4-1 

4 Generating Resources 

“Existing”, “planned-committed”, and “potential” are the three general types of generating units 

modeled in EPA Base Case v.4.10. Units that are currently operational in the electric industry are 

termed as “existing” units. Units that are not currently operating but are firmly anticipated to be 

operational in the future, and have either broken ground (initiated construction) or secured 

financing are termed “planned-committed”. “Potential” units refer to new generating options used 

in IPM for capacity expansion projections of the electric industry. Existing and planned-committed 

units are entered as exogenous inputs to the model, whereas potential units are endogenous to 

the model in the sense that the model determines the location and size of all the potential units 

that end up in the final solution for a specific model run. 

This chapter is organized into the following five sections: 

(1) Section 4.1 provides background information on the National Electric Energy Data System 

(NEEDS), the database which serves as the repository for information on existing and 

planned-committed units which are modeled in the EPA Base Case v.4.10, 

(2) Section 4.2 provides detailed information on existing non-nuclear generating units 

modeled in EPA Base Case v.4.10, 

(3) Section 4.3 provides detailed information pertaining to planned-committed units which are 

assumed in EPA Base Case v.4.10, 

(4) Section 4.4 provides detailed information pertaining to the IPM assumptions for potential 

plants, and 

(5) Section 4.5 describes the handling of existing and potential nuclear units in EPA Base 

Case v.4.10 

4.1 National Electric Energy Data System (NEEDS) 

EPA Base Case v.4.10 uses the NEEDS database as its source for data on all existing and 

planned-committed units. Table 4-1 below summarizes the resources used in developing data on 

existing units in NEEDS v.4.10. The data sources for planned-committed units in NEEDS are 

discussed below in Section 4.3. The population of existing units in NEEDS v4.10 represents 

generating units that were in operation through the end of 2006. The population of plannedcommitted includes any units online or scheduled to come online from 2007 to the end of 2011 

(with two exceptions listed in the note under Table 4-2 below). 

4.2 Existing Units 

EPA Base Case v.4.10 models existing units based on information contained in NEEDS. The 

sections below describe the procedures followed in determining the population of units in NEEDS, 

as well as each unit’s capacity, location, and configuration. Details are also given on the model 

plant aggregation scheme and the cost and performance characteristics associated with the 

existing non-nuclear units represented in EPA Base Case v.4.10. 

4.2.1 Population of Existing Units 

The population of existing units was taken primarily from EIA 860 (2006) and EIA 767 (2005). A 

number of rules were used to screen the various data sources. These rules helped to ensure data 

consistency, but also made the population data adaptable for use in IPM. Table 4-2 below 

summarizes the rules used in populating the NEEDS v.4.10 database. 
4-2 

Table 4-1 Data Sources for NEEDS v.4.10 for EPA Base Case v.4.10 

Data Source1 Data Source Documentation 

DOE's Form EIA-860 

DOE's Form EIA-860 is an annual survey of utility power plants at the 

generator level. It contains data such as summer, winter and 

nameplate capacity, location (state and county), status, prime mover, 

primary energy source and in-service year. NEEDS v.4.10 uses EIA 

Form 860 (2006) data as one of the primary data inputs. 

DOE's Form EIA-767 

DOE's Form EIA-767 is an annual survey, "Steam-Electric Plant 

Operation and Design Report", that contains data for utility nuclear and 

fossil fuel steam boilers such as fuel quantity and quality; boiler 

identification, location, status, and design information; and postcombustion NOX control, FGD scrubber and particulate collector device 

information. Note that boilers in plants with less than 10 MW do not 

report all data elements. The relationship between boilers and 

generators is also provided, along with generator-level generation and 

nameplate capacity. Note that boilers and generators are not 

necessarily in a one-to-one correspondence. NEEDS v.4.10 uses EIA 

Form 767 (2005) data as one of the primary data inputs. 

NERC Electricity 

Supply and Demand 

(ES&D) database 

The NERC ES&D is released annually. It contains generator-level 

information such as summer, winter and nameplate capacity, state, 

NERC region and sub-region, status, primary fuel and on-line year. 

NEEDS v.4.10 uses NERC ES&D (2006) data as one of the primary 

data inputs. 

DOE’s Annual Energy 

Outlook (AEO) 

The Energy Information Administration (EIA) Annual Energy Outlook 

presents annually updated forecasts of energy supply, demand and 

prices covering a 20-25 year time horizon. The projections are based 

on results from EIA’s National Energy Modeling System (NEMS). 

Information from AEO such as heat rates, planned committed units, 

nuclear unit capacities and uprates were used in NEEDS v.4.10. 

Global Energy 

Decisions New 

Entrants database 

Global Energy’s New Entrants database has information on new power 

plant builds, rerates and retirements. Information on committed units is 

based on November 2009 dataset. 

EPA's Emission 

Tracking System 

(ETS 2007) 

The Emission Tracking System (ETS) database is updated quarterly. It 

contains boiler-level information such as primary fuel, heat input, SO2

and NOX controls, and SO2 and NOX emissions. 

Utility and RPO 

(Regional Planning 

Organizations) 

Comments 

Comments from selected U.S. utilities and RPOs regarding the 

population in NEEDS as well as unit characteristics were used in 

NEEDS v.4.10. 

Note:

1

 Shown in Table 4-1 are the primary issue dates of the indicated data sources that were used. 

Other vintages of these data sources were also used in instances where date were not 

available for the indicated issued date or where there were methodological reasons for using 

other vintages of the data. 
4-3 

Table 4-2 Rules Used in Populating NEEDS v.4.10 for EPA Base Case v.4.10 

Scope Rule 

Capacity Excluded units with reported nameplate, summer and winter capacity 

of zero 

Status 

Excluded units that were out of service for two or three consecutive 

years (i.e., generators with status codes “OS” in the latest three 

reporting years and boilers with status codes “OS” in the latest two 

reporting years) and units that were no longer in service and not 

expected to be returned to service (i.e., generators or boilers with 

status codes of "RE"). Status of boiler(s) and associated generator(s) 

were taken into account for determining operation status 

Planned or Committed 

Units 

Included planned units that had broken ground or secured financing 

and were expected to be online by the end of 2011; one biomass and 

one nuclear unit that are scheduled to come online after 2011 were 

also included 

Firm/Non-firm Electric 

Sales 

Excluded non-utility onsite generators that do not produce electricity 

for sale to the grid. 

Excluded all mobile and distributed generators 

Note:

1

The biomass unit is Mitchell, unit 3, and the nuclear unit is Watts Bar Nuclear Plant, unit 2. 

As with previous versions of the database, NEEDS v.4.10 includes steam units at the boiler level 

and non-steam units at the generator level. A unit in NEEDS v.4.10, therefore, refers to a boiler in 

the case of a steam unit and a generator in the case of a non-steam unit. Table 4-3 provides a 

summary of the population and capacity of the existing units included in NEEDS v.4.10 through 

2006. EIA Form 860 (2006) and Form 767 (2005) is the starting point and largest component of 

the existing unit population in NEEDS v.4.10 but the final population of existing units is 

supplemented based on information from other sources, including comments from utilities, 

submissions to EPA's Emission Tracking System, Annual Energy Outlook, and reported capacity 

in Global Energy’s New Entrants database. 

