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Pricing of Electricity Generation Services
Recovery of Stranded Costs
Renewable Power Incentives
Power Plant Operating Cost and Performance Improvements
Other Cost Improvements
Energy Efficiency and Distributed Power (Cogeneration)
Cost of Capital
Retirement of Existing Plants
Wholesale Transmission Pricing
Reserve Margins
Generation Sector Taxes
Other Differences From the Annual Energy Outlook 1999 Assumptions

The purpose of this study is to compare NEMS results to those produced by POEMS when both modeling systems use the assumptions outlined in the Supporting Analysis. As in the Supporting Analysis, two cases have been prepared. The first, referred to as the CECA Reference case, represents an electricity market that is fully regulated. The second, referred to as the CECA Competitive case, represents an electricity market in which the generation service sector of the industry is fully competitive.

This analysis used the version of NEMS used for EIA's Annual Energy Outlook 1999 (AEO99),⁽⁵⁾ with the exception of modeling changes and minor data updates in portions of the electricity module. Enhancements to the NEMS electricity module that have been made since AEO99 are discussed in Appendix D. All of the assumption and modeling changes (other than the new dispatching algorithm described in Appendix D) to the AEO99 were made to incorporate the assumptions for the CECA Reference and CECA Competitive cases documented in the Supporting Analysis, or provided to EIA by the DOE Office of Policy (see Appendix E). Where the structure of the NEMS and POEMS electricity modules differ, assumptions were incorporated to obtain a similar impact within the NEMS framework.⁽⁶⁾ The key changes from the assumptions used in the AEO99 fall into the following areas.⁽⁷⁾

In the CECA Reference case it is assumed that all electricity services will continue to be provided as a single commodity--i.e., bundled service that includes transmission, distribution, and generation services. Consumers will continue to purchase electricity from their current electric utilities, and electricity prices will continue to be based on the average cost of service. Because some States have already moved to competitive electricity pricing, this case does not represent the current situation in all parts of the country. It more closely represents the pricing of electricity up to the mid-1990s.

In the CECA Competitive case it is assumed that the major electricity services--transmission, distribution, and generation--will be unbundled and priced separately. Transmission and distribution service prices will continue to be based on the average cost of service, including the recovery of investments in new equipment to serve customers. Prices for generation services are assumed to be set competitively, based on marginal costs. In other words, the price of power is assumed to be based on the variable operating costs (what economists refer to as marginal costs) of the last plant used to meet demand during a given time period. This means that consumers will pay their local utilities to deliver the power to them, but they will be able shop around for a power supplier of their choice. Competitive generation pricing is assumed to begin in 2000 in the CECA Competitive case with a transition period to allow for the recovery of stranded costs. The differences in the algorithms used by NEMS and POEMS for estimating competitive prices are discussed in the following chapter.

One exception to competitive pricing of generation in the CECA Competitive case is power from Federal and State utilities. The Supporting Analysis assumed that without changes in current rules and regulations this power would continue to be priced on the basis of average cost of service. To simulate this in regions with a significant amount of Federal and State electricity generation, the price is calculated as the weighted average of the average cost-of-service price and the competitive price. The weights are the percentage of regional generation from State and Federal facilities.

In the CECA Reference case, which assumes full cost-of-service regulation, electricity suppliers are assumed to recover all the costs associated with the production and delivery of electricity to their customers. The movement to competitive generation markets in the CECA Competitive case could reduce prices such that some investments that were previously made to serve customers' demand for electricity would no longer be recoverable under the conditions of a competitive market. When this occurs, these costs, referred to as stranded costs, are assumed to be recovered, as they were in the Supporting Analysis, through a nonbypassable "wires charge" (a surcharge on transmission and distribution services) over a 10-year period.⁽⁸⁾ In other words, a fee is added to each kilowatthour of power sold to recover these costs over 10 years. This fee is similar to the competitive transition fee now included in Pennsylvania electricity prices.

The treatment of negative stranded costs (which occur for utilities whose average costs are below the competitive power prices) varies by utility type. Essentially it is assumed that utilities and their customers will negotiate the allocation of negative stranded costs between ratepayers and shareholders. In the case of municipal and cooperative utilities, negative stranded costs are assumed to be returned to the customers who own those utilities. For investor-owned utilities it is assumed that 25 percent of the surplus is returned to customers. Because NEMS treats each region as a single utility, it does not have sufficient accounting detail to break out utilities which might have negative stranded costs, nor is it able to identify stranded costs associated with regulatory assets and nuclear decommissioning costs. In the Supporting Analysis, regulatory asset and nuclear decommissioning costs are assumed to continue to be recovered as they have been in a regulated environment. As a result, the values for stranded costs from the POEMS Supporting Analysis were input to NEMS in the CECA Competitive case.

