Home > Forecasts & Analyses > The National Energy Modeling System: An Overview > Electricity Market Module

The National Energy Modeling System: An Overview
  Full Printer-Friendly VersionPDF GIF


Find on this page:

Electricity Market Module

bullet gif  Electricity Capacity Planning Submodule
bullet gif  Electricity Fuel Dispatch Submodule
bullet gif  Electricity Finance and Pricing Submodule
bullet gif  Electricity Load and Demand Submodule
bullet gif  Emissions

Chapters in this Report:

Introduction/Overview of NEMS
Carbon Dioxide Emissions
Modules:
  Macroeconomic
  International Energy
  Residential Demand
  Commercial Demand

  Industrial Demand
  Transportation Demand

  Electricity Market
  Renewable Fuels
  Oil and Gas Supply
  Natural Gas Transmission & Distribution
  Petroleum Market Module

  Coal Market Module
Electricity Market Module    

The electricity market module (EMM) represents the generation, transmission, and pricing of electricity, subject to: delivered prices for coal, petroleum products, and natural gas; the cost of centralized generation from renewable fuels; macroeconomic variables for costs of capital and domestic investment; and electricity load shapes and demand. The submodules consist of capacity planning, fuel dispatching, finance and pricing, and load and demand (Figure 9). In addition, nonutility supply and electricity trade are represented in the fuel dispatching and capacity planning submodules. Nonutility  generation  from CHP and other facilities whose primary business is not electricity generation is represented in the demand and fuel supply modules. All other nonutility generation is represented in the EMM. The generation of electricity is accounted for in 15 supply regions (Figure 10), and fuel consumption is allocated to the 9 Census divisions. 

The EMM determines airborne emissions produced by the generation of electricity. It represents limits for sulfur dioxide and nitrogen oxides specified in the Clean Air Act Amendments of 1990 (CAAA90) and the Clean Air Interstate Rule.  The AEO2009 also models State-level regulations implementing mercury standards. The EMM also has the ability to track and limit emissions of carbon dioxide, and the AEO2009 includes the regional carbon restrictions of the Regional Greenhouse Gas Initiative (RGGI). 

Operating (dispatch) decisions are provided by the cost-minimizing mix of fuel and variable operating and maintenance (O&M) costs, subject to environmental costs. Capacity expansion is determined by the least-cost mix of all costs, including capital, O&M, and fuel. Electricity demand is represented by load curves, which vary by region and season. The solution to the submodules of EMM is simultaneous in that, directly or indirectly, the solution for each submodule depends on the solution to every other submodule.  A solution sequence through the submodules can be viewed as follows: 

  • The  electricity load  and  demand submodule processes electricity demand to construct load curves 
  • The electricity capacity planning submodule projects the construction of new utility and nonutility  plants,  the  level  of  firm  power trades,  and  the  addition  of  equipment  for environmental compliance 
  • The  electricity  fuel  dispatch  submodule dispatches  the  available  generating  units, both utility and nonutility, allowing surplus capacity in select regions to be dispatched to meet another regions needs (economy trade) 
  • The electricity finance and pricing submodule calculates total revenue requirements for each operation and computes average and marginal-cost based electricity prices.

Table describing EMM Outputs.  Need help, contact the National Energy Information Center at 202-586-8800.
 
Figure 9. Electricity Market Module Structure.  Need help, contact the National Energy Information Center at 202-586-8800.
Click for a larger version

Figure 10. Electricity Market Module Supply Regions.  Need help, contact the National Energy Information Center at 202-586-8800.
Click for a larger version
Electricity Capacity Planning Submodule   back to top

The electricity capacity planning (ECP) submodule determines how best to meet expected growth in electricity demand, given available resources, expected  load shapes,  expected  demands  and  fuel prices, environmental constraints, and costs for utility and nonutility technologies. When new capacity is required to meet growth in electricity demand, the technology chosen is determined by the timing of the demand increase, the expected utilization of the new capacity, the operating efficiencies, and the construction and operating costs of available technologies. 

The expected utilization of the capacity is important in the decision-making process. A technology with relatively high capital costs but comparatively low operating costs (primarily fuel costs) may be the appropriate choice if the capacity is expected to operate continuously (base load). However, a plant type with high operating costs but low capital costs may be the most economical selection to serve the peak load (i.e., the highest demands on the system), which occurs infrequently.  Intermediate or cycling load occupies a middle ground between base and peak load and is best served by plants that are cheaper to build than baseload plants and cheaper to operate than peak load plants. 

Technologies are compared on the basis of total capital and operating costs incurred over a 20-year period. As new technologies become available, they are competed against conventional plant types. Fossil-fuel, nuclear, and renewable central-station generating technologies are represented, as listed in Table 11 below.  The EMM also considers two distributed generation technologies -baseload and peak.  The EMM also has the ability to model a demand storage technology to represent load shifting. 

