Electricity Market Module
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U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2013 101

Electricity Market Module

The NEMS Electricity Market Module (EMM) represents the capacity planning, dispatching, and pricing of electricity. It is 

composed of four submodules—electricity capacity planning, electricity fuel dispatching, electricity load and demand, and 

electricity finance and pricing. It includes nonutility capacity and generation, and electricity transmission and trade. A detailed 

description of the EMM is provided in the EIA publication, Electricity Market Module of the National Energy Modeling System 

2013, DOE/EIA-M068(2013).

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. This section describes the 

model parameters and assumptions used in EMM. It includes a discussion of legislation and regulations that are incorporated in 

EMM as well as information about the climate change action plan. The various electricity side cases are also described.

EMM regions 

The supply regions used in EMM are based on the North American Electric Reliability Corporation regions and subregions 

shown in Figure 6.

Figure 6. Electricity Market Model Supply Regions
102 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2013

Electricity Market Module

Model parameters and assumptions 

Generating capacity types 

The capacity types represented in the EMM are shown in Table 8.1.

Table 8.1. Generating capacity types represented in the Electricity Market Module

Capacity Type

Existing coal steam plants1

High Sulfur Pulverized Coal with Wet Flue Gas Desulfurization

Advanced Coal - Integrated Coal Gasification Combined Cycle

Pulverized Coal with carbon sequestration

Oil/Gas Steam - Oil/Gas Steam Turbine

Combined Cycle - Conventional Gas/Oil Combined Cycle Combustion Turbine

Advanced Combined Cycle - Advanced Gas/Oil Combined Cycle Combustion Turbine

Advanced Combined Cycle with carbon sequestration

Combustion Turbine - Conventional Combustion Turbine

Advanced Combustion Turbine - Steam Injected Gas Turbine

Molten Carbonate Fuel Cell

Conventional Nuclear

Advanced Nuclear - Advanced Light Water Reactor

Generic Distributed Generation - Baseload

Generic Distributed Generation - Peak

Conventional Hydropower - Hydraulic Turbine

Pumped Storage - Hydraulic Turbine Reversible

Geothermal

Municipal Solid Waste

Biomass - Fluidized Bed

Solar Thermal - Central Tower

Solar Photovoltaic - Fixed Tilt

Wind

Wind Offshore

1

The EMM represents 32 different types of existing coal steam plants, based on the different possible configuration of NOx, particulate and SO2

emission control devices, as well as future options for controlling mercury and carbon.

Source: U.S. Energy Information Administration.

New generating plant characteristics 

The cost and performance characteristics of new generating technologies are inputs to the electricity capacity planning 

submodule (Table 8.2). These characteristics are used in combination with fuel prices from the NEMS fuel supply modules and 

foresight on fuel prices, to compare options when new capacity is needed. Heat rates for new fossil-fueled technologies are 

assumed to decline linearly through 2025.

For the AEO2013, EIA commissioned an external consultant to update current cost estimates for utility-scale electric generating 

plants [1]. This report used a consistent methodology, similar to the one used to develop the estimates for AEO2011 and 

AEO2012, but accounted for more recent data and experience. A cost adjustment factor, based on the producer price index for 

metals and metal products, allows the overnight costs to fall in the future if this index drops, or rise further if it increases.

The overnight costs shown in Table 8.2 represent the estimated cost of building a plant in a typical region of the country. 

Differences in plant costs due to regional distinctions are calculated by applying regional multipliers. Regional multipliers by 

technology are also based on regional cost estimates developed by the consultant. The regional variations account for multiple 

factors, such as differences in terrain, weather, population, and labor wages. The base overnight cost is multiplied by a project 

contingency factor and a technological optimism factor (described later in this chapter), resulting in the total construction cost 

for the first-of-a-kind unit used for the capacity choice decision.
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Electricity Market Module

Table 8.2. Cost and performance characteristics of new central station electricity generating technologies

Technology

Online

Year1

Size

(mW)

Lead 

time

(years)

Base 

Overnight 

Cost in 

2012

(2011 $/

kW)

Contingency Factors Total 

Overnight

Cost in 

20124

(2011 $/

kW)

Variable

O&M5

(2011 $/

mWh)

Fixed

O&M

(2011$/

kW)

Heatrate6

in 2012

(Btu/

kWh)

nth-of-akind

Heatrate

(Btu/

kWh)

Project 

Contingency

Factor2

Technological

Optimism

Factor3

Scrubbed Coal 

New7 2016 1300 4 2,694 1.07 1.00 2,883 4.39 30.64 8,800 8,740 

Integrated CoalGasification Comb 

Cycle (IGCC)7 2016 1200 4 3,475 1.07 1.00 3,718 7.09 50.49 8,700 7,450 

Pulverized Coal with 

Carbon sequestion 2017 650 4 4,662 1.07 1.03 5,138 4.37 65.31 12,000 9,316

Conv Gas/Oil Comb 

Cycle 2015 620 3 858 1.05 1.00 901 3.54 12.94 7,050 6,800 

Adv Gas/Oil Comb 

Cycle (CC) 2015 400 3 931 1.08 1.00 1,006 3.21 15.10 6,430 6,333 

Adv CC with carbon 

sequestration 2017 340 3 1,833 1.08 1.04 2,059 6.66 31.23 7,525 7,493 

Conv Comb 

Turbine8 2014 85 2 910 1.05 1.00 956 15.18 7.21 10,850 10,450 

Adv Comb Turbine 2014 210 2 632 1.05 1.00 664 10.19 6.92 9,750 8,550 

Fuel Cells 2015 10 3 6,045 1.05 1.10 6,982 0.00 357.47 9,500 6,960 

Adv Nuclear 2018 2236 6 4,700 1.10 1.05 5,429 2.10 91.65 10,452 10,452

Distributed 

Generation - Base 2015 2 3 1,395 1.05 1.00 1,465 7.62 17.14 9,038 8,900 

Distributed 

Generation - Peak 2015 1 2 1,675 1.05 1.00 1,759 7.62 17.14 10,042 9,880 

Biomass 2016 50 4 3,685 1.07 1.02 4,041 5.17 103.79 13,500 13,500 

Geothermal7,9 2013 50 4 2,444 1.05 1.00 2,567 0.00 110.94 9,756 9,756

MSW - Landfill Gas 2013 50 3 7,858 1.07 1.00 8,408 8.51 381.74 13,648 13,648

Conventional 

Hydropower9 2016 500 4 2,179 1.10 1.00 2,397 2.60 14.57 9,756 9,756

Wind 2013 100 3 2,032 1.07 1.00 2,175 0.00 38.86 9,756 9,756

Wind Offshore 2016 400 4 4,452 1.10 1.25 6,121 0.00 72.71 9,756 9,756

Solar Thermal7 2015 100 3 4,653 1.07 1.00 4,979 0.00 66.09 9,756 9,756

Photovoltaic7,10 2014 150 2 3,624 1.05 1.00 3,805 0.00 21.37 9,756 9,756 1

Online year represents the first year that a new unit could be completed, given an order date of 2012. For wind, geothermal and landfill gas, the online 

year was moved earlier to acknowledge the significant market activity already occurring in anticipation of the expiration of the Production Tax Credit.