In the CECA Competitive case, new renewable power plants (excluding hydroelectric plants and fossil-derived municipal solid waste facilities⁽⁹⁾ are eligible to receive two types of incentives. All new wind and biomass plants brought on between 2000 and 2015 receive a 1.5 cent per kilowatthour production tax credit for all the power they produce during the first 10 years of their operation.⁽¹⁰⁾ In addition, a 1.0 cent per kilowatthour production tax credit is provided for electricity produced from coal plants using biomass between 2000 and 2015. In the case of co-firing, it is assumed that coal plants can use up to 5 percent biomass fuel without investments to upgrade the plant.

The 5-percent maximum share is phased in between 2000 and 2005 to allow time for the industry to adjust to meet the increased demand for biomass co-firing. It could take several years for the biomass residue supply industry to meet the growing demand. The 5-percent maximum share is higher than the 2.66-percent maximum share used in EIA's analysis of the Climate Change Technology Initiative (CCTI).⁽¹¹⁾ The share used in the CCTI analysis was limited because the high costs of biomass transportation made it unreasonable to expect it to be transported across State lines or to attempt to collect crop residues for co-firing in coal plants. However, the renewable incentives included in CECA are considered likely to extend the economic range for transporting biomass.

In addition, the CECA Competitive case includes a renewable portfolio standard (RPS) requiring that 7.5 percent of total electricity sales be generated by renewable power plants by 2010. Under this provision, retail electricity sellers would have to hold 7.5 credits for each 100 kilowatthours of electricity sold. Credits would be issued to the facilities generating qualifying renewable power. The credits could be held for future use or sold to retail electricity sellers so that they can meet the RPS requirement. The maximum premium for renewable credits is limited under CECA to 1.5 cents per kilowatthour. To limit the cost of the RPS, the government will sell credits at the 1.5-cent price if they are not available in the market for less. If this occurs the required 7.5-percent nonhydroelectric renewable share will not be achieved.

To parallel the assumptions used in the Supporting Analysis, 0.3 cents per kilowatthour was added to the cap to represent the success of green power programs anticipated in that analysis.⁽¹²⁾ In addition, the supply curves for wind were modified to reduce the cost impact of a rapid buildup in manufacturing of wind capacity (reduction in short-term supply elasticities), which would no longer be reasonable in a case that assumes an RPS.⁽¹³⁾ In the AEO99, it was assumed that the cost of new wind plants would increase if the amount of capacity built in any year exceeded 20 percent of existing capacity. Costs were assumed to increase by 1 percent for each percent built beyond the 20-percent threshold in a single year. In the CECA Competitive case the threshold was raised to 25 percent, and the rate of increase in price for each percent increase in capacity over 25 percent was lowered to 0.5 percent.

In the CECA Competitive case, market competition is assumed to lower nonfuel O&M costs for existing plants over the 1998 to 2010 period. Each existing plant's nonfuel O&M costs are assumed to approach the costs of the best quartile of similar plants over time. Using the Supporting Analysis assumptions, the level of improvement varies from 50 to 75 percent (depending on the technology type⁽¹⁴⁾ of the difference between a plant's current costs and the costs of the top quartile of comparable plants. The Supporting Analysis estimated that these assumptions result in 17 percent lower nonfuel O&M costs per kilowatthour generated in the Competitive case than in the Reference case in 2010. The nonfuel O&M cost assumptions used for new plants are also improved from those used in the AEO99. Beginning in 2000, as was done in the Supporting Analysis, the nonfuel O&M costs of new plants are assumed to equal the targets for existing plants of similar types.

The CECA Competitive case also assumes improvements in transmission and distribution service costs, whereas the CECA Reference case assumes no improvement in those costs. As rates are unbundled in the competitive market, regulators are expected to motivate efficiency improvements in the transmission and distribution sectors through the use of incentive-based rate mechanisms--often referred to as performance-based rates. In addition, some portions of the regulated transmission and distribution sectors, such as billing and metering services and transmission line maintenance, may be competitively outsourced. In the CECA Competitive case the total costs for transmission services are assumed to decline by 0.75 percent annually between 2000 and 2010, while the costs of distribution services decline by 1.5 percent annually over the same period. In the CECA Reference case, overhead costs--often referred to as general and administrative (G&A) costs--are assumed to decline by 1 percent annually in real terms between 2000 and 2010. In the CECA Competitive case, the rate of improvement in G&A costs is assumed to be 5 percent annually.⁽¹⁶⁾

Two changes were made in the CECA Competitive case to represent CECA provisions designed to encourage energy efficiency and promote the development of distributed generation (generation that is located at or near customer sites). To support the goal of increased energy efficiency, the CECA calls for the collection of $3 billion per year for use in a Federal public benefits fund (PBF). This amounts to a fee of approximately 0.1 cent per kilowatthour or about 1.5 percent of the current average price of electricity. The Supporting Analysis estimated that, at the national level, the demand for electricity would be reduced by approximately 150 billion kilowatthours by 2010 (165 billion kilowatthours by 2015) because of energy efficiency investments funded by the Federal PBF and the development of integrated energy service companies. The CECA limits the combination of the PBF and any funds collected from the sale of renewable credits to $3 billion per year.