Uncertainty about investment costs for new technologies is captured in ECP using technological optimism and learning factors. The technological optimism factor reflects the inherent tendency to underestimate costs for new technologies. The degree of technological optimism depends on the complexity of the engineering design and the stage of development. As development proceeds and more data become available, cost estimates become more accurate and the technological optimism factor declines. 

Learning  factors  represent  reductions  in  capital costs due to learning-by-doing. For new technologies, cost reductions due to learning also account for international experience in building generating capacity. These factors are calculated for each of the major design components are identified only if the component is shared between multiple plant types, so that the ECP can reflect the learning that occurs across technologies. The cost adjustment factors are based on the cumulative capacity of a given component. A 3-step learning curve is utilized for all design components. 

Typically, the greatest amount of learning occurs during the initial stages of development and the rate of cost reductions declines as commercialization progresses. Each step of the curve is characterized by the learning rate and the number of doublings of capacity in which this rate is applied. Depending on the stage of development for a particular component, some of the learning may already be incorporated in the initial cost estimate. 

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 United States, 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 learning effects calculation.  Capital costs, heat rates, and first year of availablilty from the AEO2009 reference case are shown in Table 12 below; capital costs represent the costs of building new plants ordered in 2008. Additional linformation about costs and performance characteristics can be found on page 89 of the "Assumptions to the Annual Energy Outlook 2009."7 

Initially, investment decisions are determined in ECP using cost  and performance  characteristics that are represented as single point estimates corresponding to the average (expected) cost. However, these parameters are also subject to uncertainty and are better represented by distributions. If the distributions of two or more options overlap, the option with the lowest average cost is not likely to capture the  entire  market.  Therefore,  ECP  uses  a market-sharing algorithm to adjust the initial solution and reallocate some of the capacity expansion decisions to technologies that are competitive but do not have the lowest average cost. 

Fossil-fired steam and nuclear plant retirements are calculated endogenously within the model. Plants are retired if the market price of electricity is not sufficient to support continued operation.  The expected revenues from these plants are compared to  the  annual  going-forward  costs,  which  are mainly fuel and O&M costs. A plant is retired if these costs exceed the revenues and the overall cost of electricity can be reduced by building replacement capacity. 

The ECP submodule also determines whether to contract for unplanned firm power imports from Canada and from neighboring electricity supply regions. Imports from Canada are competed using supply curves developed from cost estimates for potential hydroelectric projects in Canada. Imports from neighboring electricity supply regions are competed in the ECP based on the cost of the unit in the exporting region plus the additional cost of transmitting the power. Transmission costs are computed as a fraction of revenue. 

After building new capacity, the submodule passes total available capacity to the electricity fuel dispatch submodule and new capacity expenses to the electricity finance and pricing submodule.


Table 8. Selected Technology Characteristics for Automobiles.  Need help, contact the National Energy Information Center at 202-586-8800.
Table 12. 2008 Overnight Capital costs (including Contingencies), 2008 Heat Rates, and Online Year by Technologyfor the AEO2009 Reference Case.  Need help, contact the National Energy Information Center at 202-586-8800.
 

Electricity Fuel Dispatch Submodule   back to top

Given  available  capacity,  firm  purchased-power  agreements, fuel prices, and load curves, the electricity fuel dispatch (EFD) submodule minimizes variable costs as it solves for generation facility utilization and economy power exchanges to satisfy demand in each time period and region.  Limits on emissions of sulfur dioxide from generating units and the engineering characteristics of units serve as constraints. Coal-fired capacity can co-fire with biomass in order to lower operating costs and/or emissions. 

The EFD uses a linear programming (LP) approach to provide a minimum cost solution to allocating (dispatching) capacity to meet demand. It simulates the electric transmission network on the NERC region level and simultaneously dispatches capacity regionally by time slice until demand for the year is met. Traditional cogeneration and firm trade capacity is removed from the load duration curve prior to the dispatch decision. Capacity costs for each time slice are based on fuel and variable O&M costs, making adjustments for RPS credits, if applicable, and production tax credits. Generators are required to meet planned maintenance requirements, as defined by plant type. 

Interregional economy trade is also represented in the EFD submodule by allowing surplus generation in one region to satisfy electricity demand in an importing region, resulting in a cost savings. Economy trade with Canada is determined in a similar manner as interregional economy trade. Surplus Canadian energy is allowed to displace energy in an importing region if it results in a cost savings. After dispatching, fuel use is reported back to the fuel supply modules and operating expenses and revenues from trade are reported to the electricity finance and pricing submodule.

