Report#:DOE/EIA-0554(2000)
|
Based on fuel prices and electricity demands provided by the other modules of the NEMS, the EMM determines the most economical way to supply electricity, within environmental and operational constraints. There are assumptions about the operations of the electricity sector and the costs of various options in each of the EMM submodules. The major assumptions are summarized below. Key Assumptions Capacity Types Twenty-six capacity types are presented in the EMM (Table 36). Table 36. Capacity Types Represented in the Electricity Market Module New Generating Plant Characteristics The operational characteristics of new generating technologies are the most important inputs to the electricity capacity planning submodule. The key characteristics for these technologies are summarized in Table 37. These characteristics are used, in combination with fuel price foresight from the NEMS Integrating Module, to compare resource options when new capacity is needed. Heat rates for fossil-fueled technologies decline linearly between 1995 and 2010. The assumptions for nuclear technologies are described later in this section. The overnight costs listed for each technology in Table 37 are the base costs estimated to build a plant in Middletown, U.S.A. Differences in plant costs due to regional distinctions are calculated by applying regional multipliers (Tables 38 and 39) to the cost of labor, factory equipment, and site material for each new generating technology. Table 39. Regional Multipliers for New Construction, Renewable Energy Technologies Representation of Electricity Demand The annual electricity demand projections from the NEMS demand modules are converted into load duration curves for each of the EMM regions (based on North American Electric Reliability Council regions and subregions) using historical hourly load data. However, unlike traditional load duration curves where the demands for an entire period would be ordered from highest to lowest, losing their chronological order, the load duration curves in the EMM are segmented into nine different time slices (Table 40). The time periods shown were mainly chosen to accommodate intermittent generating technologies (i.e., solar and wind facilities) and demand-side management programs. Table 40. Load Segments for the Electricity Market Module Reserve margins—the percentage of capacity required in excess of peak demand needed for unforeseeable outages—are also assumed for each regulated EMM region. A thirteen percent reserve margin is assumed for MAPP, STV and SPP, nine percent for FL, and fifteen percent for NWP. In the other regions, which are assumed to be fully or partially deregulated, the EMM determines the reserve margin by equating the marginal cost of capacity and the cost of unserved energy. Fossil Fuel-Fired Steam Plant Maintenance/Retirement Fossil-fired steam plant retirements are calculated endogenously within the model. Fossil plants are retired when it is no longer economical to continue running them. Each year, the model determines whether the market price of electricity is sufficient to support the continued operating of existing plants. If the expected revenues from these plants are not sufficient to cover the annual going forward costs - mainly fuel and operations and maintenance costs - the plant will be retired if the overall cost of producing electricity can be lowered by building new replacement capacity. Nuclear Power Plant Orders and Retirements There are no nuclear units currently under construction in the United States. New nuclear capacity will be added if the costs are competitive with other generating technologies. It is assumed that older nuclear power plants will incur aging related expenditures in the form of either increased capital costs, decreases in performance and/or increased maintenance expenditures to maintain a given level of performance. The decision to either incur the aging-related costs of the unit or retire the unit is based on the relative economics of the alternatives. In AEO2000, the retirement decision for each nuclear unit is evaluated every 10 years, starting after roughly 30 years of operation. An assumption is made regarding the capital costs required to operate an additional 10 years beyond the point of evaluation. In the reference case, the aging-related capital costs over ten years are assumed to be $150 milliion at 30 years, an additional $175 million at 40 years and $250 million at 50 years, where dollar amounts are based on an average plant size of 1,000 megawatts. The investment cost is assumed to be recovered over ten years, and an annual payment is calculated. If the combined operating costs and annual capital payment costs are lower than the cost of building new capacity, then the nuclear unit continues to operate another 10 years, until the next evaluation. Plants that have recently incurred a major retrofit are assumed not to incur aging-related expenses between 30 and 40 years and only one-third of the costs from 40 to 50 years. Additionally, the aging-related cost assumptions are adjusted downward for the newest vintage of nuclear reactors, to reflect improvements in construction and design. Interregional Electricity Trade Both firm and economy electricity transactions among utilities in different regions are represented within the EMM. In general, firm power transactions involve the trading of capacity and energy to help another region satisfy its reserve margin requirement, while economy transactions involve energy transactions