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National Energy Modeling System (NEMS) Documentation Archive

Electricity Market Module - NEMS Documentation

December 14 2018

Introduction

The National Energy Modeling System (NEMS) was developed to provide 20- to 25-year forecasts and analyses of energy-related activities. The NEMS uses a central database to store and pass inputs and outputs between the various components. The NEMS Electricity Market Module (EMM) provides a major link in the NEMS framework (Figure 1). 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. The EMM estimates the actions taken by electricity producers (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 integrating module, and capital requirements to the macroeconomic module. The model iterates until a solution is reached for each forecast year.

The EMM represents the capacity planning, generation, transmission, and pricing of electricity, subject to: delivered prices for coal, petroleum products, natural gas, and biomass; the cost of centralized generation facilities; 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 electricity load and demand (Figure 2). In addition, nonutility supply and electricity trade are represented in the fuel dispatching and capacity planning submodules. Nonutility generation from cogenerators and other facilities whose primary business is not electricity generation is represented in the NEMS demand and fuel supply modules. All other nonutility generation is represented in the EMM. The generation of electricity is accounted for in 22 supply regions (Figure 3). Alaska and Hawaii are not modeled explicitly in the EMM, but generation and consumption projections for those states are estimated for reporting national totals.

Operating (dispatch) decisions are made by choosing the mix of plants that minimizes fuel, variable operating and maintenance (O&M), and environmental costs, subject to meeting electricity demand and environmental constraints. 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, season, and time of day.

The EMM also represents distributed generation that is owned by electricity suppliers. Consumer-owned distributed generation has been determined in the end-use demand modules of NEMS, and the demand for the power sector is typically provided net of any onsite generation. However, because the end use models provide only an annual net demand, they cannot accurately reflect when rooftop solar photovoltaic (PV) generation occurs. In order to address this issue, the EMM receives total end-use demands without removing rooftop PV generation, and then dispatches both power sector and end use PV capacity using detailed solar resource profiles. This allows the end use PV to impact the net load requirements at the proper times, sending more accurate signals to the EMM regarding generation and capacity requirements at peak load times. The overall generation requirement for the EMM is unchanged, and reporting of demand and generation still reflect the end-use PV in the appropriate end-use sector.

The EMM considers construction, operating, and avoided transmission and distribution costs associated with distributed generation to evaluate these options as an alternative to central-station capacity.

The solution to the submodules of the 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 summarized as follows:

  1. The electricity load and demand submodule processes electricity demand to construct load curves.
  2. The electricity capacity planning submodule projects the construction of new generating plants, the retirement (if appropriate) of existing plants, the level of firm power trades, and the addition of scrubbers and other equipment for environmental compliance.
  3. The electricity fuel dispatch submodule dispatches the available generating units, allowing surplus capacity in selected regions to be dispatched for another region's needs (economy trade).
  4. The electricity finance and pricing submodule calculates electricity prices, based on both average and marginal costs

Electricity Load and Demand Submodule
The electricity load and demand (ELD) submodule has been designed to perform two major functions:

  • Translate Census division demand data into North American Electric Reliability Corporation (NERC) region data, and vice versa.
  • Translate total electricity consumption forecasts into system load shapes.

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. The ELD generates load curves representing the variations in the demand for electricity. For operational and planning analysis, a 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 for operational purposes.

Electricity Capacity Planning Submodule
The electricity capacity planning (ECP) submodule determines how to best meet expected growth in electricity demand, given available resources, expected load shapes, expected demands and fuel prices, environmental constraints, and technology costs and performance characteristics. When new capacity is required to meet electricity demand, the technology that is 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 ECP evaluates retirement decisions for fossil fuel and nuclear plants and captures responses to environmental regulations. 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.

The utilization of the capacity is important in the decision-making process. A technology with relatively high capital costs but comparatively low operating costs (such as coal-fired technologies) 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 (such as a natural gas-fired turbine technology) 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 base load plants and cheaper to operate than peak load plants (such as a natural gas-fired combined cycle plant).

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