 
Electricity Finance and Pricing Submodule   back to top

The costs of building capacity, buying power, and generating electricity are tallied in the electricity finance and pricing (EFP) submodule, which simulates both competitive electricity pricing and the cost-of-service method often used by State regulators to determine the price of electricity. The AEO2009 reference case assumes a transition to full competitive pricing in New York, Mid-Atlantic Area Council, and Texas, and a 95 percent transition to competitive pricing in New England (Vermont being the only fully-regulated State in that region). California returned to almost fully regulated pricing in 2002, after beginning a transition to competition in 1998. In addition electricity prices in the East Central Area Reliability Council, the Mid-American Interconnected Network, the Southeastern Electric Reliability Council, the Southwest Power Pool, the Northwest Power Pool, and the Rocky Mountain Power Area/Arizona are a mix of both competitive and regulated prices. Since some States in each of these regions have not taken action to deregulate their pricing of electricity, prices in those States are assumed to continue to be based on traditional cost-of-service pricing. The price for mixed regions is a load-weighted average of the competitive price and the regulated price, with the weight based on the percent of electricity load in the region that has taken action to deregulate. In regions where none of the states in the region have introduced competition—Florida Reliability Coordinating Council and Mid-Continent Area Power Pool—electricity prices are assumed to remain regulated and the cost-of-service calculation is used to determine electricity prices. 

Using historical costs for existing plants (derived from various sources such as Federal Energy Regulatory Commission Form 1, Annual Report of Major Electric Utilities, Licensees and Others, and Form EIA-412, Annual Report of Public Electric Utilities), cost estimates for new plants, fuel prices from the NEMS fuel supply modules, unit operating levels, plant decommissioning costs, plant phase-in costs,  and  purchased  power costs,  the  EFP submodule calculates total revenue requirements for each area of operation—generation, transmission, and distribution—for pricing of electricity in the fully  regulated  States.  Revenue  requirements shared over sales by customer class yield the price of electricity for each class. Electricity prices are returned to the demand modules. In addition, the submodule generates detailed financial statements. 

For those States for which it is applicable, the EFP also determines competitive prices for electricity generation. Unlike cost-of-service prices, which are based on average costs, competitive prices are based on marginal costs. Marginal costs are primarily the operating costs of the most expensive plant required to meet demand. The competitive price also includes a reliability price adjustment, which represents the value consumers place on reliability of service when demands are high and available capacity is limited. Prices for transmission and distribution are assumed to remain regulated, so the delivered electricity price under competition is the sum of the marginal price of generation and the average price of transmission and distribution.

 
Electricity Load and Demand Submodule   back to top

The electricity load and demand (ELD) submodule generates load curves representing the demand for electricity. The demand for electricity varies over the course of a day. Many different technologies and end uses, each requiring a different level of capacity for different lengths of time, are powered by electricity. For operational and planning analysis, an annual load duration curve, which represents  the  aggregated  hourly  demands,  is constructed. Because demand varies by geographic area and time of year, the ELD submodule generates load curves for each region and season.

   
Emissions   back to top

EMM tracks emission levels for sulfur dioxide (SO2) and nitrogen oxides (NOx).  Facility development, retrofitting, and dispatch are constrained to comply with the pollution constraints of the CAAA90 and other pollution constraints including the Clean Air Interstate Rule.  An innovative feature of this legislation is a system of trading emissions allowances.  The trading system allows a utility with a relatively low cost of compliance to sell its excess compliance (i.e., the degree to which its emissions per unit of power generated are below maximum allowable levels) to utilities with a relatively high cost of compliance.  The trading of emissions allowances does not change the national aggregate emissions level set by CAAA90, but it does tend to minimize the overall cost of compliance. 

In addition to SO2, and NOx, the EMM also determines mercury and carbon dioxide emissions.  It represents control options to reduce emissions of these four gases, either individually or in any combination.  Fuel switching from coal to natural gas, renewables, or nuclear can reduce all of these emissions.  Flue gas desulfurization equipment can decrease SO2 and mercury emissions.  Selective catalytic reduction can reduce NOx and mercury emissions. Selective non-catalytic reduction and low-NOx burners can lower NOx emissions.  Fabric filters and activated carbon injection can reduce mercury emissions.  Lower emissions resulting from demand reductions are determined in the end-use demand modules. 

The AEO2009 includes a generalized structure to model current state-level regulations calling for the best available control technology to control mercury.  The AEO2009 also includes the carbon caps for States that are part of the RGGI.

   

 

 

 

 

 

 

 

 

 

 

Preface and Contacts
Appendix

Notes and Sources

 
Chapters in this Report:

Introduction/Overview of NEMS
Carbon Dioxide Emissions
Modules:
  Macroeconomic
  International Energy
  Residential Demand
  Commercial Demand

  Industrial Demand
  Transportation Demand

  Electricity Market
  Renewable Fuels
  Oil and Gas Supply
  Natural Gas Transmission & Distribution
  Petroleum Market Module

  Coal Market Module