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Electricity Market Module (EMM)

Description:

The NEMS Electricity Market Module (EMM) provides a major link in the NEMS framework. In each model year, the EMM receives electricity demand from the NEMS demand modules, fuel prices from the NEMS fuel supply modules, expectations from the NEMS system module, and macroeconomic parameters from the NEMS macroeconomic module and then estimates the actions taken by electric utilities and nonutilities to meet demand in the most economical manner. The EMM then outputs electricity prices to the demand modules, fuel consumption to the fuel supply modules, emissions to the system module, and capital requirements to the macroeconomic module. The model is iterated until a solution is reached for that model year. The EMM consists of four submodules: Electricity Capacity Planning (ECP), Electricity Fuel Dispatch (EFD), Electricity Finance and Pricing (EFP), and Load and Demand-Side Management (LDSM).

Electricity Capacity Planning Submodule (ECP):

The purpose of the ECP is to determine how the electric power industry will change its mix of generating capacity over the forecast horizon. It is intended to consider investment decisions for both demand- and supply-side options. However, consumer responses are assumed to be represented in the end-use demand modules, so the structure for demand-side management (DSM) options is not utilized within the ECP. It evaluates retirement decisions for fossil and nuclear plants and captures responses to environmental regulations, such as the CAAA or limits on carbon emissions. It includes traditional and nontraditional sources of supply. The ECP also represents changes in the competitive structure (i.e., deregulation). Due to competition, no distinction is made between utilities and nonutilities as owners of new capacity.

Electricity Fuel Dispatch Submodule (EFD):

The objective of the EFD is to represent the economic, operational, and environmental considerations in electricity dispatching and trade. The EFD allocates available generating capacity to meet the demand for electricity on a minimum cost basis, subject to engineering constraints and to restrictions on emissions such as SO2, NOx, mercury, and carbon.

Electricity Finance and Pricing Submodule (EFP):

The EFP forecasts financial information for electric utilities on an annual basis given a set of inputs and assumptions concerning forecast capacity expansion plans, operating costs, regulatory environment, and financial data. The outputs of the model include electricity prices by end use sectors for North American Electric Reliability (NERC) and Census regions, financial statements, revenue requirements, and financial ratios for each state of production (generation, transmission and distribution).

Load and Demand-Side Management Submodule (LDSM):

Broadly speaking, the LDSM submodule has been designed to perform four major functions:

• Translate total electricity consumption forecasts into system load shapes
• Develop utility DSM programs for potential inclusion in future utility capacity expansion plans
• Translate census division demand data into NERC region data, and vice versa
• Report DSM impact on regional system demand.

Emissions:

The EMM tracks emission levels for sulfur dioxide (SO2), nitrogen oxides (Nox), and mercury (hg). Facility development, retrofitting, and dispatch are constrained to comply with the constraints to the Clean Air Act Amendments of 1990 (CAAA90) and other pollution constraints. 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.

Last Model Update:

September 2001

Part of Another Model?

Part of the National Energy Modeling System (NEMS).

Sponsor:

• Office: Office of Integrated Analysis and Forecasting
• Division: Coal and Electric Power Division
• Model Contact: Jeffrey Jones
• Telephone: (202) 586-2038
• E-Mail Address: Jeffrey.Jones@eia.doe.gov

Documentation:

Energy Information Administration, Model Documentation Report: The Electricity Market Module of the National Energy Modeling System, DOE/EIA-M068 (Washington, DC, February 2001)
http://tonto.eia.doe.gov/FTPROOT/modeldoc/m0682001.pdf.

Archive Media and Installation Manual(s):

See Integrating Module of the National Energy Modeling System.

Coverage:

• Geographic: 13 North American Electric Reliability Council (NERC) Regions and Subregions, called EMM regions
• Time Unit/Frequency: Annually through 2020
• Product(s):
  • Electricity prices and price components
  • Fuel demands
  • Capacity additions
  • Capital requirements
  • Emissions
  • Renewable capacity
  • Avoided costs
• Economic Sector(s): Electric utilities and non-utilities.