motivated by the marginal generation costs of different regions. The flow of power from region to region is constrained by the existing and planned capacity limits as reported in the NERC and WSCC Summer and Winter Assessment of Reliability of Bulk Electricity Supply in North America. Known firm power contracts are obtained from NERC’s Electricity Supply and Demand Database 1998. They are locked in for the term of the contract and then phased out through 2020. In addition, in certain regions where data show an established commitment to build plants to serve another region, new plants are permitted to be built to serve the other region’s needs. This option is available to compete with other resource options. Economy transactions are determined in the dispatching submodule by comparing the marginal generating costs of adjacent regions in each time slice. If one region has less expensive generating resources available in a given time period (adjusting for transmission losses and transmission capacity limits) than another region, the regions are allowed to exchange power. International Electricity Trade Two components of international firm power trade are represented in the EMM—existing and planned transactions, and unplanned transactions. Existing and planned transactions are obtained from the North American Electric Reliability Council’s Electricity Supply and Demand Database 1998. Unplanned firm power trade is represented by competing Canadian supply with U.S. domestic supply options. Canadian supply is represented via supply curves using cost data from the Department of Energy report Northern Lights: The Economic and Practical Potential of Imported Power from Canada, (DOE/PE-0079). International economy trade is determined endogenously based on surplus energy expected to be available from Canada by region in each time slice. Canadian surplus energy is determined using Canadian electricity supply and demand projections as reported in the Canadian National Energy Board report Energy Supply and Demand 2025. Electricity Finance and Pricing The reference case assumes a transition to full competitive pricing in California, New York, the New England and Mid-Atlantic Area Council, and Texas. In addition electricity prices in the East Central Area Reliability Council, the Mid-American Interconnected Network (Illinois, plus parts of Missouri Michigan and Wisconsin), and the Rocky Mountain Power Area/ Arizona are assumed to be partially competitive. Some of the States in each of these regions have not taken action to deregulate their pricing of electricity, and in those States prices are assumed to continue to be based on traditional cost-of-service pricing. The reference case assumes that: in California, the price of electricity will remain constant between 1996 and 2001 for commercial and industrial consumers while residential customers will enjoy a 10 percent reduction in current prices starting in 1998; the market will transition from a regulated to a competitive market between 2002 and 2007; and California markets will be fully competitive by 2008. Similarly, in the other competitive regions, the transition period is assumed to occur over a ten-year period beginning in 1999 or 2000. The price of electricity to the consumer is comprised of the price of generation, transmission and distribution. Transmission and distribution are considered to remain regulated in the AEO; that is, the price of transmission and distribution is based on the average cost for each customer class. In the competitive regions, the generation component of price is based on marginal cost, which is defined as the cost of the last (or most expensive) unit dispatched. The marginal cost includes fuel, operating and maintenance, taxes, and a reliability price adjustment, which represents the value of capacity in periods of high demand. Therefore, the price of electricity in the regulated regions consists of the average cost of generation, transmission, and distribution for each customer class. The price of electricity in the five regions with a competitive generation market consists of the marginal cost of generation summed with the average costs of transmission and distribution. In recent years, the move towards competition in the electricity business has led utilities to make efforts to reduce costs to improve their market position. These cost reduction efforts are reflected in utility operating data reported to the Federal Energy Regulatory Commission (FERC) and trends evidenced there have been incorporated in the AEO2000. The key trends are discussed below:
Demand-Side Management Improvements in energy efficiency induced by rising energy prices, new appliance standards, and utility demand-side management programs are represented in the end-use demand models. Appliance choice decisions are a function of the relative costs and performance characteristics of a menu of technology options. In 1997, utilities reported spending over $1.64 billion on demand-side management programs.87 Fuel Price Expectations Capacity planning decisions in the EMM are based on a lifecycle cost analysis over a 20-year period. This requires foresight assumptions for fuel prices. Expected prices for coal, natural gas, and oil are derived using adaptive expectations, in which future prices are extrapolated from recent historical trends.88 For each projection year, coal prices are assumed to decrease one percent annually from that year’s projected price until the end of the subsequent 20 year period. For each oil product, future prices are estimated by applying a constant markup to an external forecast of world oil prices. The markups are calculated by taking the differences between the regional product prices and the world oil price for the previous forecast year. For natural gas, expected wellhead prices are based on a nonlinear function that relates the expected price to the expected cumulative domestic gas production. Delivered prices are developed by applying a constant markup, which represents the difference between the delivered and wellhead prices from the prior forecast year. The approach for natural gas was developed to have the following properties:
1. The natural gas wellhead price should be upward sloping as a function
of
2. The rate of change in wellhead prices should increase as fewer economical The approach assumes that at some point in the future a given target price, PF, results when cumulative gas production reaches a given level, QF. The target values for PF and QF were assumed to be $6.00 per thousand cubic feet (1995 dollars) and 2000 trillion cubic feet, respectively. Gas hydrates are included in the resource base. The future annual production is assumed to be constant at the prior year’s level. The expected wellhead gas price equation is of the following form: Pk = A * Qk0.75 + B where P is the wellhead price for year k, Qk is the cumulative production from 1991 to year k, and A and B are determined each year such that the price equation will intersect the future target point (PF, QF). Technological Optimism and Learning Overnight costs for each technology are calculated as a function of regional construction parameters, project contingency, and technological optimism and learning factors. For each generating technology available for new capacity in a region, the overnight cost used by the model is calculated using the base cost for the technology from Table 37 and the technological and learning parameters from Table 41. Table 41. Technological Optimism and Learning Parameters for New Generating Technologies The learning function has the nonlinear form: OC(C) = a*C-b, where C is the cumulative capacity for the technology. The progress ratio (pr) is defined by speed of learning (e.g., how much costs decline for every doubling of capacity). The reduction in capital cost for every doubling of cumulative capacity (f) is an exogenous parameter input for each technology Table 41. Consequently, the progress ratio and f are related by: pr = 2-b = (1 - f) The parameter “b” is calculated by (b =-(ln(1-f)/ln(2)). The parameter “a” can now be found from initial conditions. That is, a =OC(C0)/C0-b Where C0 is the cumulative initial capacity. Thus, once the rates of learning (f) and the cumulative capacity (C0) are known for each interval, the corresponding parameters (a and b) of the nonlinear function are known. The overnight costs (OC) computed in this manner are then adjusted to account for technological optimism. In AEO2000, capital costs for all new electricity generating technologies (fossil, nuclear, and renewable) decrease in response to foreign and domestic experience. Foreign units of new technologies are assumed to contribute to reductions in capital costs for units that are installed in the United States to the extent that (1) the technology characteristics are similar to those used in U.S. markets, (2) the design and construction firms and key personnel compete in the U.S. market, (3) the owning and operating firm competes actively in the U.S., market, and (4) there exists relatively complete information about the status of the associated facility. If the new foreign units do not satisfy one or more of these requirements, they are given a reduced weight or not included in the domestic learning effects calculation. International Learning. For AEO2000, capital costs for all new fossil-fueled electricity generating technologies decrease in response to foreign as well as domestic experience, to the extent that the new plants reflect technologies and firms also competing in the United States. AEO2000 includes 3,887 megawatts of advanced coal gasification combined cycle capacity and 15,177 megawatts of advanced combined cycle natural gas capacity to be built outside the United States after 1999 and through 2003. Legislation Clean Air Act Amendments of 1990 (CAAA90) It is assumed that electricity producers comply with the CAAA90, which mandate a limit of 9.48 million short tons of sulfur dioxide emissions by 2000 and 8.95 million tons by 2010. Utilities are assumed to comply with the limits on sulfur emissions by retrofitting units with flue gas desulfurization (FGD) equipment, transferring or purchasing sulfur emission allowances, operating high-sulfur coal units at a lower capacity utilization rate, or switching to low-sulfur fuels. The costs for FGD equipment average approximately $195 per kilowatt, in 1988 dollars, although the costs vary widely across the regions. It is also assumed that the market for trading emission allowances is allowed to operate without regulation and that the States do not further regulate the selection of coal to be used. Utilities are assumed to comply with the mandates set forth in the CAAA90 with respect to the SO2 and NOx standards. It is assumed that utilities will comply with CAAA90 and reduce their emissions of sulfur dioxide (SO2) by 10 million tons over the forecast period. Consequently, the forecast assumes that the cost associated with purchasing an SO2 allowance (dollars per ton of SO2) is equivalent to the marginal cost of compliance (dollars per ton of SO2 removed). As specified in the CAAA90, EPA has developed a two-phase NOx program, with the first set of standards for existing coal plants taking force in 1996 while the second set is to be implemented in 2000 (Table 42). Dry bottom wall-fired, and tangential fired boilers, the most common boiler types, referred to as Group 1 Boilers, were required to make significant reductions beginning in 1996 and further reductions in 2000. Relative to their uncontrolled emission rates, which range roughly between 0.6 and 1.0 pounds per million Btu, they are required to make reductions of between 25 and 50 percent to meet the Phase I limits and further reductions to meet their Phase II limits. The EPA did not impose limits on existing oil and gas plants, but some states have Nox regulations. All new fossil units are required to meet standards. In pounds per million Btu, these limits are 0.11 for conventional coal, 0.02 for advanced coal, 0.02 for combined cycle, and 0.08 for combusion turbines. All of these Nox limits are incorporated in the NEMS. Table 42. NO2 Emissions Standards Energy Policy Act of 1992 (EPACT) The provisions of the EPACT include revised licensing procedures for nuclear plants and the creation of exempt wholesale generators (EWGs). EPACT allows the issuance of a combined construction and operating license for nuclear plants; however, it also allows for a post-construction hearing and judicial review. The uncertainty associated with waste, regulatory, and financial issues is sufficiently large to require their resolution or some manner of financial protection for investors before investments in nuclear power would take place. Unresolved, these conditions would lead to investments in alternative capacity additions or a delay in capital investment. Therefore, no newly ordered nuclear plants are assumed to become operational by 2020. EPACT reformed the Public Utility Holding Company Act of 1935 (PUHCA). Prior to the passage of EPACT, PUHCA required that utility holding companies register with the Securities and Exchange Commission (SEC) and restricted their business activities and corporate structures.89
Entities that wished to develop facilities in several States were regulated
under PUHCA. To avoid the stringent SEC regulation, nonutilities had to
limit their development to a single State or limit their ownership share
of projects to less than 10 percent. EPACT changed this by creating a class
of generators that, under certain conditions, are exempt from PUHCA restrictions.
These EWGs can be affiliated with an existing utility (affiliated power
producers) or independently owned (independent power producers). In general,
subject to State commission approval, these facilities are free to sell
their generation to any electric utility, but they cannot sell to a retail
consumer. These EWGs are represented in NEMS. Climate Change Action Plan As a result of the Climate Challenge Program (CCAP) many utilities have announced efforts to voluntarily reduce their greenhouse gas emissions between now and 2000. These efforts cover a wide variety of programs including increasing DSM investments, repowering (fuel-switching) of fossil plants, restarting of nuclear plants that have been out-of-service, planting trees, and purchasing emission offsets from international sources. To the degree possible, each one of the participation agreements was examined to determine if the commitments made were addressed in the normal reference case assumptions or whether they were addressable in NEMS. Programs like tree planting and emission offset purchasing are not addressable in NEMS. With regard to the other programs, they are, for the most part, captured in NEMS. For example, utilities annually report to EIA their plans (over the next 5 years) to bring a plant back on line, repower a plant, life extend a plant, cancel a previously planned plant, build a new plant, or switch fuel at a plant. Additionally, reduced transmission losses due to improved transformer efficiencies are incorporated. These data are inputs to NEMS. Thus, programs that would affect these areas are reflected in NEMS input data. However, because many of the agreements do not identify the specific plants where action is planned, it is not possible to determine which of the specified actions, together with their greenhouse gas emission savings, should be attributed to the Climate Challenge Program and which are just the result of normal business operations. FERC Orders 888 and 889 FERC has issued two related rules (Orders 888 and 889) designed to bring low cost power to consumers through competition, ensure continued reliability in the industry, and provide for open an equitable transmission services by owners of these facilities. Specifically, Order 888 requires open access to the transmission grid currently owned and operated by utilities. The transmission owners must file nondiscriminatory tariffs that offer other suppliers the same services that the owners provide for themselves. Order 888 also allows these utilities to recover stranded costs (investments in generating assets that are unrecoverable due to consumers selecting another supplier). Order 889 requires utilities to implement standards of conduct and a Open Access Same-time Information System (OASIS) through which utilities and non-utilities can receive information regarding the transmission system. Consequently, utilities are expected to functionally or physically unbundle their marketing functions from their transmission functions.