Table 4-3 Summary Population (through 2006) of Existing Units in NEEDSv.4.10 for EPA 

Base Case v.4.10 

Plant Type Number of Units Capacity (MW) 

Biomass 134 2,286 

Coal Steam 1,235 305,451 

Combined Cycle 1,532 179,557 

Combustion Turbine 5,386 132,293 

Fossil Waste 20 610 

Geothermal 196 2,264 

Hydro 3,754 77,713 

IGCC 4 529 

Landfill Gas 698 1,068 

Municipal Solid Waste 176 2,098 

Non-Fossil Waste 45 516 

Nuclear 104 101,099 

O/G Steam 682 112,371 

Pumped Storage 150 20,940 

Solar 19 412 

Tires 3 44 

Wind 330 11,637 

Grand Total 14,468 950,889 
4-4 

4.2.2 Capacity 

The NEEDS unit capacity values implemented in EPA Base Case v.4.10 reflect net summer 

dependable capacity16, to the extent possible. Table 4-4 summarizes the hierarchy of primary 

data sources used in compiling capacity data for NEEDS v.4.10. 

Table 4-4 Hierarchy of Data Sources for Capacity in NEEDS v.4.10 

Sources Presented in Hierarchy 

Capacity from Utility Comments 

2006 EIA 860 Summer Capacity 

NERC ES&D 2006 Summer Capacity 

2006 EIA 860 Winter Capacity 

NERC ES&D 2006 Winter Capacity 

2006 EIA 860 Nameplate Capacity 

Notes: 

Presented in hierarchical order that applies. 

If capacity is zero, unit is not included. 

As noted earlier, for steam units NEEDS v.4.10 includes boiler level data, while for non-steam 

units NEEDS v.4.10 contains generator level data. Capacity data in EIA and NERC data sources 

are generator specific and not boiler specific. Therefore, it was necessary to develop an algorithm 

for parsing generator level capacity to the boiler level for steam producing units. 

The capacity-parsing algorithm used for steam units in NEEDS v.4.10 took into account boilergenerator mapping. Fossil steam and nuclear steam electric units have boilers attached to 

generators that produce electricity. There are generally four types of links between boilers and 

generators: one boiler to one generator, one boiler to many generators, many boilers to one 

generator and many boilers to many generators. 

The capacity-parsing algorithm used for steam units in NEEDS utilized steam flow data with the 

boiler-generator mapping. Under EIA 767, steam units report the maximum steam flow from the 

boiler to the generator. There is, however, no further data on the steam flow of each boilergenerator link. Instead, EIA 767 contains only the maximum steam flow for each boiler. Table 4-5 

summarizes the algorithm used for parsing capacity with data on maximum steam flow and boilergenerator mapping. In Table 4-5 MFBi

 refers to the maximum steam flow of boiler i and MWGj

refers to the capacity of generator j. The algorithm uses the available data to derive the capacity 

of a boiler, referred to as MWBj

 in Table 4-5. 

Table 4-5 Capacity-Parsing Algorithm for Steam Units in NEEDS v.4.10 

Type of Boiler-Generator Links 

For Boiler B1 One-to-One One-to-Many Many-to-One Many-to-Many 

to BN linked to 

Generators 

G1 to GN

MWBi = 

MWGj

MWBi = 

ΣjMWGj

MWBi = 

(MFBi / ΣiMFBi) * MWGj

MWBi = 

(MFBi / ΣiMFBi) * ΣjMWGj

Notes:

MFBi = maximum steam flow of boiler i 

MWGj = electric generation capacity of generator j

 

16As used here, net summer dependable capacity is the net capability of a generating unit in 

megawatts (MW) for daily planning and operation purposes during the summer peak season, after 

accounting for station or auxiliary services. 
4-5 

Since EPA Base Case v.4.10 uses net energy for load as demand, NEEDS v.4.10 only includes 

generators that sell the majority of their power to the electric grid in order to be consistent with 

demand. The generators that should be in NEEDS v.4.10. by this qualification are determined 

from the 2005 EIA Form 906 non-utility source and disposition data set. 

4.2.3 Plant Location 

NEEDS v.4.10 uses state, county and model region data to represent the physical location of each 

plant. 

State and County

NEEDS v.4.10 used the state and county data in EIA 860 (2006) 

Model Region

For each unit the associated model region was derived based on NERC regions and sub-regions 

reported in NERC ES&D 2006 for that unit. For units with no NERC sub-region data, NERC 

region and state were used to derive associated model regions. For units with no NERC region 

data, state and county were used to derive associated model regions. Table 3-1 in Chapter 3 

provides a summary of the mapping between NERC regions and EPA Base Case v.4.10 model 

regions. 

4.2.4 Online Year 

The EPA Base Case v.4.10 uses online year to capture when the unit entered service. NEEDS 

includes online years for all units in the database. In NEEDS v.4.10, online years for boilers, utility 

and non-utility generators were primarily derived from reported in-service dates in EIA 767 2005 

and EIA 860 2006 respectively. 

EPA Base Case v.4.10 does not include any assumption about the retirement year for generating 

units, except for existing nuclear units which must retire when they reach age 60. (See section 

3.7 for a discussion of the nuclear lifetime assumption.) EPA Base Case v.4.10 does, however, 

provide economic retirement options to coal, oil and gas steam, combined cycle, combustion 

turbines, and nuclear units. This means that the model may elect to retire these units if it is 

economical to do so. In IPM, an early retired plant ceases to incur FOM and VOM costs. 

However, retired units do meet capital cost obligations for retrofits if the model projected a retrofit 

on the unit prior to retirement. 

4.2.5 Unit Configuration 

Unit configuration refers to the physical specification of a unit’s design. Unit configuration in EPA 

Base Case v.4.10 drives model plant aggregation, modeling of pollution control options and 

mercury emission modification factors. NEEDS v.4.10 contains information on the firing and 

bottom type of coal steam boilers in the database. Great effort was taken to see that the inventory 

of existing and committed controls represented in EPA Base Case v.4.10 was comprehensive and 

as up-to-date as possible. The hierarchy of data sources used is shown in Table 4-6. 

4.2.6 Model Plant Aggregation 

While IPM is comprehensive in representing all the units contained in NEEDS, an aggregation 

scheme is used to combine existing units with similar characteristics into “model plants”. The 

aggregation scheme serves to reduce the size of the model and makes the model manageable 

while capturing the essential characteristics of the generating units. The EPA Base Case v.4.10 

aggregation scheme is designed so that each model plant only represents generating units from a 

single state. This design makes it possible to obtain state-level results directly from IPM outputs. 

