Report#:DOE/EIA-0554(99)
Introduction
Transportation
Demand
Electricity Market
Oil
and Gas Supply
Natural Gas Transmission & Distribution
Petroleum Market
Coal Market
Renewable Fuels
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The NEMS Electricity Market Module (EMM) represents the planning, operations, and pricing of electricity in the United States. It is composed of four primary submodules—electricity capacity planning, electricity fuel dispatching, load and demand-side management, and electricity finance and pricing. In addition, nonutility generation and supply and electricity transmission and trade are represented in the planning and dispatching submodules.
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 38. Regional Multipliers for New Construction, Fossil-Fueled and Nuclear Generating TechnologiesTable 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.
Reserve margins—the percentage of capacity required in excess of peak demand needed for unforeseeable outages—are also assumed for each EMM region. Fifteen percent reserve margins are assumed for NWP and NY, fourteen percent for CNV and RA, and thirteen percent for ECAR, ERCOT, MAAC, MAIN, MAPP, SPP and STV, eight percent for NE, and four percent for FL.
Table 40. Load Segments for the Electricity Market Module
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 revenue from these plants is not sufficient to cover the going forward costs - mainly fuel and operations and maintenance costs - the plant will be retired.
Nuclear Power Plant Orders and Retirements
There are no nuclear units currently under construction in the United States, and the AEO99 does not assume any new units become operational in the forecast period.
It is assumed that nuclear power plants will operate until some major capital expenditure is required to repair the effects of aging. The decision to either incur the costs of repairing the unit or retire the unit is based on the relative economics of the alternatives. In the reference case, it is first assumed that a retrofit costing $150 per kilowatt will be required after 30 years of operation to operate the plant for another 10 years. Plants that have already incurred a major expenditure (such as a steam generator replacement) are assumed not to need additional retrofits and to run for 40 years. For other units, the capital investment is assumed to be recovered over 10 years, and an annual payment is calculated. If the combined operating costs and capital payment costs are cheaper than building new capacity, then the plant is run through its license period. If it is not economical, the plant is retired at 30 years.
It is also assumed that nuclear licenses will be renewed at the end of 40 years, if it is economical to continue running the plant. A more extensive capital investment ($250 per kilowatt) is assumed to be required to operate a nuclear unit for 20 years past its current license expiration date. If this investment, recovered after 20 years, is less expensive than building new capacity, the unit is assumed to continue operating. Otherwise, it will be retired when it reaches the expiration date on its license. For both of these investment decisions, adjustments are made for new units to capture the improvements in their designs compared with older units.
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 on the April 1995, Coordinated Bulk Power Supply Program Report, (DOE Form OE-411). Known firm power contracts are locked in for the term of the contract. 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. The price for the economy transactions is assumed to be set by splitting the difference between the exporting and importing region’s marginal generation costs.
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 regional publications of the Coordinated Bulk Power Supply Program Report, (DOE Form OE-411). 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 1993-2010.
Electricity Finance and Pricing
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, plus parts of Missouri and Wisconsin). Although other states such as Oklahoma, Wisconsin, and Montana have decided to allow consumers to choose their electricity suppliers, the regional configuration of these suppliers assumed in the reference case prevents representation of competitive markets in the regions in which these states are located. Nevertheless, 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 from 1998 through 2007 with full competitive pricing of electricity beginning in 2008.
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 AEO99. The key trends are discussed below:
- Reduced General and Administrative Expenses (G&A) - Over the 1990 through 1994 period, utilities have reduced their employment by 65,000, a reduction of nearly 3 percent annually. This trend has been incorporated by reducing G&A expenditures at a rate of 2.5 percent annually over the next 10 years.
- Reduced Fossil Plant Operations Expenditures (O&M) - Again, over the 1990 through 1994 period, utility fossil plant operation and maintenance costs (all operating costs other than fuel) fell at a rate of nearly 3 percent annually. As with G&A, this trend has been incorporated by reducing fossil O&M expenditures at a rate of 2.5 percent annually over the next 10 years.
- Reduced Nuclear Operations and Maintenance Expenditures - In the AEO99 nuclear O&M expenditures are reduced over time to reflect the impact of older more expensive plants retiring in the later years of the forecast. In 2020 nuclear capacity is 50 gigawatts below the 1997 level and nuclear O&M expenditures are reduced 5 percent to reflect this.
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 1996, utilities reported spending over $1.90 billion on demand-side management programs. These expenditures are expected to decrease slightly to over $1.81 billion by the year 2001.63
Fuel Price Expectations
Capacity planning decisions for the electric power industry are based on a lifecycle cost analysis over a 30-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.64 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 30 year period or until the cumulative decrease based on the annual one percent reduction equals or exceeds 0.75. If the cumulative increase equals or exceeds 0.75 then coal prices are assumed to remain constant from that year to the end of the 30 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 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 cumulative gas production.
2. The rate of change in wellhead prices should increase as fewer economical reserves remain to be discovered and produced.