Modeling Features:

• Model Structure:
  • ECP — The ECP is executed once a year to determine planning decisions that must be initiated in the current forecast year and completed within the planning horizon. The ECP uses a linear programming (LP) formulation to compete options for meeting future demands for electricity and complying with environmental regulations. It selects the strategies that minimize the total present value of the investment and operating costs over a pre-specified period, subject to certain conditions. These conditions include requirements that demands for electricity (accounting for seasonal and daily fluctuations variations and transmission/distributions losses) are met, minimum reliability requirements are satisfied, and emissions limits are not exceeded
  • EFD — The EFD addresses utility and nonutility supplies endogenously; i.e., the EFD dispatches new nonutility sources together with utility fossil-fuel, geothermal, biomass, and nuclear generating capacity. However, existing nonutility supply, along with nontraditional cogenerators, are considered "must run:" units and are placed such that they are always dispatched. Most of these facilities have contracts with utilities to purchase power, so this treatment ensures that the model output reflects actual usage. Traditional cogeneration and intermittent renewable technologies are represented exogenously with the load curve adjusted prior to dispatching other generating technologies
  • EFP — The EFP is an accounting system that models regulatory practice and is completely deterministic. It has solution algorithms for the generation, transmission, and distribution stages of production. Pricing mechanisms are implemented for the generation and transmission stages of production to enhance the model's flexibility in simulating emerging pricing techniques used in the electric power industry
  • LDSM — The LDSM submodule is designed to be a fully integrated part of the NEMS framework. The submodule models the impact of DSM activities in terms of changes in load shapes. To do this, the LDSM submodule has a database of end-use load shapes for each of the thirteen EMM regions, being modeled in the NEMS framework. The LDSM also uses a technologies database develops jointly with the demand modules. Individual DSM options then match a base technology ("FROM" technology) to a more efficient DSM technology ("TO" technology). The energy changes and the resulting changes in load shapes (delta load shapes) are computed for each option. These constitute the unit level impact of DSM options. To compute the system level impacts, the DSM options must first be penetrated over time, and then aggregated to a form that can be completed against supply-side options. Details of these processes are given in the sections that follow. The three primary functions of the LDSM submodule are to (a) develop regional system load duration curves from demand estimates for the ECP and EFD modules, (b) screen potential DSM options for analysis by the EMM Capacity Planning module, and (c) supply the demand modules with feedback from the ECP concerning the shifts in end-use technology resulting from the optimal choice of DSM options. In addition to these three functions, the LDSM also translates the nine Census division electricity demand estimates into the 13 NERC regions and subregions that the EMM requires
• Modeling Technique:
  • ECP — The ECP uses a linear programming (LP) formulation to determine planning decisions for the electric power industry. The ECP contains a representation of planning and dispatching in order to examine the tradeoff between capital and operating costs. It simulates least-cost planning and competitive markets by selecting strategies for meeting expected demands and complying with environmental restrictions that minimize the discounted, present value of investment and operating costs. The ECP explicitly incorporates emissions restrictions imposed by the CAAA90 and provides the flexibility to examine potential regulations such as emissions taxes and carbon stabilization
  • EFD — The EFD uses an heuristic approach to provide a least-cost solution to allocating (dispatching) capacity to meet demand. Dispatching involves deciding what generating capacity should be operated to meet the demand for electricity, which is subject to seasonal, daily, and hourly fluctuations. The objective of the EFD is to provide an economic/environmental dispatching procedure. In an economic (least-cost) dispatch, the marginal source of electricity is selected to react to each change in load. In environmental dispatching, the demand for electricity must be satisfied without violating certain emissions restrictions. The EFD integrates the cost-minimizing solution with environmental compliance options to produce the least-cost solution that satisfies electricity demand and restricts emissions to be within specified limits
  • EFP — The EFP is an accounting system that models regulatory practice and is completely deterministic. It has solution algorithms for the generation, transmission, and distribution stages of production. Pricing mechanisms are implemented for the generation and transmission stages of production to enhance the model's flexibility in simulating emerging pricing techniques used in the electric power industry. There are many pricing mechanisms that could be used for this purpose. The one that has been included initially in this submodule is the traditional cost of service method. The modular design of this submodule will allow the user to plug in additional pricing methods as they are needed in the future
  • LDSM — The basic algorithm can be thought of as an end-use building block approach. The system demand is divided into a set of components called end-uses. The hourly loads for each end-use are forecast. Next, the hourly loads of each end-use are summed to yield the forecast of system load at the customers' meters (i.e., hourly system sales). The final step is to simulate transmission and distribution losses. The regional hourly loads are calculated as the sum of hourly system sales and transmission and distribution losses.

