets in many parts of the United States are being restructured to increase competition. Competitive pressures are affecting the operations of electricity generators, even in areas where no formal restructuring legislation has been introduced. For example, operating and maintenance costs for existing power plants have been falling in recent years, and further reductions are anticipated. To reflect this trend, the AEO99 reference case assumes a 25-percent reduction in current nonfuel operating costs in all regions over the next 10 years. Capital costs and operating efficiencies for new plants are also assumed to improve over time in all regions.

Future investment decisions may also be affected by increasing competition. Accordingly, the AEO99 reference case assumes higher costs of capital and shorter recovery periods. Thus, the reference case forecast incorporates many of the expected effects of industry restructuring in all regions, including those where competitive pricing legislation or other binding rules have not been passed.

Historically, prices have been set administratively as the average embedded costs of producing elec tricity, including all fuel and operating and maintenance costs, as well as recovery of construction costs and a regulated profit. In a competitive market, generation prices will vary over time (even hour to hour), and will be set in each time period by the operating costs of the most expensive plant needed to meet demand at that point in time-the "marginal cost" of production. The marginal cost typically includes the fuel and variable operating and maintenance costs for the generator.

During periods of high demand in a competitive market, when the demand for electricity approaches the available generating capacity, prices might rise over the operating costs of the most expensive gen erator operating. Such occasional price spikes can encourage consumers to reduce their usage so that

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supply and demand are kept in balance. Similarly, prices consistently over the marginal operating costs will provide incentives for the construction of new generating capacity.

In AEO99, a full competitive pricing sensitivity case assumes that competitive pricing will be phased in throughout the United States over 10 years, with full competitive pricing based entirely on marginal costs occurring by 2008. Currently, marginal operating costs are generally lower than average embedded costs, which include the recovery of construction costs on plants that are not competitive in today's market. With a gradual shift to full competitive pricing, it is assumed that a portion of such costs will be recovered in the competitive price. When the uneconomical generators have either been paid for or retired, average costs are expected to approach, and possibly fall below, marginal costs. In the early years of the forecast, coal-fired units are projected to be used most often to set the marginal cost (Figure 15). In the later years, as demand increases and most new capacity is gas-fired, the projected marginal unit is more often a combined-cycle or turbine unit, and the marginal costs are dependent on gas prices. As a result, by 2020, marginal costs are projected to be slightly higher than average costs. Figure 15. Percentage of time that different plant types set national marginal electricity prices, 2000, 2010, and 2020 (percent of total)

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Issues in Focus

competitive pricing are assumed to have competitive electricity prices in both the reference and full competitive pricing cases. (The reference case assumes a transition to competitive pricing in California, New York, the New England States, the Mid-Atlantic States, and the Mid-America Interconnected Network-Illinois and parts of Wisconsin and Missouri.) As a result, the projected differences in national average electricity prices between the two cases are relatively modest, ranging from 5 percent lower in 2005 to 4 percent higher in 2020 in the full competitive pricing case than in the reference case. In 2020, the electricity price in the full competitive pricing case is higher than in the reference case because of increasing natural gas prices, which affect marginal electricity prices more directly than average prices. Detailed results from the full competitive pricing case are presented in Appendix F, Table F9.

The full competitive pricing case also assumes that some consumers will be able to respond to time-ofuse pricing by altering their demand patterns. Through "load-shifting," consumers can reduce usage during a peak period, when prices are high and supply is tight, and shift that usage to an offpeak period. The net effect is lower peak demand and a flatter demand pattern for the year, with less variation between the lowest and highest points. Load shifting could also reduce the need for new capacity, because peak demand would be lower, so that different types of capacity would be built. In the full competitive pricing case, 28 gigawatts less new capacity is projected to be built by 2020 than in the reference case. Some of the difference results from lower reserve margins overall under full competitive pricing (reserve margins are projected to be as much as 3 percentage points lower nationally), but a portion is also due to the flatter load pattern.

Sectoral Pricing of Electricity in Competitive Markets

The emergence of competitive markets for generation in the electricity industry has created the potential for a new distribution of costs and benefits among classes of utility customers. Traditionally, rates were set by regulators on the basis of "embedded costs"-the average cost of producing electricity and serving the customer, including both short-run costs such as fuel and long-run costs such as plant and capital recovery. Because rates

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were set to cover all costs, including return on capital invested, this was referred to as "rateof return regulation." Rates were generally set to reflect average costs rather than the more volatile fluctuations in marginal costs.