In addition, the aggregation scheme supports modeling plant-level emission limits on fossil 

generation 

The “model plant” aggregation scheme encompasses a variety of different classification 

categories including location, size, technology, heat rate, fuel choices, unit configuration, SO2
4-6 

emission rates and environmental regulations among others. Units are aggregated together only 

if they match on all the different categories specified for the aggregation. The 10 major categories 

used for the aggregation scheme in EPA Base Case v.4.10 are the following: 

(1) Model Region 

(2) Unit Technology Type 

(3) Fuel Demand Region 

(4) Applicable Environmental Regulations 

(5) State 

(6) Unit Configuration 

(7) Emission Rates 

(8) Heat Rates 

(9) Fuel 

(10) Size 

Table 4-6 Data Sources for Unit Configuration in NEEDS v.4.10 for EPA Base Case v.4.10 

Unit 

Component Primary Data Source Secondary Data Source 

Tertiary 

Data 

Source 

Other 

Sources Default 

Firing Type Utility/RPO Comments 2005 EIA 767 -- -- -- 

Bottom Type Utility/RPO Comments 2005 EIA 767 -- -- Dry 

SO2 Pollution 

Control 

NSR Settlement or 

Utility/RPO Comments 

EPA’s Emission 

Tracking System 

(ETS) - 2006 

2005 EIA 

767 See Note No Control 

NOx Pollution 

Control 

NSR Settlement or 

Utility/RPO Comments 

EPA’s Emission 

Tracking System 

(ETS) - 2006 

2005 EIA 

767 See Note No Control 

Particulate 

Matter 

Control 

NSR Settlement or 

Utility/RPO Comments 

EPA’s Emission 

Tracking System 

(ETS) - 2006 

2005 EIA 

767 

1999 Hg 

ICR -- 

Note:

In addition to the primary, secondary and tertiary data sources listed here, the following sources 

were consulted and emission controls were updated when corroborating information could be 

found: McILVAINE Utility Upgrade Database, ICAC (Institute of Clean Air Companies), and web 

sites of generating unit owners and operators. 

Table 4-7 provides a crosswalk between actual plants and the aggregated “model plants” used in 

the EPA Base Case v.4.10. For each plant type, the table shows the number of real plants and 

the number of model plants representing these real plants in EPA Base Case v.4.10.17

 

17For readers interested in the intricacies of Table 4-7, here are several observations: (1) 

Depending on its capacity and fuel types combusted, an existing coal steam model plant may be 

provided with multiple scrubber and ACI retrofit options. As a result the total number of model 

plants representing scrubber and ACI retrofits may exceed the total number of model plants 

representing existing coal steam units. (See chapter 5 for a detailed description of the sulfur 

dioxide (scrubber) and mercury (ACI) retrofit options.) (2) The “Number of IPM Model Plants” 

shown for many of the “Plant Types” in the “Retrofits” block in Table 4-7 exceeds the “Number of 

IPM Model Plants” shown for “Plant Type” “Coal Steam” in the block labeled “Existing and 

Planned/Committed Units”, because a particular retrofit “Plant Type” can include multiple 

technology options and multiple timing options (e.g., Technology A in Stage 1 + Technology B in 

Stage 2, the reverse timing, or both technologies simultaneously in Stage 1). (3) Since only a 

subset of coal plants is eligible for certain retrofits, many of the “Plant Types” in the “Retrofits” 

block that represent only a single retrofit technology (e.g., “Retrofit Coal with Selective 

Noncatalytic Reduction (SNCR)”) have a “Number of of IPM Model Plants” that is a smaller than 
4-7 

Table 4-7 Aggregation Profile of Model Plants as Provided at Set Up of EPA Base Case 

v.4.10 

Existing and Planned/Committed Units 

Plant Type Number of 

Units 

Number of IPM 

Model Plants 

Biomass 161 71 

Coal Steam 1,267 913 

Combined Cycle 1,627 610 

Combustion Turbine 5,474 2,225 

Fossil_Other 21 14 

Fuel Cell 4 4 

Geothermal 211 8 

Hydro 3,771 99 

Import 2 2 

Integrated Gas Combined Cycle 6 5 

Landfill Gas 747 59 

Non Fossil_Other1 241 73 

Nuclear2 105 105 

Oil/Gas Steam 685 435 

Pumped Storage 151 21 

Solar 92 37 

Wind 458 57 

Total 15,023 4,738 

New Units 

Plant Type Number of 

Units 

Number of IPM 

Model Plants 

New Biomass -- 64 

New Coal with Carbon Capture -- 754 

New Combined Cycle -- 32 

New Combustion Turbine -- 32 

New Fuel Cell -- 32 

New Future Technology -- 160 

New Geothermal -- 26 

New IGCC -- 58 

New Landfill Gas -- 96 

New Nuclear -- 64 

New Offshore Wind -- 690 

New Onshore Wind -- 600 

New SPC-DryFGD_SCR_ACI 27 

New SPC-WetFGD_SCR -- 27 

New Solar Thermal -- 55 

New Solar PV -- 32 

 the “Number of IPM Model Plants” shown for “Plant Type” “Coal Steam”. (4) The total number of 

model plants representing different types of new units often exceeds the 32 model regions and the 

specific totals vary from technology to technology for several reasons. First, some technologies 

have multiple vintages, which must be represented by separate model plants in each IPM region. 

Second, some technologies are not available in particular regions (e.g., geothermal is 

geographically restricted to certain regions, conventional pulverized coal is not provided as an 

option in CA-N). 
4-8 

Total -- 2,749 

 

Retrofits 

Plant Type Number of 

Units 

Number of IPM 

Model Plants 

Retrofit Coal with Activated Carbon Injection (ACI) -- 427 

Retrofit Coal with ACI + SCR -- 1,076 

Retrofit Coal with ACI + SCR + Scrubber -- 1,575 

Retrofit Coal with ACI + SCR + Scrubber + CCS -- 1,708 

Retrofit Coal with ACI + SNCR + Scrubber -- 357 

Retrofit Coal with ACI + SNCR -- 447 

Retrofit Coal with ACI + SNCR + Scrubber + CCS -- 161 

Retrofit Coal with ACI + Scrubber -- 1,570 

Retrofit Coal with ACI + Scrubber + CCS -- 1,372 

Retrofit Coal with Selective Catalytic Reduction (SCR) -- 360 

Retrofit Coal with SCR + Scrubber -- 2,281 

Retrofit Coal with SCR + Scrubber + CCS -- 2,065 

Retrofit Coal with Selective Noncatalytic Reduction (SNCR) -- 141 

Retrofit Coal with SNCR + Scrubber -- 544 

Retrofit Coal with SNCR + Scrubber + CCS -- 112 

Retrofit Coal with Scrubber -- 587 

Retrofit Coal with Scrubber + CCS -- 1,078 

Retrofit Coal with CCS -- 14 

Retrofit Oil Gas with SCR -- 281 

Total -- 16,156 

Early Retirements 

Plant Type Number of 

Units 

Number of IPM 

Model Plants 

CC Early Retirement -- 610 

Coal Early Retirement -- 6,178 

CT Early Retirement -- 2,225 

IGCC Early Retirement -- 5 

Nuke Early Retirement -- 105 

O/G Early Retirement -- 435 

Total -- 9,558 

 

Grand Total (Existing and Planned/Committed + New + Retrofits + Early Retirements): 33,201 

 Notes:

1

Non Fossil_Other includes units whose fuel is municipal solid waste, tires, and other non-fossil waste. 