2

A contingency allowance is defined by the American Association of Cost Engineers as the “specific provision for unforeseeable elements of costs within 

a defined project scope; particularly important where previous experience has shown that unforeseeable events which will increase costs are likely to 

occur” 

3

The technological optimism factor is applied to the first four units of a new, unproven design, it reflects the demonstrated tendency to underestimate 

actual costs for a first-of-a-kind unit.

4 Overnight capital cost including contingency factors, excluding regional multipliers and learning effects. Interest charges are also excluded. These 

represent costs of new projects initiated in 2012. 

5

O&M = Operations and maintenance.

6

For hydro, wind, solar and geothermal technologies, the heatrate shown represents the average heatrate for conventional thermal generation as of 

2011.  This is used for purposes of calculating primary energy consumption displaced for these resources, and does not imply an estimate of their actual 

energy conversion efficiency.

7

Capital costs are shown before investment tax credits are applied. 

8

Combustion turbine units can be built by the model prior to 2014 if necessary to meet a given region’s reserve margin. 

9

Because geothermal and hydro cost and performance characteristics are specific for each site, the table entries represent the cost of the least expensive 

plant that could be built in the Northwest Power Pool region, where most of the proposed sites are located.

10Costs and capacities are expressed in terms of net AC power available to the grid for the installed capacity. 

Sources: For the AEO2013, EIA updated cost estimates for utility-scale electric generating plants, based on a draft report provided by external consultants. 

The final report can be found at www.eia.gov/forecasts/capitalcost/. Site specific costs for geothermal were provided by the National Energy Renewable 

Laboratory, “Updated U.S. Geothermal Supply Curve”, February 2010.
104 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2013

Electricity Market Module

Table 8.3. Learning parameters for new generating technology components

Technology Component

Period 1

Learning Rate 

(LR1)

Period 2

Learning 

Rate(LR2)

Period 3

Learning 

Rate (LR3)

Period 1

Doublings

Period 2

Doublings

Minimum Total

Learning by 2035

Pulverized Coal - - 1% - - 5%

Combustion Turbine - conventional - - 1% - - 5%

Combustion Turbine - advanced - 10% 1% - 5 10%

HRSG1 - - 1% - - 5%

Gasifier - 10% 1% - 5 10%

Carbon Capture/Sequestration 20% 10% 1% 3 5 20%

Balance of Plant - IGCC - - 1% - - 5%

Balance of Plant - Turbine - - 1% - - 5%

Balance of Plant - Combined Cycle - - 1% - - 5%

Fuel Cell 20% 10% 1% 3 5 20%

Advanced Nuclear 5% 3% 1% 3 5 10%

Fuel prep - Biomass - 10% 1% - 5 10%

Distributed Generation - Base - 5% 1% - 5 10%

Distributed Generation - Peak - 5% 1% - 5 10%

Geothermal - 8% 1% - 5 10%

Municipal Solid Waste - - 1% - - 5%

Hydropower - - 1% - - 5%

Wind - - 1% - - 5%

Wind Offshore 20% 10% 1% 3 5 20%

Solar Thermal 20% 10% 1% 3 5 10%

Solar PV - Module - 10% 1% - 5 10%

Balance of Plant - Solar PV - 10% 1% - 5 10% 1

HRSG = Heat Recovery Steam Generator

Note: Please see the text for a description of the methodology for learning in the Electricity Market Module.

Source: U.S. Energy Information Administration, Office of Electricity, Coal, Nuclear and Renewables Analysis.

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.

The technological optimism factor represents the demonstrated tendency to underestimate actual costs for a first-of-a-kind, 

unproven technology. As experience is gained (after building 4 units) the technological optimism factor is gradually reduced to

1.0.

The learning function in NEMS is determined at a component level. Each new technology is broken into its major components, 

and each component is identified as revolutionary, evolutionary or mature. Different learning rates are assumed for each 

component, based on the level of experience with the design component (Table 8.3). Where technologies use similar 

components, these components learn at the same rate as these units are built. For example, it is assumed that the underlying 

turbine generator for a combustion turbine, combined cycle and integrated coal-gasification combined cycle unit is basically the 

same. Therefore construction of any of these technologies would contribute to learning reductions for the turbine component.

The learning function has the nonlinear form:

OC(C) = a*C-b, 

where C is the cumulative capacity for the technology component.
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Electricity Market Module

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 (LR) is an exogenous parameter input for each component 

(Table 8.3). The progress ratio and LR are related by: 

pr = 2-b = (1 - LR) 

The parameter “b” is calculated from the second equality above (b =-(ln(1-LR)/ln(2)). The parameter “a” is computed from 

initial conditions, i.e. 

a =OC(C0)/CO

-b

where C0 is the initial cumulative capacity. Once the rates of learning (LR) and the cumulative capacity (C0) are known for each 

interval, the parameters (a and b) can be computed. Three learning steps were developed to reflect different stages of learning 

as a new design is introduced into the market. New designs with a significant amount of untested technology will see high rates 

of learning initially, while more conventional designs will not have as much learning potential. Costs of all design components 

are adjusted to reflect a minimal amount of learning, even if new capacity additions are not projected. This represents cost 

reductions due to future international development or increased research and development.

Once the learning rates by component are calculated, a weighted average learning factor is calculated for each technology. The 

weights are based on the share of the initial cost estimate that is attributable to each component (Table 8.4). For technologies 

that do not share components, this weighted average learning rate is calculated exogenously, and input as a single component.

These technologies may still have a mix of revolutionary components and more mature components, but it is not necessary to 

include this detail in the model unless capacity from multiple technologies would contribute to the component learning. In the 

case of the solar PV technology, it is assumed that the module component accounts for 50 percent of the cost, and that the 

balance of system components accounts for the remaining 50 percent. Because the amount of end-use PV capacity (existing 

and projected) is significant relative to total solar PV capacity, and because the technology of the module component is 

common across the end-use and electric power sectors, the calculation of the learning factor for the PV module component also 

takes into account capacity built in the residential and commercial sectors.