Non-DOE Input Sources:

• The EPA 1985 National Utility Reference File (NURF), 1989. NURF data were submitted to the 10 EPA regions for review of the following key elements: 1985 SO2 emissions and emissions rate, 1985 total heat input, and 1985 SO2 emission limits and associated variables
• Data Resources/McGraw-Hill, Inc., Energy Review, Winter 1986-1987
• ICF, Incorporated
  • A survey of Canadian taxes
• New England Power Pool, New York Power Pool, and Western Area Power Administration
• NERC Mid-Atlantic Area Council and Northeast Power Coordinating Council
  • Reliability data
  • Electricity prices are calculated by use of a traditional cost of service discounting method for regulated regions, marginal cost calculations for competitive regions, and a hint of both methods when warrented. Accounting also takes into consideration regulatory nuances among regions
• Pacific Gas and Electric, Hydro-Quebec, Manitoba Hydro, and British Columbia Hydro
• Environmental Protection Agency: The National Allowance Data Base, Version 2.11, March 1993
  • Data base elements on utility combustion sources
• 1985 National Emissions Data System (NEDS) submittals
• EPRI, Technical Assessment Guide (TAG) Electricity Supply, 1989
• Oak Ridge National Laboratories, Energy Economic Database (EEDB), various program phases
• Electric Power Research Institute, Technical Assessment Guide (EPRI-TAG1993)
  • Photovoltatic cost and performance data
• EPRI, 1991: United Engineers and Constructors, Technical Feasibility and Costs of Selective Catalytic Reduction NOx Control, GS-7276
• EPRI, 1991: United Engineers and constructors, Economic Evaluation of Flue Gas Desulfurization Systems, GS-7193
• Vatabuk, Estimating Costs of Air Pollution Controls, Louis Publishers, 1990.

DOE Data Input Sources:

Forms and Publications:

• Energy Information Administration, Form EIA-860, Annual Generator Report
  • Capacity and fuel source information
• Energy Information Administration, Form EIA-867, Annual Nonutility Power Producer Report
  • Installed capacity, energy consumption, generation and electric energy sales to electric utilities and other nonutilities by facility
• EIA, Electric Plant Cost and Power Production Expenses, 1990
• Distributed Utility Associates, Assessing Market Acceptance and Penetration for Distributed Generation in the United States, Spring 1999, prepared for EIA. This report contains cost and performance characteristics for modeling distributed generation in the Electricity Market Module
• Energy Information Administration, Form EIA-767, Steam Electric Plant Operation and Design Report
  • Plant operations and equipment design (including boiler, generator, cooling system, flue gas desulfurization, flue gas particulate collectors, and stack data)
• Energy Information Administration, Form EIA-759, Monthly Power Plant Report
  • Monthly data on net generation, consumption of coal, petroleum, and natural gas; and end-of-the-month stocks of petroleum and coal for each plant by prime mover and fuel type combination
• Energy Information Administration, Form EIA-411, Coordinated Regional Bulk Power Supply Program Report
  • Actual energy and peak demand for the preceding year and 10 additional years; existing and future generating capacity; scheduled capacity transfers; projections of capacity, demand, purchases, sales, and scheduled maintenance; assessment of adequacy; generating capacity unavailability; bulk power system maps; near term transmission adequacy; future critical bulk power facilities that may not be in service when required; and system evaluation criteria
• Federal Energy Regulatory Commission, Form FERC-423, Monthly Report of Cost and Quality of Cost and Quality of Fuels for Electric Plants
  • Cost and performance data for both existing and future units

Models and Other:

• Energy Information Administration, Office of Integrated Analysis and Forecasting, "Cost and Performance Database for New Generating Technologies"
  • A database of current costs and performance characteristics
• Energy Information Administration, Annual Outlook for U.S. Electric Power, 1987
  • EIA survey data
• U.S. Department of Energy, Northern Lights: The Economic and Practical Potential of Imported Power from Canada, DOE/PE-0079 (Washington, DC, December 1987)
  • Capital costs to build
  • Variable and fixed operating and maintenance costs
  • Transmission costs
  • Various publications on Canadian energy supply cited in the Northern Lights bibliography

System Modules:

• Cogeneration and other electricity production, Commercial and Industrial Demand Modules
• Generation from renewable sources
• Renewables Fuels Module
• Fossil fuel prices — Fuel Supply Modules of NEMS
• SO2 and mercury emissions — Coal Market Module
• Bond rates — Macroeconomic Activity Module
• Capacity utilization by technology — Renewable Fuels Module
• Electricity consumption by sector and region, traditional cogeneration

Demand Modules:

• Fuel and variable O&M costs, fixed O&M costs, SO2 allowance costs, RPS allowance costs, trade results and nonutility generation — EFD
• Sectoral consumption by time period — LDSM
• New plant capital costs, plant type, ownership type, and retrofit decisions — ECP
• EIA, Advanced Reactor Sourcebook.