2

The 105 nuclear units include 104 currently operating units plus Watts Bar Nuclear Plant, Unit 2, which is 

scheduled to come online in 2014. All are listed in Appendix 4-3. 
4-9 

4.2.7 Cost and Performance Characteristics of Existing Units 

In EPA Base Case v.4.10 heat rates, emission rates, variable operation and maintenance cost 

(VOM) and fixed operation and maintenance costs (FOM) are used to characterize the cost and 

performance of all existing units in NEEDS v.4.10. For existing units, only the cost of maintaining 

(FOM) and running (VOM) the unit are modeled. Embedded costs, such as carrying capital 

charges, are not modeled. The section below contains a discussion of the cost and performance 

assumptions for existing units used in the EPA Base Case v.4.10. 

Variable Operating and Maintenance Cost (VOM)

VOM represents the non-fuel cost variable associated with producing a unit of electricity. If the 

generating unit contains pollution control equipment, VOM includes the cost of operating the 

control equipment. Table 4-8 below summarizes VOM assumptions used in EPA Base Case 

v.4.10. The values shown in this table were obtained using a procedure developed jointly by 

EPA’s power sector engineering staff and ICF. 

Table 4-8 VOM Assumptions (2007$) in EPA Base Case v.4.10 

Capacity Type SO2 Control Hg Control NOx Control 

Variable O&M 

Range 

(mills/kWh) 

No NOx 2.63 - 7.67 Combined Cycle -- -- SCR 2.75 - 7.79 

No NOx 3.66 - 5.05 

No Hg SCR 4.34 - 5.73 

SNCR 4.73 - 6.12 

No NOx 4.62 - 6.02 

SCR 5.30 - 6.69 

Scrubbed - Dry 

ACI 

SNCR 5.70 - 7.09 

No NOx 2.48 - 3.87 

No Hg SCR 3.16 - 4.55 

SNCR 3.55 - 4.94 

No NOx 3.44 - 4.83 

SCR 4.12 - 5.51 

Scrubbed - 

Wet 

ACI 

SNCR 4.51 - 5.91 

No NOx 0.90 - 2.29 

No Hg SCR 1.58 - 2.97 

SNCR 1.97 - 3.37 

No NOx 1.87 - 3.26 

SCR 2.54 - 3.94 

Coal Steam 

Unscrubbed 

ACI 

SNCR 2.94 - 4.33 

Conventional 

Hydroelectric -- -- -- 6.66 

No NOx 2.60 - 9.59 Combined Turbine -- No Hg SCR 2.73 - 9.71 

Fuel Cell -- -- -- 9.7 

Geothermal -- -- -- 8.3 

IGCC -- -- -- 0 - 4.72 

MSW/Landfill Gas -- -- -- 8.79 
4-10 

Capacity Type SO2 Control Hg Control NOx Control 

Variable O&M 

Range 

(mills/kWh) 

Scrubbed - No NOx 0.94 - 5.07 

Wet No Hg SNCR 1.49 - 5.62 

No NOx 0.94 - 5.07 

SCR 1.06 - 5.19 

Oil/Gas Steam 

Unscrubbed No Hg 

SNCR 1.49 - 5.62 

Pumped Storage -- -- -- 8.37 

Solar Photovoltaic -- -- -- 2.09 

Solar Thermal -- -- -- 2.78 

Wind -- -- -- 3.18 

Wood/Biomass -- -- -- 6.98 

Fixed Operation and Maintenance Cost (FOM)

FOM represents the annual fixed cost of maintaining a unit. FOM costs are incurred independent 

of achieved generation levels and signify the fixed cost of operating and maintaining the unit for 

generation. Table 4-9 summarizes the FOM assumptions used in EPA Base Case v.4.10. Note 

that FOM varies by the age of the unit. The values appearing in this table include the cost of 

maintaining any associated pollution control equipment. The values in Table 4-9 are based on 

FERC (Federal Energy Regulatory Commission) Form 1 data. 

Heat Rates

Heat Rates describe the efficiency of the unit expressed as BTUs per kWh. The treatment of heat 

rates in EPA Base Case v.4.10 is discussed in Section 3.8. 

Lifetimes

Unit lifetime assumptions in EPA Base Case v.4.10 are detailed in Sections 3.7 and 4.2.8. 

SO2 Rates

Section 3.9.1 contains a detailed discussion of SO2 rates for existing units. 

NOx Rates

Section 3.9.2 contains a detailed discussion of NOx rates for existing units. 

Mercury Emission Modification Factors (EMF)

Mercury EMF refers to the ratio of mercury emissions (mercury outlet) to the mercury content of 

the fuel (mercury inlet). Section 5.4.2 contains a detailed discussion of the EMF assumptions in 

EPA Base Case v.4.10. 

4.2.8 Life Extension Costs for existing units 

The usable modeling time horizon in previous EPA Base Cases typically extended out only as far 

as 2030 and covered a period of roughly 20-25 years. In contrast, the modeling time horizon in 

EPA Base Case 4.10 extends to 2050 covers a period of almost 40 years. Due to this longer time 

horizon, provision had to be made in EPA Base Case v.4.10 for investments (beyond the routine 

maintenance of the power plant) that would be required to extend the life of existing units over this 

longer time horizon. The life extension costs for units with retirement options are summarized in 

Table 4-10 below. These costs were based on a review of FERC Form 1 data regarding annual 

capital expenditures over the last 10 – 15 years of the power plan. 
4-11 

Table 4-9 FOM Assumptions Used in EPA Base Case v.4.10 

Prime Mover 

Type 

Primary 

Fuel SO2 Control Hg Control 

NOx

Control Age of Unit FOM (2007$ /kW-Yr) 