Table 8.5 shows the capacity credit toward component learning for the various technologies. It was assumed that for all 

combined-cycle technologies, the turbine unit contributed two-thirds of the capacity, and the steam unit one-third. Therefore, 

building one gigawatt of gas combined cycle would contribute 0.67 gigawatts toward turbine learning, and 0.33 gigawatts 

toward steam learning. Components that do not contribute to the capacity of the plant, such as the balance of plant category, 

receive 100 percent capacity credit for any capacity built with that component. For example, when calculating capacity for 

the “Balance of plant - CC” component, all combined cycle capacity would be counted 100 percent, both conventional and 

advanced.

Table 8.4. Component cost weights for new technologies

Technology

Pulverized 

Coal

Combustion

Turbineconventional

Combustion

Turbineadvanced HRSG Gasifier

Carbon

Capture/

Sequestration

Balance

of PlantIGCC

Balance 

of

PlantTurbine

Balance 

of

PlantCombined

Cycle

Fuel Prep

Biomass

Integrated

Coal-Gasification 

Comb Cycle (IGCC) 0% 0% 15% 20% 41% 0% 24% 0% 0% 0%

Pulverized Coal with 

carbon sequestration 70% 0% 0% 0% 0% 30% 0% 0% 0% 0%

Conv Gas/Oil Comb 

Cycle 0% 30% 0% 40% 0% 0% 0% 0% 30% 0%

Adv Gas/Oil Comb 

Cycle (CC) 0% 0% 30% 40% 0% 0% 0% 0% 30% 0%

Adv CC with carbon 

sequestration 0% 0% 20% 25% 0% 40% 0% 0% 15% 0%

Conv Comb Turbine 0% 50% 0% 0% 0% 0% 0% 50% 0% 0%

Adv Comb Turbine 0% 0% 50% 0% 0% 0% 0% 50% 0% 0%

Biomass 50% 0% 0% 0% 0% 0% 0% 0% 0% 50%

Note: All unlisted technologies have a 100 percent weight with the corresponding component. Components are not broken out for all technologies unless 

there is overlap with other technologies.

HRSG = Heat Recovery Steam Generator.

Source: Market-Based Advanced Coal Power Systems, May 1999, DOE/FE-0400.
106 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2013

Electricity Market Module

Table 8.5. Component capacity weights for new technologies

Technology

Pulverized 

Coal

Combustion

Turbineconventional

Combustion

Turbineadvanced HRSG Gasifier

Carbon

Capture/

Sequestration

Balance

of PlantIGCC

Balance 

of PlantTurbine

Balance of

PlantCombined

Cycle

Fuel 

Prep

Biomass

Integrated

Coal-Gasification 

Comb Cycle (IGCC) 0% 0% 67% 33% 100% 0% 100% 0% 0% 0%

Pulverized Coal with 

Carbon sequestration 100% 0% 0% 0% 0% 100% 0% 0% 0% 0%

Conv Gas/Oil Comb 

Cycle 0% 67% 0% 33% 0% 0% 0% 0% 100% 0%

Adv Gas/Oil Comb 

Cycle (CC) 0% 0% 67% 33% 0% 0% 0% 0% 100% 0%

Adv CC with carbon 

sequestration 0% 0% 67% 33% 0% 100% 0% 0% 100% 0%

Conv Comb Turbine 0% 100% 0% 0% 0% 0% 0% 100% 0% 0%

Adv Comb Turbine 0% 0% 100% 0% 0% 0% 0% 100% 0% 0%

Biomass 50% 0% 0% 0% 0% 0% 0% 0% 0% 100%

HRSG = Heat Recovery Steam Generator.

Source: U.S. Energy Information Administration, Office of Electricity, Coal, Nuclear and Renewables Analysis.

Distributed generation 

Distributed generation is modeled in the end-use sectors (as described in the appropriate chapters) as well as in the EMM. This 

section describes the representation of distributed generation in the EMM only. Two generic distributed technologies are modeled. 

The first technology represents peaking capacity (capacity that has relatively high operating costs and is operated when demand 

levels are at their highest). The second generic technology for distributed generation represents base load capacity (capacity that 

is operated on a continuous basis under a variety of demand levels). See Table 8.2 for costs and performance assumptions. It is 

assumed that these plants reduce the costs of transmission upgrades that would otherwise be needed. 

Demand storage 

The electricity model includes the option to build a new demand storage technology to simulate load shifting, through programs 

such as smart meters. This is modeled as a new technology build, but with operating characteristics similar to pumped storage. The 

technology is able to decrease the load in peak slices, but must generate to replace that demand in other time slices. There is an 

input factor that identifies the amount of replacement generation needed, where a factor of less than 1.0 can be used to represent 

peak shaving rather than purely shifting the load to other time periods. This plant type is limited to operating only in the peak load 

slices, and for AEO2013, it is assumed that this capacity is limited to 3.5 percent of peak demand on average in 2040, with limits 

varying from 2.2 percent to 6.8 percent of peak across the regions.

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 Corporation regions and subregions) using historical hourly load data. 

The load duration curve in the EMM is made up of 9 time slices. First, the load data is split into three seasons (winter - December 

through March, summer - June through September, and fall/spring). Within each season the load data is sorted from high to low, 

and three load segments are created - a peak segment representing the top 1 percent of the load, and then two off-peak segments 

representing the next 49 percent and 50 percent, respectively. The seasons were defined to account for seasonal variation in supply 

availability.

Reserve margins—the percentage of capacity required in excess of peak demand needed for unforeseeable outages—are determined 

within the model through an iterative approach comparing the marginal cost of capacity and the cost of unserved energy. The target 

reserve margin is adjusted for each model cycle until the two costs converge. The resulting reserve margins from the AEO2013

Reference case range from 8 to 21 percent.