The riskiness of investments in new generating assets is expected to increase as the market becomes more competitive. Historically the recovery of funds expended to build new power plants was generally assured once the capacity expansion plan was approved by the appropriate regulatory body. In competitive markets there is no such assurance. Changing conditions can force a company to abandon (or write down) a formerly profitable investment at any time. As a result, investors in new power plants will require a higher rate of return than has historically been required in the electricity business. To represent this, the CECA Competitive case incorporates a higher cost of capital than used in the CECA Reference case. The CECA Reference case incorporates a weighted cost of capital of 10.8 percent, while the CECA Competitive case uses a rate of 12.0 percent.

In both the CECA Reference and Competitive cases, plants are assumed to be retired if they are no longer economical to maintain and operate. In other words, once a plant is no longer profitable it is retired. The only exception to this rule is in the treatment of nuclear plants in the CECA Reference case. In this case, the Supporting Analysis assumed that nuclear plants would not be retired unless their operating costs exceed the revenues they receive by 7 percent. This differs slightly from the approach used in the AEO99. In the AEO99, because it was assumed that power plant operators would not make retirement decisions when losses were very small, a 10-percent loss hurdle was incorporated. This was done to represent utilities' resistance to building new capacity when existing capacity was already available--a motivation that should weaken as competitive pressures grow. In addition, because there is considerable uncertainty about future demand and fuel prices, a plant that is unprofitable in one period could turn out to be very profitable in another.

In the Supporting Analysis, wholesale transmission rates were assumed to be a percentage of the FERC Order 888 pro forma tariffs (80 percent of the rates in the Reference case and 50 percent in the Competitive case). The reduction in rates assumed in the Supporting Analysis reflects action by transmission owners to discount rates in order to attract more volume. In addition, the Competitive case assumes that transmission charges are zonal rates within Regional Transmission Groups, in contrast to "pancaked" rates (separate rates for each utility system entered) in the Reference case. In both cases, transmission owners recover their full cost of service through a combination of native load and wholesale revenues. NEMS represents the economics of interregional wholesale transactions very differently from POEMS. As a result, it was not possible to directly represent the assumptions from the Supporting Analysis. To simulate this effect in the CECA Competitive case, the hurdle rate used for interregional wholesale trades in NEMS was reduced by 50 percent from the value used in the CECA Reference case.

In the Supporting Analysis, reserve margins were held constant at 8 percent (4 percent in Florida) in both the CECA Reference and Competitive cases as a surrogate for equivalent reliability. In NEMS, reserve margins under competition are endogenously determined by balancing the cost of new capacity against consumers' willingness to pay to avoid outages. In each region, NEMS uses the demand profile, the size and operating characteristics of available capacity, and an assumption about the value consumers would be willing to pay to avoid losing power (the value of unserved energy) to determine the appropriate reserve margin. For this analysis, it was assumed that the same level of reliability would be maintained in both cases. However, because the performance of existing plants was assumed to improve in the CECA Competitive case (plants are assumed to be out of service for fewer hours), the amount of reserve capacity needed to maintain the same level of reliability is slightly lower. Nationally, the resultant NEMS reserve margins in the CECA Competitive case average near the 8 percent used in the Supporting Analysis, but they vary from region to region.

The NEMS CECA Competitive case follows the standard competitive market logic that income taxes are not included in the competitive generation price, since maximization of profits prior to the application of income taxes also maximizes profits net of those taxes. Similarly, property taxes, like other fixed annual expenses, are also not included in the estimation of the competitive generation price, although they do enter into decisions affecting unit retirement. On the other hand, taxes that are proportional to the value of generation--gross receipts or sales taxes--are reflected in competitive market prices. The Competitive case in the Supporting Analysis did not include an estimate for this latter category in its bid price. In the NEMS CECA Competitive case, FERC Form 1 data were used to estimate regional sales tax rates, which are included in the price of electricity delivered to customers.

Table 1. Summary of Assumptions for NEMS Implementation of the CECA Reference and Competitive Cases