Combined 

Cycle Oil & Gas -- -- -- All Years 12.6 

Conventional 

Hydroelectric Water -- -- -- All Years 14.3 

Fuel Cell Natural 

Gas -- -- -- All Years 18.3 

 >30 years 8.8 

Gas Turbine Oil & Gas 20-30 years 8.5 -- -- -- 

 0-20 years 3.7 

Geothermal Earth -- -- -- All Years 21.6 

IGCC Coal -- -- -- All Years 118.4 

MSW/Landfill 

Gas 

Landfill 

Gas -- -- -- All Years 23.6 

Nuclear Nuclear -- -- -- All Years 100.5 

Pumped 

Storage Water -- -- -- All Years 18.3 

Solar 

Photovoltaic Sun -- -- -- All Years 17.1 

Solar Thermal Sun -- -- -- All Years 22.6 

0 to 20 Years 42.2 

20 to 30 Years 44.2 

30 to 40 Years 55.1 

No NOx

Greater than 40 Years 60.8 

0 to 20 Years 42.9 

20 to 30 Years 44.9 

30 to 40 Years 55.7 

SCR 

Greater than 40 Years 61.4 

0 to 20 Years 42.5 

20 to 30 Years 44.5 

30 to 40 Years 55.3 

No Hg 

SNCR 

Greater than 40 Years 61.1 

0 to 20 Years 42.4 

20 to 30 Years 44.4 

30 to 40 Years 55.2 

No NOx

Greater than 40 Years 60.9 

0 to 20 Years 43.0 

20 to 30 Years 45.0 

30 to 40 Years 55.9 

SCR 

Greater than 40 Years 61.6 

0 to 20 Years 42.6 

20 to 30 Years 44.6 

30 to 40 Years 55.5 

Scrubbed - 

Dry 

ACI 

SNCR 

Greater than 40 Years 61.2 

0 to 20 Years 43.2 

20 to 30 Years 45.2 

30 to 40 Years 56.0 

No NOx

Greater than 40 Years 61.8 

0 to 20 Years 43.8 

Steam Turbine Coal 

Scrubbed - 

Wet 

No Hg 

SCR 

20 to 30 Years 45.8 
4-12 

Prime Mover 

Type 

Primary 

Fuel SO2 Control Hg Control 

NOx

Control Age of Unit FOM (2007$ /kW-Yr) 

30 to 40 Years 56.7 

Greater than 40 Years 62.4 

0 to 20 Years 43.5 

20 to 30 Years 45.5 

30 to 40 Years 56.3 

SNCR 

Greater than 40 Years 62.0 

0 to 20 Years 43.3 

20 to 30 Years 45.3 

30 to 40 Years 56.2 

No NOx

Greater than 40 Years 61.9 

0 to 20 Years 44.0 

20 to 30 Years 46.0 

30 to 40 Years 56.8 

SCR 

Greater than 40 Years 62.6 

0 to 20 Years 43.6 

20 to 30 Years 45.6 

30 to 40 Years 56.5 

ACI 

SNCR 

Greater than 40 Years 62.2 

0 to 20 Years 32.9 

20 to 30 Years 34.9 

30 to 40 Years 45.8 

No NOx

Greater than 40 Years 51.5 

0 to 20 Years 33.6 

20 to 30 Years 35.6 

30 to 40 Years 46.4 

SCR 

Greater than 40 Years 52.2 

0 to 20 Years 33.2 

20 to 30 Years 35.2 

30 to 40 Years 46.1 

No Hg 

SNCR 

Greater than 40 Years 51.8 

0 to 20 Years 33.1 

20 to 30 Years 35.1 

30 to 40 Years 45.9 

No NOx

Greater than 40 Years 51.7 

0 to 20 Years 33.7 

20 to 30 Years 35.7 

30 to 40 Years 46.6 

SCR 

Greater than 40 Years 52.3 

0 to 20 Years 33.3 

20 to 30 Years 35.3 

30 to 40 Years 46.2 

Unscrubbed 

ACI 

SNCR 

Greater than 40 Years 51.9 

0 to 20 Years 18.4 

20 to 30 Years 21.0 

30 to 40 Years 22.3 

No NOx

Greater than 40 Years 28.4 

Oil & Gas -- -- 

SCR 0 to 20 Years 19.3 
4-13 

Prime Mover 

Type 

Primary 

Fuel SO2 Control Hg Control 

NOx

Control Age of Unit FOM (2007$ /kW-Yr) 

20 to 30 Years 21.9 

30 to 40 Years 23.2 

Greater than 40 Years 29.3 

0 to 20 Years 18.6 

20 to 30 Years 21.2 

30 to 40 Years 22.5 SNCR 

Greater than 40 Years 28.6 

Wind Wind -- -- -- All Years 18.3 

Wood/Biomass Biomass -- -- -- All Years 20.1 

Table 4-10 Life Extension Cost Assumptions Used in EPA Base Case v.4.10 

Plant Type 

Lifespan 

without Life 

Extension 

Expenditures 

Life Extension 

Cost as 

Proportion of 

New Unit 

Capital Cost 

(%) 

Capital 

Cost of 

New Unit 

(2007$/kW) 

Life 

Extension 

Cost 

(2007$/kW) 

Coal Steam 40 7.0 2,918 204 

Combined Cycle 30 9.3 976 91 

Combustion Turbine & 

 IC Engine 30 4.2 698 30 

Oil/Gas Steam 40 3.4 2,699 91 

IGCC 40 7.4 3,265 242 

Nuclear 40 9.0 4,621 416 

Note:

Life extension expenditures double the lifespan of the unit. 

4.3 Planned-Committed Units 

EPA Base Case v.4.10 includes all planned-committed units that are likely to come online 

because ground has been broken, financing obtained, or other demonstrable factors indicate a 

high probability that the unit will be built before 2012. 

4.3.1 Population and Model Plant Aggregation 

Like existing units, planned-committed units are contained in NEEDS. A comprehensive update 

of planned-committed units contained in NEEDS was performed for EPA Base Case v.4.10 using 

the information sources listed in Table 4-1 . Table 4-11 summarizes the extent of inventory of 

planned-committed units in EPA Base Case v.4.10 indicating its generating capacity by unit types. 

Due to data confidentiality restrictions, NEEDS v.4.10 does not list the planned-committed units on 

a unit by unit basis. Rather, all units having similar technologies and located within the same 

model region are aggregated together as one record. Table 4-12 gives a breakdown of plannedcommitted units by IPM region, unit type, number of units, and capacity included in EPA Base 

Case v.4.10. 
4-14 

Table 4-11 Summary of Planned-Committed Units in NEEDS v.4.10 for EPA Base Case 

v.4.10 

Type Capacity (MW) Year Range Described 

Renewables/Non-conventional 

Biomass 495 2007 - 2012 

Fuel Cell 3 2011 

Geothermal 302 2007 - 2011 

Hydro 91 2007 - 2011 

Landfill Gas 279 2007 - 2011 

Municipal Solid Waste 35 2007 - 2011 

Non-Fossil Waste 235 2011 

Pumped Storage 40 2011 

Solar 687 2007 - 2011 

Wind 26,295 2007 - 2011 

Subtotal 28,462 

Fossil/Conventional 

Coal Steam 17,055 2007 - 2011 

Combined Cycle 25,088 2007 - 2011 

Combustion Turbine 9,648 2007 - 2011 

Fossil Waste 274 2011 

IGCC 1,230 2009 - 2011 

Nuclear 1,180 2014 

O/G Steam 115 2008 - 2011 

Subtotal 54,590 

Grand Total 83,052 

Table 4-12 Planned-Committed Units by Model Region in NEEDS v.4.10 for EPA Base Case 

v.4.10 

IPM Region Plant Type Capacity (MW) 