Fossil fuel-fired and nuclear steam plant retirement 

Fossil-fired steam plant retirements and nuclear retirements are calculated endogenously within the model. Generating units are 

assumed to retire 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 operation of existing plant generators. A generating unit is assumed to
U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2013 107

Electricity Market Module

retire if the expected revenues from the generator are not sufficient to cover the annual going-forward costs and if the overall 

cost of producing electricity can be lowered by building new replacement capacity. The going-forward costs include fuel, 

operations and maintenance costs and annual capital additions, which are unit-specific and based on historical data. The 

average capital additions for existing plants are $8 per kilowatt (kW) for oil and gas steam plants, $17 per kW for coal plants 

and $22 per kW for nuclear plants (in 2011 dollars). These costs are added to the estimated costs at existing plants regardless 

of their age. Beyond 30 years of age an additional $7 per kW capital charge for fossil plants, and $33 per kW charge for nuclear 

plants is included in the retirement decision to reflect further investment to address the impacts of aging. Age-related cost 

increases are attributed to capital expenditures for major repairs or retrofits, decreases in plant performance, and/or increases in 

maintenance costs to mitigate the effects of aging.

EIA assumes all retirements reported as planned during the next ten years on the Form EIA-860 will occur. Additionally, 

the AEO2013 nuclear projection assumes an additional 6.5 gigawatts of nuclear capacity retirements by 2040 based on the 

uncertainty related to resolving issues associated with long-term operations and aging management.

Biomass co-firing 

Coal-fired power plants are assumed to co-fire with biomass fuel if it is economical. Co-firing requires a capital investment for 

boiler modifications and fuel handling. This expenditure is assumed to be $280 per kW of biomass capacity. A coal-fired unit 

modified to allow co-firing can generate up to 15 percent of the total output using biomass fuel, assuming sufficient residue 

supplies are available.

Nuclear uprates 

The AEO2013 nuclear power projection assumes capacity increases at existing units. Nuclear plant operators can increase the 

rated capacity at plants through power uprates, which are license amendments that must be approved by the U.S. Nuclear 

Regulatory Commission (NRC). Uprates can vary from small (less than 2 percent) increases in capacity, which require very little 

capital investment or plant modification, to extended uprates of 15-20 percent, requiring significant modifications. Historically, 

most uprates were small, and the AEO projections accounted for them only after they were implemented and reported, but 

recent surveys by the NRC and EIA have indicated that more extended power uprates are expected in the near future. AEO2013

assumes that all of those uprates reported to EIA as planned modifications on the Form EIA-860 will take place, representing 1.5 

gigawatts of additional capacity. EIA also assumes an additional 6.5 gigawatts of nuclear power uprates will be completed over 

the projection period, based on interactions with industry stakeholders and the NRC. Table 8.6 provides a summary of projected 

uprate capacity additions by region.

Table 8.6. Nuclear uprates by EMM region

gigawatts

Texas Reliability Entity 0.25

Florida Reliability Coordinating Council 1.12

Midwest Reliability Council - East 0.00

Midwest Reliability Council - West 0.55

Northeast Power Coordinating Council/New England 0.25

Northeast Power Coordinating Council/NYC-Westchester 0.00

Northeast Power Coordinating Council/Long Island 0.00

Northeast Power Coordinating Council/Upstate 0.50

ReliabilityFirst Corporation/East 0.82

ReliabilityFirst Corporation/Michigan 0.25

ReliabilityFirst Corporation/West 0.99

SERC Reliability Corporation/Delta 0.43

SERC Reliability Corporation/Gateway 0.00

SERC Reliability Corporation/Southeastern 0.25

SERC Reliability Corporation/Central 0.75

SERC Reliability Corporation/Virginia-Carolina 1.06

Southwest Power Pool/North 0.00

Southwest Power Pool/South 0.00

Western Electricity Coordinating Council/Southwest 0.25

Western Electricity Coordinating Council/California 0.55

Western Electricity Coordinating Council/Northwest Power Pool Area 0.00

Western Electricity Coordinating Council/Rockies 0.00

Total 8.02

Source: U.S. Energy Information Administration, Office of Electricity, Coal, Nuclear and Renewables Analysis, based on Nuclear Regulatory 

Commission survey www.nrc.gov/reactors/operating/licensing/power-updates.html.
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Electricity Market Module

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 North American 

Electric Reliability Corporation and Western Electricity Coordinating Council 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 2007 and information provided in the 2012 Summer and Winter Assessments. They are locked in for the term of 

the contract. Contracts that are scheduled to expire by 2016 are assumed not to be renewed. Because there is no information 

available about expiration dates for contracts that go beyond 2016, they are assumed to be phased out by 2025. The EMM 

includes an option to add interregional transmission capacity. In some cases it may be more economic to build generating 

capacity in a neighboring region, but additional costs to expand the transmission grid will be incurred as well. Explicitly expanding 

the interregional transmission capacity may also make the transmission line available for additional economy trade.

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 assumed 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. Data on existing and planned transactions are obtained from the North American Electric Reliability 

Corporation’s Electricity Supply and Demand Database 2007. 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 from 

the MAPLE-C model developed for Natural Resources Canada.

Electricity pricing

Electricity pricing is projected for 22 electricity market regions in AEO2013 for fully competitive, partially competitive and 

fully regulated supply regions. The price of electricity to the consumer comprises the price of generation, transmission, and 

distribution, including applicable taxes. 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 to build, operate and maintain these systems. In competitive 

regions, an algorithm allows customers to compete for better rates among rate classes as long as the overall average cost is 

met. The price of electricity in the regulated regions consists of the average cost of generation, transmission, and distribution 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 competitive generation price includes the marginal cost (fuel 

and variable operations and maintenance costs), taxes, and a reliability price adjustment, which represents what customers 

are willing to pay for added capacity to avoid outages in periods of high demand. For the AEO2013, the difference between EIA’s 

reliability costs and the historical Independent System Operator capacity, ancillary service, and uplift charges was added to 

the competitive generation price. The price of electricity in the regions with a competitive generation market consists of the 

competitive cost of generation summed with the average costs of transmission and distribution. The price for mixed regions 

reflects a load-weighted average of the competitive price and the regulated price, based on the percent of electricity load in the 

region subject to deregulation. In competitively supplied regions, a transition period is assumed to occur (usually over a ten-year 

period) from the effective date of restructuring, with a gradual shift to marginal cost pricing.