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, Q 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 Factors
Overnight costs are calculated for each new generating technology by applying the regional cost multipliers from Table 38 to the base overnight cost in Table 37. For advanced generating technologies these costs are assumed to be fifth-of-a-kind costs ( the overnight cost for the fifth unit constructed). Technological optimism factors (Table 41) are applied to the first-of-a-kind unit (the first unit constructed of that technology) and decrease linearly until the fifth unit is constructed. In addition, overnight costs for advanced generating technologies other than wind decrease by 10 percent for each doubling of capacity for the first through the fifth unit, decrease by 5 percent for each doubling of capacity for the sixth through the fortieth unit, and decrease by 2.5 percent for each doubling of capacity past the forty-first unit. The cost of unit technologies decrease by 8 percent for each doubling of capacity from the first to the fifth unit and decrease by 5 percent fo each doubling, thereafter. In the case of conventional generating technologies, no technological optimism factors are applied. Construction costs as computed from the regional multipliers and the base overnight costs are assumed to be the cost per kilowatt for the first forty units constructed. Costs then decrease by 2.5 percent for each doubling of capacity for past forty units.
Table 41. Technological Optimism and Learning Factors for New Generating Technologies
In AEO99, 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 reduce weight or not included in the learning effects calculation.
International learning effects this year include 1,553 megawatts advanced coal (gasification), 2,330 megawatts advanced combined cycle, 360 megawatts advanced combustion turbine, 110 megawatts geothermal, 1,250 megawatts wind, 115 megawatts grid-connected photovoltaics, and 57 megawatts biomass integrated combined cycle capacity in operation, under construction, or under contract for construction outside the United States. Table 66 shows identified offshore units contributing to U.S. learning in AEO99.
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 $144 per kilowatt, in 1987 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 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. Both Phase I and Phase II NOx limits are incorporated in the NEMS.
Table 42. NOx Emissions Standards (Pounds per million Btu)
Ozone Transport Rule
Powerplant operators are assumed to comply with the Ozone Transport Rule (OTR) issued on September 24, 1998. The OTR sets summer season (May through September) nitrogen dioxide (NO2) emission caps for 22 midwestern and eastern states beginning in 2003. The model evaluates the economical options available for meeting the caps. It is assumed that, the states will set up a region wide cap and trade program, rather than attempting to meet their individual caps. The compliance technologies available include various combustion controls, selective noncatalytic reduction, and selective catalytic reduction.
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.65 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 10 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 1996 and 2020, and 1.8 percent between 1990 and 1997. In the reference case, electricity demand is projected to grow 1.4 percent annually between 1997 and 2020. No attempt was made to determine the changes necessary in the end-use sectors needed to result in the stronger demand growth.
The high electricity demand case is a partially integrated run, i.e., the Macroeconomic Activity, Petroleum Marketing, International Energy, and end-use demand modules use the reference case values and are not affected by the higher electricity demand growth. Conversely, the Oil and Gas, Natural Gas Transmission and Distribution, Coal Market, and Renewable Fuels Modules are allowed to interact with the EMM in the high electricity demand case. AEO99 also analyzed an integrated high technology case (consumption high technology), which combines the high technology cases of the four end-use demand sectors and the electricity high fossil technology case.
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 first-of-a-kind 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
The low and high nuclear cases were developed with different assumptions regarding the capital investments at the 30 and 40 year decision points, which changes the retirement decisions. In the low nuclear case, the cost reduction adjustments for the new plants were removed, making these units face higher capital investments. The high nuclear case assumes that there are no aging effects and, therefore, no capital expenditures required during the current license life or for license renewal.
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.66 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. Further, for the high renewables case, EIA assumes that additional capacity effects of State RPS programs included in the reference case will extend beyond 2010, by 2020 adding 97 megawatts of additional generating capacity. All other technologies and other NEMS modeling characteristics remain unchanged from the reference case (Table 44).
Table 44. Cost and Performance Characteristics for Renewable Generating Technologies: Two Cases
Renewable Portfolio Standard Case
A case was run in which a minimum level of nonhydroelectric renewable generation was required. In this case, the minimum percentage of renewable generation (defined as generation from wind, biomass, geothermal, solar thermal, photovoltaic, and landfill gases divided by total sales and multiplied by 100) increased from 2 percent to 5.5 percent over the period 2000 through 2020 inclusive. This was a fully integrated run, in which all the modules were used. As in the reference case, New York, California, New England, the Middle Atlantic, and MAIN (Illinois-Wisconsin-Michigan) use marginal-cost-based pricing for electricity generation, while other regions are assumed to use the average cost methodology for electricity prices.
Competitive Pricing Cases
The competitive pricing case assumes that all regions of the country will gradually move toward marginal-cost-based pricing for generation services. Prices for transmission and distribution services are assumed to continue to be based on average costs. Competitive pricing for generation services is phased in over 10 years (1998-2007) 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. Other than the pricing methodology, all other assumptions in the competitive pricing case are the same as those in the reference case.
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.