Biomass 24 

Coal Steam 400 

Combined Cycle 94 

Combustion Turbine 593 

Geothermal 95 

Solar 20 

AZNM 

Wind 130 

Combined Cycle 1,279 

Combustion Turbine 603 

Fuel Cell 1 

Geothermal 25 

Landfill Gas 17 

Solar 249 

CA-N 

Wind 2,533 

Biomass 2 

Combined Cycle 1,293 

Combustion Turbine 454 

Fuel Cell 2 

Hydro 5 

CA-S 

Landfill Gas 8 
4-15 

IPM Region Plant Type Capacity (MW) 

Pumped Storage 40 

Solar 255 

Wind 112 

Combined Cycle 573 

COMD Landfill Gas 6 

Wind 282 

DSNY Combined Cycle 635 

Biomass 14 

ENTG Coal Steam 665 

Combined Cycle 1,336 

Biomass 50 

Coal Steam 3,250 

Combined Cycle 3,266 

Combustion Turbine 639 

Fossil Waste 274 

Landfill Gas 16 

Non-Fossil Waste 10 

Solar 3 

ERCT 

Wind 7,669 

Combined Cycle 6,365 

Combustion Turbine 1,191 

Landfill Gas 21 FRCC 

Municipal Solid Waste 16 

Coal Steam 1,800 

GWAY Landfill Gas 5 

Wind 1,177 

LILC Combined Cycle 350 

Combustion Turbine 105 

Landfill Gas 27 

O/G Steam 9 MACE 

Solar 7 

Combustion Turbine 30 

MACS Landfill Gas 5 

O/G Steam 100 

Biomass 30 

Landfill Gas 22 

Municipal Solid Waste 14 

Wind 480 

Landfill Gas 10 

MACW 

Wind 480 

Biomass 107 

Coal Steam 1,782 

Combined Cycle 1,204 

Combustion Turbine 878 

Hydro 11 

Landfill Gas 7 

MRO 

Municipal Solid Waste 5 
4-16 

IPM Region Plant Type Capacity (MW) 

Non-Fossil Waste 25 

Wind 4,598 

Biomass 44 

Combined Cycle 987 

Combustion Turbine 301 

Hydro 16 

Landfill Gas 11 

O/G Steam 6 

Solar 1 

NENG 

Wind 650 

Biomass 1 

Coal Steam 1,112 

Combined Cycle 1,062 

Geothermal 182 

Hydro 12 

Solar 2 

NWPE 

Wind 266 

NYC Combustion Turbine 1 

Biomass 31 

Combined Cycle 1,262 

Combustion Turbine 175 

Hydro 19 

Landfill Gas 10 

Non-Fossil Waste 58 

Solar 2 

PNW 

Wind 2,584 

Combined Cycle 720 

IGCC 1,230 

Landfill Gas 26 

Non-Fossil Waste 3 

RFCO 

Wind 554 

Coal Steam 695 

Combined Cycle 580 

Landfill Gas 5 

Non-Fossil Waste 80 

RFCP 

Wind 264 

Coal Steam 768 

Combustion Turbine 658 

Hydro 9 

Landfill Gas 6 

Solar 15 

RMPA 

Wind 1,362 

Combustion Turbine 720 

SNV Solar 112 

Wind 189 

SOU Biomass 116 

Combined Cycle 1,237 
4-17 

IPM Region Plant Type Capacity (MW) 

Non-Fossil Waste 18 

Coal Steam 1,172 

SPPN Combustion Turbine 845 

Wind 651 

Coal Steam 660 

Combined Cycle 1,080 

Combustion Turbine 939 

Non-Fossil Waste 35 

Solar 8 

Wind 943 

Nuclear 1,180 

SPPS 

Wind 111 

Coal Steam 1,018 

TVAK Combustion Turbine 200 

Landfill Gas 5 

Biomass 25 

Hydro 13 

Landfill Gas 14 

Non-Fossil Waste 7 

UPNY 

Wind 826 

Coal Steam 1,980 

Combustion Turbine 779 

Hydro 6 

Landfill Gas 18 

Solar 12 

VACA 

Wind 38 

Combined Cycle 1,190 

Combustion Turbine 537 

Landfill Gas 31 VAPW 

Solar 1 

Biomass 50 

Coal Steam 1,753 

Combined Cycle 575 

Landfill Gas 8 

WUMS 

Wind 396 

Note:

Any unit that has an online year of 2007- 2011 was considered a Planned and Committed Unit 

4.3.2 Capacity 

The capacity of planned-committed units in NEEDS v.4.10 was obtained from the information 

sources reported above in Table 4-1 . 

4.3.3 State and Model Region 

State location data for the planned-committed units in NEEDS v.4.10 came from the information 

sources noted in Section 4.3.1. The state information was then used to assign planned-committed 

units to their respective model regions. 
4-18 

4.3.4 Online and Retirement Year 

As noted above, planned-committed units included in NEEDS v.4.10 are only those units which 

are likely to come on-line before 2012. All planned-committed units were given a default online 

year of end of 2011 since this is the first analysis year in EPA Base Case v.4.10. The 

assumptions in EPA Base Case v.4.10 do not include a lifetime for planned-committed units. 

4.3.5 Unit Configuration and Cost-and-Performance 

All planned-committed units in NEEDS v.4.10 assume the cost, performance, and unit 

configuration characteristics of potential units that are available in 2012. A detailed description of 

potential unit assumptions is provided below in Section 4.4. 

4.4 Potential Units 

The EPA Base Case v.4.10 includes options for developing a variety of potential units that may be 

“built” at a future date in response to electricity demand and the constraints represented in the 

model. Defined by region, technology, and the year available, potential units with an initial 

capacity of 0 MW are inputs into IPM. When the model is run, the capacity of certain potential 

units is raised from zero to meet demand and other system and operating constraints. This 

results in the model’s projection of new capacity. 

In Table 4-7 the block labeled “New Units” gives a breakdown of the type and number of potential 

units provided in EPA Base Case v.4.10. The following sections describe the cost and 

performance assumptions for the potential units represented in the EPA Base Case v.4.10. 

4.4.1 Methodology Used to Derive the Cost and Performance Characteristics of 

Conventional Potential Units 

Cost and performance assumptions for potential units in previous EPA base cases were based 

primarily on data from the latest available Annual Energy Outlook (AEO) published by the U.S. 

Department of Energy’s Energy Information Administration. However, an unprecedented run up in 

the costs of new generating units over the preceding 5 years prompted EPA to analyze other 

references in addition to the AEO for Base Case v.4.10. The cost escalation which was 

particularly noticeable for base load electric generating units, was generally attributed to 

international competition and, was increasingly seen as permanent. That is, there was a growing 

consensus that costs were not going to settle back to pre-2010 levels. 