The Reference case assumes a transition to full competitive pricing in the three New York regions and in the ReliabilityFirst

Corporation/ East region, and a 97-percent transition to competitive pricing in New England (Vermont being the only fullyregulated state in that region). Six regions fully regulate their electricity supply, including the Florida Reliability Coordinating 

Council, three of the SERC Reliability Corporation subregions - Southeastern (SRSE), Central (SRCE) and Virginia-Carolina (SRVC) 

- Southwest Power Pool Regional Entity/North (SPNO), and the Western Electricity Coordinating Council / Rockies (RMPA). The 

Texas Reliability Entity, which in the past was considered fully competitive by 2010, is now only 88-percent competitive, since 

many cooperatives have declined to become competitive or allow competitive energy to be sold to their customers. California 

returned to almost fully regulated pricing in 2002, after beginning a transition to competition in 1998, with only 7 percent 

competitive supply sold currently in the Western Electricity Coordinating Council (WECC)/ California region. All other regions 

reflect a mix of both competitive and regulated prices.
U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2013 109

Electricity Market Module

There have been ongoing changes to pricing structures for ratepayers in competitive states since the inception of retail 

competition. The AEO has incorporated these changes as they have been incorporated into utility tariffs. These have included 

transition period rate reductions and freezes instituted by various states, and surcharges in California relating to the 2000-2001 

energy crisis in the state. Since price freezes for most customers have ended or will end in the next year or two, a large survey of 

utility tariffs found that many costs related to the transition to competition were now explicitly added to the distribution portion, 

and sometimes the transmission portion of the customer bill, regardless of whether or not the customer bought generation 

service from a competitive or regulated supplier. There are some unexpected costs relating to unforeseen events. For instance, 

as a result of volatile fuel markets, state regulators have had a hard time enticing retail suppliers to offer competitive supply 

to residential and smaller commercial and industrial customers. They have often resorted to procuring the energy themselves 

through auction or competitive bids or have allowed distribution utilities to procure the energy on the open market for their 

customers for a fee. 

For AEO2013, typical charges that all customers must pay on the distribution portion of their bill (depending on where they reside) 

include: transition charges (including persistent stranded costs), public benefits charges (usually for efficiency and renewable 

energy programs), administrative costs of energy procurement, and nuclear decommissioning costs. Costs added to the 

transmission portion of the bill include the Federally Mandated Congestion Charges (FMCC), a bill pass-through associated with 

the Federal Energy Regulatory Commission passage of Standard Market Design (SMD) to enhance reliability of the transmission 

grid and control congestion. Additional costs not included in historical data sets have been added in adjustment factors to 

the transmission and distribution operations and maintenance costs, which impact the cost of both competitive and regulated 

electricity supply. Since most of these costs, such as transition costs, are temporary in nature, they are gradually phased out 

throughout the projection. Regions found to have these added costs include the Northeast Power Coordinating Council/ New 

England and New York regions, the ReliabilityFirst Corporation/ East and West regions, and the WECC/ California region.

Fuel price expectations 

Capacity planning decisions in the EMM are based on a life cycle 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 rational expectations, or ‘perfect 

foresight.’ In this approach, expectations for future years are defined by the realized solution values for these years in a prior run. 

The expectations for the world oil price and natural gas wellhead price are set using the resulting prices from a prior run. The 

markups to the delivered fuel prices are calculated based on the markups from the previous year within a NEMS run. Coal prices 

are determined using the same coal supply curves developed in the Coal Market Module. The supply curves produce prices at 

different levels of coal production, as a function of labor productivity, and costs and utilization of mines. Expectations for each 

supply curve are developed in the EMM based on the actual demand changes from the prior run throughout the projection 

horizon, resulting in updated mining utilization and different supply curves.

The perfect foresight approach generates an internally consistent scenario for which the formation of expectations is consistent 

with the projections realized in the model. The NEMS model involves iterative cycling of runs until the expected values and 

realized values for variables converge between cycles.

Nuclear fuel prices 

Nuclear fuel prices are calculated through an offline analysis which determines the delivered price to generators in mills per 

kilowatthour. To produce reactor grade uranium, the uranium (U308) must first be mined, and then sent through a conversion 

process to prepare for enrichment. The enrichment process takes the fuel to a given purity of U-235, typically 3-5 percent for 

commercial reactors in the United States. Finally, the fabrication process prepares the enriched uranium for use in a specific type 

of reactor core. The price of each of the processes is determined, and the prices are summed to get the final price of the delivered 

fuel. The one mill per kilowatthour charge that is assessed on nuclear generation to go to the DOE’s Nuclear Waste Fund is also 

included in the final nuclear price. The analysis uses forecasts from Energy Resources International for the underlying uranium 

prices.

Legislation and regulations

Clean Air Act Amendments of 1990 (CAAA90) and Clean Air Interstate Rule (CAIR) 

Currently, regulation of SO2 and NOX emissions is administered under the Clean Air Interstate Rule (CAIR), and the AEO2013

assumes that CAIR remains a binding regulation throughout the projection period. CAIR was initially promulgated in 2005, but 

has been challenged in court several times. The Cross-State Air Pollution Rule (CSAPR) was released by EPA in July 2011 and 

was intended to replace CAIR, but it was vacated by the U.S. Court of Appeals for the District of Columbia Circuit, and CAIR was 

reinstated. 
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CAIR covers all fossil fueled power plants greater than 25 megawatts in 27 states and the District of Columbia. There are annual 

emissions caps for SO2 and NOX and different states fall under each cap, as shown in the map in Figure 7, although all are in the 

eastern half of the United States. The caps for SO2 and NOX were set to allow states to achieve their National Ambient Air Quality 

Standards (NAAQS) for particulate matter (impacted by SO2 levels) and ground level ozone (impacted by NOX). Allowances can 

be traded amongst all participants in the CAAA90 Title IV program, not just those in CAIR states, however allowances are traded 

at a discount in non-CAIR states. AEO2013 represents emissions trading in both the CAIR and non-CAIR regions, as specified by 

the regulation, and includes banking of allowances consistent with CAIR’s provisions.

As specified in the CAAA90, EPA developed a two-phase nitrogen oxide (NOx) program, with the first set of standards for 

existing coal plants applied in 1996 while the second set was implemented in 2000. 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 between 25 and 50 percent to meet the Phase I limits and 

further reductions to meet the Phase II limits. The EPA did not impose limits on existing oil and gas plants, but some states have 

instituted additional NOx regulations. All new fossil units are required to meet current 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 combustion turbines. 

These NOx limits are incorporated in EMM.

Sample costs of adding flue gas desulfurization equipment (FGD) to remove sulfur dioxide (SO2) and selective catalytic reduction 

(SCR) equipment to remove nitrogen oxides (NOx) are given below for 100, 300, 500, and 700-megawatt coal plants. In the 

EMM, plant-specific costs are calculated based on the size of the unit and other operating characteristics. FGD units are assumed 

to remove 95 percent of the SO2, while SCR units are assumed to remove 90 percent of the NOx. The EMM also includes an 

option to install a dry sorbent injection (DSI) system, which is assumed to remove 70 percent of the SO2. However, the DSI option 

is only available under the mercury and air toxics rule discussed in the next section, as its primary benefit is for reducing hydrogen 

chloride (HCl). The costs per megawatt of capacity decline with plant size and are shown in Table 8.7.