Historically, given the large transaction costs associated with real-time pricing, average cost pricing was seen as ensuring that revenues would cover total costs. Because some activities or investments, such as maintenance of a substation, serve multiple customer classes, regulators developed various methods of allocating the costs to different customer classes. Typically, both fairness and efficiency [25] played a role in setting customer class tariffs [26]. The changing nature of the electric utility industry will undoubtedly modify the pattern of allocations of costs among customer classes, with market forces having a greater role. Although all customers are expected to benefit eventually from the introduction of competition in the generation function, the rate and degree of such benefits may vary by customer class. Figure 16 shows sectoral prices of electricity in the United Kingdom during the period 19881996 when the electricity industry was privatized and competition was introduced in the generation sector-indexed to 1988 prices. Profitability in the regulated market was allowed to rise for 2 years before the introduction of competition in 1990. Savings from the introduction of competition were realized more quickly by the larger customers first.

Figure 16. Real electricity prices in the
United Kingdom after deregulation, 1988-1996
(index, 1988 = 1.0)

were referred to as non-franchise customers, and they had the choice of any of the 12 Regional Electricity Companies (RECs), or other independent generating companies. Franchise customers, primarily residential and small commercial, were required to purchase electricity through their local RECS. The franchise threshold was lowered to 100 kilowatts in 1994, and all customers were to have choice of suppliers by the end of 1998.

In general, over this time, small consumers have seen only modest price reductions. As the franchise limitations were removed, first large and then medium industrial customers received greater benefits, although there was a good deal of variation in the experience of industrial customers. Some very large industrial customers, participants in the "qualifying industrial customer scheme" (QUICS) program before privatization, initially saw price increases and have received relatively little benefit from the competitive market [27]. As shown in Figure 16, even after a transition period, it is likely that the effect of deregulation will vary by customer class.

As markets are restructured, firms have incentives to change their pricing to meet specialized demands. An example is the U.S. natural gas market for transmission services, where restructuring resulted in a wider array of options for some customers. In particular, those customers with more flexibility in their transmission and distribution requirements were in a position to reduce their overall price of service. Those users, primarily large industrial consumers, benefited most from the restructured natural gas market [28]. Figure 17 shows the transmission and distribution markup (the difference Figure 17. Index of real U.S. natural gas transmission and distribution markups by end-use sector, 1985-1996 (index, 1985 = 1.0)

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Initially only the largest customers in the United Kingdom, those with peak loads of more than 1 megawatt (approximately the size of 500 households), had a choice of suppliers. These customers

between the wellhead and end-use prices of natural gas) by sector from 1985 to 1996, indexed to 1985. As shown, the average price of transmission and distribution for industrial users declined significantly more (on a percentage basis) than that for residential users.

Traditionally, an electric utility was granted an exclusive franchise over its territory and served as a regulated monopoly. Because customers are easily identified by demand level and have different price elasticities of demand, a utility can charge different prices to different customers. In a regulated monopoly, there is no inherent requirement that prices equal long-run average costs. In order for the revenue requirements of the utility to be met, some price differentials must be established. That is, if every customer class were charged its incremental cost of service, a utility might not cover its total costs. Allocation of such costs over and above the incremental costs are decided by regulators. Such allocations, translated into rates, result in different prices per kilowatthour for different customers. Such differences are inherent in traditional rate development [29].

Given the traditional market structure of a regulated monopoly, efficiency considerations encourage the adoption of a pricing approach whereby classes of customers with inelastic demands pay a higher markup over marginal cost than those with more elastic demands [30]. However, the goal of equity leads policymakers to set prices that are seen as fair and reasonable. This goal can lead regulators to deviate from the economically optimal pricing methodology so as to avoid imposing "unreasonably" high prices on groups with inelastic demands. Thus, regulated sectoral pricing deviates from economically optimal pricing, because both equity and efficiency are important in setting rates.

Figure 18 compares actual prices of electricity by customer class in 1996 with an estimate of what such prices would look like if the costs were allocated in an economically optimal (market-based) manner. The results indicate that current industrial and commercial prices are largely higher and current residential prices are lower than the prices associated with the economically optimal solution. Significant changes may occur when there is a restructured electricity generation market. Figure 19

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compares the generation price by customer class in the full competition case, in which generation is assumed to be priced on a marginal cost basis. It is also assumed that, through the function of an independent system operator (ISO) or other market structure, the generation component of price at any one time will be equal for all customers. That is, the difference between the average yearly price of the generation component of electricity for different customer classes depends only on the fraction of annual electricity requirements purchased during high-priced periods. With these assumptions, the average annual generation prices are nearly equal for the different customer classes.

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