With this in mind, the power sector engineering staff in EPA’s Clean Air Markets Division 

performed comparative cost analyses based on reports and discussions with government 

agencies, national technical laboratories, industry, academia, and various non-governmental 

organizations. The key sources reviewed included: 

• U.S. Energy Information Administration: Annual Energy Outlook 2008, 2009, 201018 

• National Energy Technology Laboratory, Fossil Energy Power Plant Desk Reference 

(Bituminous Coal)19

 

18 U.S. Department of Energy, Energy Information Administration, Assumptions to the Annual 

Energy Outlook 2008: Electric Market Module, DOE/EIA-0554(2008), June 2008. 

www.eia.doe.gov/oiaf/archive/aeo08/assumption/electricity.html

U.S. Department of Energy, Energy Information Administration, Assumptions to the Annual 

Energy Outlook 2009: Electric Market Module, DOE/EIA-0554(2009), March 2009. 

www.eia.doe.gov/oiaf/archive/aeo09/assumption/electricity.html

U.S. Department of Energy, Energy Information Administration, Assumptions to the Annual 

Energy Outlook 2010: Electric Market Module, #:DOE/EIA-0554(2010), April 2010. 

www.eia.doe.gov/oiaf/aeo/assumption/electricity.html. 19 U.S. Department of Energy, National Energy Technology Laboratory, Fossil Energy Power Plant 

Desk Reference, Bituminous Coal and Natural Gas to Electricity Summary Sheets DOE/NETL-
4-19 

• U.S. Environmental Protection Agency, Environmental Footprints and Costs of Coal-Based 

Integrated Gasification Combined Cycle and Pulverized Coal Technologies20

• EPRI (Electric Power Research Institute): “Economic Assessment of Advanced Coal-Based 

Power Plants with CO2 Capture”21

• Harvard University: “Realistic Costs of Carbon Capture”22

• Massachusetts Institute of Technology: ”Update on the Cost of Nuclear Power”23 

• Union of Concerned Scientists: Climate 2030 - A National Blueprint for a Clean Energy 

Economy24

4.4.2 Cost and Performance for Potential Conventional Units 

The comparative analyses described in the preceding section resulted in the cost and 

performance characteristics shown in Table 4-13. They are based on EPA’s engineering 

assessments. As seen in Table 4-13, EPA Base Case v.4.10 includes cost and performance 

characteristics for the following potential technologies: supercritical pulverized coal, advanced 

combined cycle, advanced combustion turbines, integrated gasification combined cycle (IGCC), 

advanced coal with carbon capture capabilities, and nuclear units. The cost and performance 

assumptions are based on the size (i.e., electrical generating capacity in MW) indicated in the 

table. However, the total new capacity that is added in a given model run for these technologies is 

not restricted to these capacity levels. 

This table includes several components of cost. The total installed cost of developing and building 

a new plant is captured through the capital cost. It includes expenditures on pollution control 

equipment that new units are assumed to install to satisfy air regulatory requirements. The capital 

costs shown in Table 4-13 are typically referred to as “overnight” capital costs. They include 

engineering, procurement, construction, startup, and owner’s costs (for such items as land, 

cooling infrastructure, administration and associated buildings, site works, switchyards, project 

management, licenses, etc). The capital costs in Table 4-13 do not include interest during 

construction (IDC). IDC is added to the capital costs shown in Table 4-13 during the set-up of a 

run. Calculation of IDC is based on the construction profile and the discount rate. Details on the 

discount rates used in the EPA Base Case v.4.10 are discussed in Chapter 8 under financial 

assumptions. 

 2007/1282, May 2007. http://www.netl.doe.gov/energyanalyses/pubs/Cost%20and%20Performance%20Baseline-012908.pdf

20U.S. EPA, Environmental Footprints and Costs of Coal-Based Integrated Gasification Combined 

Cycle and Pulverized Coal Technologies. EPA-430/R-06/2006, July 2006. 

21Booras, G., Economic Assessment of Advanced Coal-Based Power Plants with CO2 Capture, a 

presentation at EPRI (Electric Power Research Institute) MIT Carbon Sequestration Forum IC, 

September 16, 2008. 

22Al-Juaied, M and A Whitmore, ““Realistic Costs of Carbon Capture” Harvard Kennedy School. 

Belfer Center Discussion Paper 2009-08, July 2009. 

http://belfercenter.ksg.harvard.edu/files/2009_AlJuaied_Whitmore_Realistic_Costs_of_Carbon_C

apture_web.pdf

23Du, Y., J.E. Parsons (2009). Update on the cost of nuclear power. MIT Center for Energy and 

Environmental Policy Research (CEEPR) Working Paper 09-004, May 2009. 

http://web.mit.edu/ceepr/www/publications/workingpapers/2009-004.pdf

24Cleetus R., S. Clemmer, and D. Friedman, Climate 2030 - A National Blueprint for a Clean 

Energy Economy, Union of Concerned Scientists, May 2009. 

http://www.ucsusa.org/global_warming/solutions/big_picture_solutions/climate-2030-

blueprint.html#Download_the_Climate_2030_Blueprint_repo
4-20 

Table 4-13 Performance and Unit Cost Assumptions for Potential (New) Capacity from Conventional Technologies i

Advanced 

Combined 

Cycle 

Advanced 

Combustion 

Turbine 

Nuclear 

Integrated 

Gasification 

Combined 

Cycle –

Bituminous 

Integrated 

Gasification 

Combined Cycle 

– Subbituminous 

Advanced 

Coal with 

Carbon 

CaptureBituminous1

Advanced Coal 

 with Carbon 

Capture – 

Subbituminous1

Supe

Pulv

Coa

Bitu

Size (MW) 560 170 1350 600 600 500 500 

First Year 

Available 2015 2012 2017 2013 2013 2015 2015 2

Lead Time (Years) 3 2 6 4 4 4 4 

Vintage #1 

(years covered) 

2012 - 

2054 2012 - 2054 2012 - 2054 2012 - 2054 2012 - 2054 2012 - 2054 2015 - 2054 2012 

Availability 87% 92% 90% 85% 85% 85% 85% 8

Vintage #1 

Heat Rate 

(Btu/kWh) 6,810 10,720 10,400 8,424 8,062 10,149 9,713 8

Capital2

(2007$/kW) 976 698 4,621 3,265 3,310 4,720 4,785 2

Fixed O&M 

(2007$/kW/yr) 14.4 12.3 92.4 47.9 48.2 60.5 61.0 2

Variable O&M 

(2007$/MWh) 2.57 3.59 0.77 1.32 1.15 1.67 1.46 3

Notes:1For The term “Advanced Coal with Carbon Capture” is used here and in the output files for EPA Base Case v.4.10 to repre

technologies that are expected to provide carbon capture capabilities. These include both supercritical steam generators wintegrated gasification combined cycle (IGCC) with carbon capture. Although IGCC with carbon capture was used to define 

performance parameters that are implemented in EPA Base Case v.4.10, projections of “Advanced Coal with Carbon Captuv.4.10 are not limited to this technology. 

2Capital cost represents overnight capital cost. 
4-21 

Table 4-13 also shows fixed operating and maintenance (FOM) and variable operating and 

maintenance (VOM) components of cost. FOM is the annual cost of maintaining a generating 

unit. It represents expenses incurred regardless of the extent that the unit is run. It is expressed 

in units of $ per kW per year. VOM represents the costs incurred in running an electric generating 

unit. It is proportional to the electrical energy produced and is expressed in units of $ per MWh. 