Figure 7. States covered by the Clean Air Interstate Rule

Source: U.S. Environmental Protection Agency, Clean Air Interstate Rule—Where You Live (Washington, DC, July 31, 2012), 

website http://www.epa.gov/cair/where.html.
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Electricity Market Module

Table 8.7. Coal plant retrofit costs

2011 dollars

Coal Plant Size (MW) FGD Capital Costs ($/kW) SCR Capital Costs ($/kW) DSI Capital Costs ($/kW)

100 695 280 128

300 538 213 58

500 454 191 41

700 395 179 32

Documentation for EPA Base Case v4.10 using the Integrated Planning Model, August 2010, EPA Contract EP-W-08-018.

Mercury regulation

The Mercury and Air Toxics Standards (MATS) were finalized in December 2011 to fulfill EPA’s requirement to regulate 

mercury emissions from power plants. MATS also regulates other hazardous air pollutants (HAPS) such as hydrogen chloride 

(HCl) and fine particulate matter (PM2.5). MATS applies to coal- and oil-fired power plants with a nameplate capacity greater 

than 25 megawatts. The standards are scheduled to take effect in 2015, but allow for a one year waiver to comply, and require 

that all qualifying units achieve the maximum achievable control technology (MACT) for each of the three covered pollutants. 

For AEO2013, EIA assumes that all coal-fired generating units with a capacity greater than 25 megawatts will comply with the 

rule beginning in 2016, due to the large number of plants requesting the one year extension. All power plants are required to 

reduce their mercury emissions to 90 percent below their uncontrolled emissions levels.

Because the EMM does not explicitly model HCl or PM2.5, specific control technologies are assumed to be used to achieve 

compliance. In order to meet the HCl requirement, units must have either flue gas desulfurization (FGD) scrubbers or dry 

sorbent injection (DSI) systems in order to continue operating. A full fabric filter is also required to meet the PM2.5 limits and 

to improve the effectiveness of the DSI technology. When plants alter their configuration by adding equipment such as an SCR 

to remove NOx or an SO2 scrubber, removal of mercury is often a resulting cobenefit. The EMM considers all combinations 

of controls and may choose to add NOX or SO2 controls purely to lower mercury if it is economic to do so. Plants can also 

add activated carbon injection systems specifically designed to remove mercury. Activated carbon can be injected in front of 

existing particulate control devices or a supplemental fabric filter can be added with activated carbon injection capability.

The equipment to inject activated carbon in front of an existing particulate control device is assumed to cost approximately 

$6 (2011 dollars) per kilowatt of capacity, while the cost of a supplemental fabric filter with activated carbon injection (often 

referred as a COPAC unit) is approximately $153 (2011 dollars) per kilowatt of capacity [2]. The amount of activated carbon 

required to meet a given percentage removal target is given by the following equations [3]. 

For a unit with a cold side electrostatic precipitator (CSE), using subbituminous coal, and simple activated carbon injection:

• Hg Removal (%) = 65 - (65.286 / (ACI + 1.026)) 

For a unit with a CSE, using bituminous coal, and simple activated carbon injection: 

• Hg Removal (%) = 100 - (469.379 / (ACI + 7.169)) 

For a unit with a CSE, and a supplemental fabric filter with activated carbon injection: 

• Hg Removal (%) = 100 - (28.049 / (ACI + 0.428)) 

For a unit with a hot side electrostatic precipitator (HSE) or other particulate control, and a supplemental fabric filter with 

activated carbon injection: 

• Hg Removal (%) = 100 - (43.068 / (ACI + 0.421)) 

ACI = activated carbon injection rate in pounds per million actual cubic feet of flue gas. 
112 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2013

Electricity Market Module

Power plant mercury emissions assumptions 

The EMM represents 35 coal plant configurations and assigns a mercury emissions modification factor (EMF) to each configuration. 

Each configuration represents different combinations of boiler types, particulate control devices, sulfur dioxide (SO2) control 

devices, nitrogen oxide (NOx) control devices, and mercury control devices. An EMF represents the amount of mercury that was 

in the fuel that remains after passing through all the plant’s systems. For example, an EMF of 0.60 means that 40 percent of the 

mercury that was in the fuel is removed by various parts of the plant. Table 8.8 provides the assumed EMFs for existing coal plant 

configurations without mercury-specific controls.

Table 8.8. Mercury emission modification factors

Configuration EIA EMFs EPA EMFs

SO2 Control Particulate Control

NOx 

Control Bit Coal Sub Coal Lignite Coal Bit Coal Sub Coal Lignite Coal

None BH -- 0.11 0.27 0.27 0.11 0.26 1.00

Wet BH None 0.05 0.27 0.27 0.03 0.27 1.00

Wet BH SCR 0.10 0.27 0.27 0.10 0.15 0.56

Dry BH -- 0.05 0.75 0.75 0.50 0.75 1.00

None CSE -- 0.64 0.97 0.97 0.64 0.97 1.00

Wet CSE None 0.34 0.73 0.73 0.34 0.84 0.56

Wet CSE SCR 0.10 0.73 0.73 0.10 0.34 0.56

Dry CSE -- 0.64 0.65 0.65 0.64 0.65 1.00

None HSE/Oth -- 0.90 0.94 0.94 0.90 0.94 1.00

Wet HSE/Oth None 0.58 0.80 0.80 0.58 0.80 1.00

Wet HSE/Oth SCR 0.42 0.76 0.76 0.10 0.75 1.00

Dry HSE/Oth -- 0.60 0.85 0.85 0.60 0.85 1.00

Notes: SO2 Controls - Wet = Wet Scrubber and Dry = Dry Scrubber, Particulate Controls, BH - fabric filter/baghouse. CSE = cold side electrostatic 

precipitator, HSE = hot side electrostatic precipitator, NOx Controls, SCR = selective catalytic reduction, 

— = not applicable, Bit = bituminous coal, Sub = subbituminous coal. The NOx control system is not assumed to enhance mercury removal unless a wet 

scrubber is present, so it is left blank in such configurations. Sources: EPA, EMFs. www.epa.gov/clearskies/technical.html. EIA EMFs not from EPA: Lignite 

EMFs, Mercury Control Technologies for Coal-Fired Power Plants, presented by the Office of Fossil Energy on July 8, 2003. Bituminous coal mercury removal 

for a Wet/HSE/Oth/SCR configured plant, Table EMF1, Analysis of Mercury Control Cost and Performance, Office of Fossil Energy & National Energy 

Technology Laboratory, U.S. Department of Energy, January 2003, Washington, DC.