These orders are represented in the EMM by assuming that the debt/equity
financing structure for new technologies is the same for utilities and
nonutilities. Electricity and Renewable Technology Cases High Electricity Demand Case The high electricity demand case assumes that electricity demand grows at 2.0 percent annually between 1998 and 2020. In the reference case, electricity demand is projected to grow 1.4 percent annually between 1998 and 2020. No attempt was made to determine the changes needed in the end-use sectors to result in the stronger demand growth. The high electricity demand case is a partially integrated run. The end-use demand modules are not operated, but all of the electricity end-use demands from the reference case are multiplied by the same factor to achieve the higher growth rate. Using the higher electricity demand and all other reference case demand projections as inputs, the EMM, Macroeconomic Activity, Petroleum Marketing, International Energy, Oil and Gas, Natural Gas Transmission and Distribution, Coal Market, and Renewable Fuels Modules are allowed to interact. Low and High Fossil Cases The low fossil case assumes that the costs of advanced generating technologies (integrated coal-gasification combined-cycle, advanced natural gas combined-cycle and turbines, and fuel cells) will remain at the base cost during the projection period. Capital costs of conventional generating technologies are the same as those assumed in the reference case (Table 43). In the high fossil case, efficiencies of advanced fossil generating technologies are higher than the reference case, based on discussions with the Department of Energy, Office of Fossil Energy, while efficiencies of conventional technologies are the same as used in the reference case. The low and high fossil runs are partially-integrated runs, i.e., the Macroeconomic Activity, Petroleum Market, International Energy, and end-use demand modules use the reference case values and are not effected by changes in generating capacity mix. Conversely, the Oil and Gas Supply, Natural Gas Transmission and Distribution, Coal Market, and Renewable Fuels Modules are allowed to interact with the EMM in the low and high fossil cases. Low and High Nuclear Cases Two side cases were developed with different assumptions regarding the capital investments, which change the retirement decisions. In the low nuclear case the capital investment is increased by $50 million at each decisions point. In addition, the adjustments for the new plants were removed, making these units face higher capital investments. The high nuclear case assumes that no additional investment is needed during the first 40 years of operation, and that capital expenditures are reduced by $100 to $125 million after 40 years. The low and high nuclear cases are partially-integrated model runs, i.e., the Macroeconomic Activity, Petroleum Market, and International Energy modules use the reference case outputs and are not affected by changes in nuclear capacity. Conversely, the Oil and Gas Supply, Natural Gas Transmission and Distribution, Coal Market, and Renewable Fuels Modules interact with the EMM in the high and low nuclear cases. High Renewables Case For the high renewables case, EIA incorporates approximations of renewable energy technology characterizations prepared jointly by the U.S. Department of Energy and the Electric Power Research Institute, technology assumptions of lower capital and operating costs, and higher efficiencies (capacity factors) for new renewable energy generating technologies than used in the reference case.90 EIA also assumed that the yields for energy crops grown on pasture and crop land are nearly 20 percent higher than in the reference case. All other technologies and other NEMS modeling characteristics remain unchanged from the reference case (Table 44). Renewable Portfolio Standard Case Three different cases involving minimum requirements for nonhydroelectric renewable generation are represented. Each case uses the requirement of 7.5 percent of electricity sales by 2010, as specified in the Administration’s proposed Comprehensive Electricity Competition Act. The RPS with cap and sunset case includes a 1.5 cents per kilowatthour cap on the renewable credit price. That is, suppliers can purchase credits rather than generate electricity from renewables if the market price for credits exceeds this cap. It also contains a sunsetting provision, in which the required share is held constant through 2015 and then expires thereafter. The RPS with cap, no sunset case incorporates the price cap, but removes the sunsetting provision. RPS no cap, no sunset case contains neither the cap or sunset options and therefore requires that the standard be achieved through 2020. Competitive Pricing Cases There are three competitive pricing cases that differ in their assumptions on natural gas supply technology development. The mid-price gas case uses the reference case assumptions on natural supply technology. The competitive pricing case with low gas prices incorporates the oil and natural gas supply technology assumptions from the oil and gas rapid technology case. Similarly, the competitive pricing case with high gas prices incorporates the oil and natural gas supply technology assumptions from the oil and gas slow technology case. Each competitive pricing case assumes that all regions of the country will gradually move toward marginal-cost-based pricing for generation services. Competitive pricing for generation services is phased in over 10 years by computing a weighted average of the traditional average-cost-based price and a price based on marginal costs. The weighting factor changes over time—initially weighting the average-cost-based price more heavily, then decreasing the weight over the phase-in period—until the price is based solely on marginal costs. Prices in two regions, NWP and STV, are weighted to reflect the assumption that public power would still be priced at average costs. It is also assumed that some consumers will be able to respond to time-of-use pricing by altering their demand patterns. Through “load shifting”, consumer can reduce usage during a peak period, when prices are high and supply is tight, and shift that usage to an off-peak period. |