Planned SO2 Scrubber and NOx control equipment additions

EIA assumes that all planned retrofits, as reported on the Form EIA-860, will occur as currently scheduled. For AEO2013, this 

includes 17.7 gigawatts of planned SO2 scrubbers (Table 8.9) and 9.5 gigawatts of planned selective catalytic reduction (SCR).

Carbon capture and sequestration retrofits 

Although a Federal greenhouse gas program is not assumed in the AEO2013 Reference case, the EMM includes the option of 

retrofitting existing coal plants for carbon capture and sequestration (CCS). This option is important when considering alternate 

scenarios that do constrain carbon emissions. The modeling structure for CCS retrofits within the EMM was developed by the 

National Energy Technology Laboratory[4] and uses a generic model of retrofit costs as a function of basic plant characteristics 

(such as heatrate). The costs have been adjusted to be consistent with costs of new CCS technologies. The CCS retrofits are 

assumed to remove 90 percent of the carbon input. The addition of the CCS equipment results in a capacity derate of around 30 

percent and reduced efficiency of 43 percent at the existing coal plant. The costs depend on the size and efficiency of the plant, with 

the capital costs ranging from $1,250 to $1,650 per kilowatt. It was assumed that only plants greater than 500 megawatts and with 

heat rates below 12,000 BTU per kilowatthour would be considered for CCS retrofits.

State air emissions regulation

AEO2013 continues to model the Northeast Regional Greenhouse Gas Initiative (RGGI), which applies to fossil-fuel powered plants 

over 25 megawatts in the Northeastern United States. The State of New Jersey withdrew from the program at the end of 2011, 

leaving nine states in the accord. The rule caps CO2 emissions from covered electricity generating facilities and requires that they 

account for each ton of CO2 emitted with an allowance purchased at auction. Because the baseline and projected emissions were 

calculated before the economic recession that began in 2008, the actual emissions in the first years of the program have been less 

than the cap, leading to excess allowances and allowance prices at the floor price.
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The California Assembly Bill 32 (AB 32), the Global Warming Solutions Act of 2006, authorized the California Air Resources Board 

(CARB) to set California’s GHG reduction goals for 2020 and establish a comprehensive, multi-year program to reduce GHG 

emissions in California. As one of the major initiatives for AB 32, CARB designed a cap-and-trade program that started on January 

1, 2012, with the enforceable compliance obligations beginning in 2013 for the electric power sector and industrial facilities. Fuel 

providers must comply starting in 2015. The AB32 cap-and-trade provisions are incorporated in AEO2013 through an emission 

constraint in the EMM that also accounts for the emissions determined by the other sectors. An allowance price is calculated and 

added to fuel prices for the affected sectors. Limited banking and borrowing of allowances as well as an allowance reserve and 

offsets have been modeled, as specified in the Bill, providing some compliance flexibility and cost containment.

Table 8.9. Planned SO2 scrubber additions by EMM region

gigawatts

Texas Reliability Entity 0.0

Florida Reliability Coordinating Council 0.0

Midwest Reliability Council - East 0.0

Midwest Reliability Council - West 1.2

Northeast Power Coordinating Council/New England 0.5

Northeast Power Coordinating Council/NYC-Westchester 0.0

Northeast Power Coordinating Council/Long Island 0.0

Northeast Power Coordinating Council/Upstate 1.0

ReliabilityFirst Corporation/East 0.0

ReliabilityFirst Corporation/Michigan 1.4

ReliabilityFirst Corporation/West 6.1

SERC Reliability Corporation/Delta 0.0

SERC Reliability Corporation/Gateway 3.0

SERC Reliability Corporation/Southeastern 2.5

SERC Reliability Corporation/Central 0.2

SERC Reliability Corporation/Virginia-Carolina 0.0

Southwest Power Pool/North 1.4

Southwest Power Pool/South 0.0

Western Electricity Coordinating Council/Southwest 0.4

Western Electricity Coordinating Council/California 0.0

Western Electricity Coordinating Council/Northwest Power Pool Area 0.0

Western Electricity Coordinating Council/Rockies 0.0

Total 17.7

Source: U.S. Energy Information Administration, Form EIA-860, “Annual Electric Generator Report.”

Energy Policy Acts of 1992 (EPACT92) and 2005 (EPACT05) 

The provisions of the EPACT92 include revised licensing procedures for nuclear plants and the creation of exempt wholesale 

generators (EWGs). The EPACT05 provides a 20-percent investment tax credit for Integrated Coal-Gasification Combined Cycle 

capacity and a 15-percent investment tax credit for other advanced coal technologies. These credits are limited to 3 gigawatts

in both cases. It also contains a production tax credit (PTC) of 1.8 cents (nominal) per kilowatthour for new nuclear capacity 

beginning operation by 2020. This PTC is specified for the first 8 years of operation, is limited to $125 million annually, and is 

limited to 6 gigawatts of new capacity. However, this credit may be shared to additional units if more than 6 gigawatts are under 

construction by January 1, 2014. EPACT05 extended the PTC for qualifying renewable facilities by 2 years, or December 31, 2007. It 

also repealed the Public Utility Holding Company Act (PUHCA).

Energy Improvement and Extension Act 2008 (EIEA2008) 

EIEA2008 extended the investment tax credit of 30 percent through 2016 for solar and fuel cell facilities.

American Recovery and Reinvestment Act (ARRA) 

Updated tax credits for Renewables 

ARRA extended the expiration date for the PTC to January 1, 2013, for wind and January 1, 2014, for all other eligible renewable 

resources. In addition, ARRA allows companies to choose an investment tax credit (ITC) of 30 percent in lieu of the PTC and allows 

for a grant in lieu of this credit to be funded by the U.S. Treasury. For some technologies, such as wind, the full PTC would appear to 

be more valuable than the 30 percent ITC; however, the difference can be small. Qualitative factors, such as the lack of partners with 

sufficient tax liability, may cause companies to favor the ITC grant option. AEO2013 generally assumes that renewable electricity 

projects will claim the more favorable tax credit or grant option available to them.
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Electricity Market Module

Loan guarantees for renewables

ARRA provided $6 billion to pay the cost of guarantees for loans authorized by the Energy Policy Act of 2005. While most 

renewable projects which started construction prior to September 30, 2011 are potentially eligible for these loan guarantees, the 

application and approval of guarantees for specific projects is a highly discretionary process, and has thus far been limited. While 

AEO2013 includes projects that have received loan guarantees under this authority, it does not assume automatic award of the loans 

to potentially eligible technologies. 

Support for CCS

ARRA provided $3.4 billion for additional research and development on fossil energy technologies. A portion of this funding is 

expected to be used to fund projects under the Clean Coal Power Initiative program, focusing on projects that capture and sequester 

greenhouse gases. To reflect the impact of this provision, AEO2013 Reference case assumes that an additional 1 gigawatt of coal 

capacity with CCS will be stimulated by 2018.

Smart grid expenditures 

ARRA provides $4.5 billion for smart grid demonstration projects. While somewhat difficult to define, smart grid technologies 

generally include a wide array of measurement, communications, and control equipment employed throughout the transmission 

and distribution system that will enable real-time monitoring of the production, flow, and use of power from the generator to the 

consumer. Among other things, these smart grid technologies are expected to enable more efficient use of the transmission and 

distribution grid, lower line losses, facilitate greater use of renewables, and provide information to utilities and their customers that 

will lead to greater investment in energy efficiency and reduced peak load demands. The funds provided will not fund a widespread 

implementation of smart grid technologies, but could stimulate more rapid investment than would otherwise occur.

Several changes were made throughout the NEMS to represent the impacts of the smart grid funding provided in ARRA. In the 

electricity module, it was assumed that line losses would fall slightly, peak loads would fall as customers shifted their usage 

patterns, and customers would be more responsive to pricing signals. Historically, line losses, expressed as the percentage of 

electricity lost, have been falling for many years as utilities make investments to replace aging or failing equipment.

Smart grid technologies also have the potential to reduce peak demand through the increased deployment of demand response 

programs. In AEO2013, it is assumed that the Federal expenditures on smart grid technologies will stimulate efforts that reduce 

peak demand from what they otherwise would be, with the amount of total peak load reduction growing from 2.2 percent initially 

to 3.5 percent by 2040, although the shifts vary by region. Load is shifted to offpeak hours, so net energy consumed remains largely 

constant.

FERC Orders 888 and 889

FERC 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 and 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 an Open Access SameTime Information System (OASIS) through which utilities and non-utilities can receive information regarding the transmission 

system. As a result, utilities have functionally or physically unbundled their marketing functions from their transmission functions.

These orders are represented in EMM by assuming that all generators in a given region are able to satisfy load requirements 

anywhere within the region. Similarly, it is assumed that transactions between regions will occur if the cost differentials between 

them make such transactions economical. 

Electricity alternative cases 

Nuclear Alternative cases

For AEO2013, three alternate cases were run for nuclear power plants to address uncertainties about the operating lives of existing 

reactors, the potential for new nuclear capacity, and capacity uprates at existing plants. These scenarios are discussed in the Issues 

in Focus article, “Nuclear Power in AEO2013” in the full AEO2013 report.
U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2013 115

Electricity Market Module

• The Low Nuclear case assumes that all existing reactors will not receive a second license renewal and are retired within 60 

years of operation. The reported retirement at Oyster Creek occurs as currently planned, at the end of 2019. Kewaunee is also 

retired in this case, at the end of 2014, based on an announcement by Dominion Resources in late 2012. Additionally, two units 

that are currently out of service are assumed to be permanently shut down in the Low Nuclear case. San Onofre 2 and Crystal 

River 3 are not currently operating, but are assumed to be returned to service in 2015 in the Reference case. In the Low Nuclear 

Case both units are assumed to retire in 2013. In the Reference case, existing plants are assumed to run as long as they continue 

to be economic, implicitly assuming that a second 20-year license renewal will be obtained for most plants reaching 60 years 

of age before 2040. The Low Nuclear case was run to analyze the impact of additional nuclear retirements, which could occur 

if the oldest plants do not receive a second license extension. In this case, 45 gigawatts of nuclear capacity are assumed to 

be retired by 2040. This case assumes that no new nuclear capacity will be added throughout the projection, excluding the 

capacity already planned and under construction. The case also assumes that only those capacity uprates reported to EIA will be 

completed. In contrast, the Reference case assumes additional uprates based on Nuclear Regulatory Commission (NRC) surveys 

and industry reports.

• The High Nuclear case assumes that all existing nuclear units will receive a second license renewal and operate beyond 60 years 

(excluding one announced retirement). In the Reference case, beyond the announced retirement of Oyster Creek, an additional 

6.5 gigawatts of nuclear capacity is assumed to be retired through 2040, reflecting uncertainty surrounding future aging impacts 

and/or costs. This case was run to provide a more optimistic outlook where all licenses are renewed and all plants are assumed 

to find it economic to continue operating beyond 60 years. The High Nuclear case also assumes additional planned nuclear 

capacity is completed based on combined license (COL) applications with the NRC. The Reference case assumes 5.5 gigawatts 

of planned capacity are added, while the High Nuclear case includes 13.3 gigawatts of planned capacity additions.

• The Small Modular Reactor case assumes that new advanced nuclear plants built in the forecast will be based on a smaller 

modular design rather than the larger AP1000 design used in the Reference case. The overnight costs are assumed to be the 

same as in the Reference case, but the construction lead time is reduced from six years to three years for the smaller design. The 

fixed operating and maintenance costs are assumed to be higher for the smaller design. To account for the necessary time for 

design certification, the first available online date for the small reactors is assumed to be 2025.
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Electricity Market Module

Notes and sources

[1] Review of Power Plant Cost and Performance Assumptions for NEMS, Science Applications International Corporation, 

April 2013. The costs shown Table 8.2 and used for the AEO2013 were based on a draft report provided in September 

2012 and may vary slightly from the published final report.

[2] These costs were developed using the National Energy Technology Laboratory Mercury Control Performance and

Cost Model, 1998.

[3] U.S. Department of Energy, Analysis of Mercury Control Cost and Performance, Office of Fossil Energy & National

Energy Technology Laboratory, January 2003.

[4] Retrofitting Coal-Fired Power Plants for Carbon Dioxide Capture and Sequestration - Exploratory Testing of NEMS for

Integrated Assessments, DOE/NETL-2008/1309, P.A. Geisbrecht, January 18, 2009.