In addition to the three components of cost, Table 4-13 indicates the first year available, lead time, 

vintage periods, heat rate, and availability for each type of unit. Lead time represents the 

construction time needed for a unit to come online. Vintage periods are used to capture the cost 

and performance improvements resulting from technological advancement and learning-by-doing. 

Mature technologies and technologies whose first year available is not at the start of the modeling 

time horizon may have only one vintage period, whereas newer technologies may have several 

vintage periods. Heat rate indicates the efficiency of the unit and is expressed in units of energy 

consumed (Btus) per unit of electricity generated (kWh). Availability indicates the percentage of 

time that a generating unit is available to provide electricity to the grid once it has come on line. 

Availability takes into account estimates of the time consumed by planned maintenance and 

forced outages. The emission characteristics of the potential units are not presented in Table 

4-13, but can be found in Table 3-11. 

4.4.3 Short-Term Capital Cost Adder 

Besides the capital costs shown in Table 4-13 and Table 4-16 EPA Base Case v.4.10 includes a 

short-term capital cost adder that kicks in if the new capacity in a specific model run year exceeds 

certain upper bounds. This is meant to reflect the added cost incurred due to short-term 

competition for scarce labor and materials. Table 4-14 shows the cost adders for each type of 

potential unit for model run years through 2030. The adder is not imposed after 2030 on the 

premise that by then market adjustments will have eliminated the short term scarcity experienced 

in earlier years. 

Here’s how these short-term adders work in Base Case v.4.10: The column labeled “Step 1” in 

Table 4-14 indicates the total amount of capacity of a particular plant type that can be built in a 

given model run year without incurring a cost adder. However, if the Step 1 upper bound is 

exceeded, then either the Step 2 or Step 3 cost adder is incurred. Above the Step 1 upper bound, 

the Step 2 cost adder applies until the cumulative capacity exceeds the Step 1 + Step 2 upper 

bound. Beyond that point, the Step 3 capital cost adder applies. For example, the Step 1 upper 

bound in 2012 for coal steam potential units is 25,301 MW. If no more than this total new coal 

steam capacity is built in 2012, only the capital cost shown in Table 4-13 is incurred. Between 

25,301 and 42,168 MW (the sum of the Step 1 and Step 2 upper bounds, i.e., 25,301 MW + 16, 

867 MW = 42,168 MW), the Step 2 cost adder of $967/MW applies. For all the new coal capacity 

built in that model run year (not just the increment of new capacity above the Step 1 upper bound 

of 25,301 MW), this extra cost is added to the capital cost shown in Table 4-13. If the total new 

coal steam capacity exceeds the Step 1 + Step 2 upper bound of 42,168 MW, then the Step 3 

capacity adder of $2,500/MW is incurred. To determine if the upper bounds for plant type “Coal 

Steam” in Table 4-14 have been reached, one must sum the capacities added in a model run year 

for plant types Supercritical Pulverized Coal - Wet Bituminous and Supercritical Pulverized Coal - 

Dry Bituminous. The upper bound for “Coal Steam” applies to the sum of the capacity added in 

the model run year for these two plant types. 

The short-term capital cost adders shown in Table 4-14 were derived from AEO assumptions. 

4.4.4 Regional Cost Adjustment 

The capital costs reported in Table 4-14 are generic. Before EPA implements these capital cost 

values they are converted to region-specific costs. This is done through the application of regional 

adjustment factors which capture regional differences in labor, material, and construction costs. 

The regional adjustment factors used in EPA Base Case v.4.10 are shown in Table 4-15. They 
4-22 

were developed from AEO and are applied to both conventional technologies shown in Table 4-13 

and to the renewable and non-conventional technologies shown in Table 4-16 below. 

 
4-23 

Table 4-14 Short-Term Capital Cost Adders for New Power Plants in EPA Base Case v.4.10 (200

2012 2015 2020 

ID 

Number Plant Type Step 1 Step 2 Step 3 Step 1 Step 2 Step 3 Step 1 Step 2 Step 3 

Upper Bound (MW) 600 400 -- 1,800 1,200 -- 3,000 2,000 -- 

1 Biomass 

Adder ($/kW) -- 1,410 3,646 -- 1,410 3,646 -- 1,410 3,646 Upper Bound (MW) 8,434 5,622 -- 25,301 16,867 -- 42,168 28,112 -- 

2 Coal Steam 

Adder ($/kW) -- 967 2,500 -- 967 2,500 -- 967 2,500 Upper Bound (MW) 46,469 30,979 -- 139,406 92,937 -- 232,344 154,896 -- 

3 Combined Cycle Adder ($/kW) -- 310 801 -- 310 801 -- 310 801 

Upper Bound (MW) 24,098 16,066 -- 72,295 48,197 -- 120,492 80,328 -- 

4 Combustion Turbine Adder ($/kW) -- 213 551 -- 213 551 -- 213 551 

Upper Bound (MW) 600 400 -- 1,800 1,200 -- 3,000 2,000 -- 

5 Fuel Cell 

Adder ($/kW) -- 1,987 5,138 -- 1,987 5,138 -- 1,987 5,138 Upper Bound (MW) 315 210 -- 946 630 -- 1,576 1,051 -- 

6 Geothermal 

Adder ($/kW) -- 1,981 5,123 -- 1,981 5,123 -- 1,981 5,123 Upper Bound (MW) 2,400 1,600 -- 7,200 4,800 -- 12,000 8,000 -- 

7 

IGCC and Advanced Coal with Carbon Capture 

Adder ($/kW) -- 1,072 2,774 -- 1,072 2,774 -- 1,072 2,774 Upper Bound (MW) 600 400 -- 1,800 1,200 -- 3,000 2,000 -- 

8 Landfill Gas 

Adder ($/kW) -- 1,135 2,936 -- 1,135 2,936 -- 1,135 2,936 Upper Bound (MW) 11,230 7,487 -- 33,690 22,460 -- 56,151 37,434 -- 

9 Nuclear 

Adder ($/kW) -- 1,579 4,083 -- 1,579 4,083 -- 1,579 4,083 Upper Bound (MW) 106 70 -- 317 211 -- 528 352 -- 

10 Solar Thermal Adder ($/kW) -- 1,608 4,158 -- 1,608 4,158 -- 1,608 4,158 

Upper Bound (MW) 54 36 -- 54 36 -- 90 60 -- 

11 Solar PV 

Adder ($/kW) -- 1,733 4,483 -- 1,733 4,483 -- 1,733 4,483 
4-24 

2012 2015 2020 

ID 

Number Plant Type Step 1 Step 2 Step 3 Step 1 Step 2 Step 3 Step 1 Step 2 Step 3 

Upper Bound (MW) 23,000 19,670 -- 29,505 19,670 -- 49,174 32,783 -- 

12 Onshore Wind Adder ($/kW) -- 646 1,672 -- 646 1,672 -- 646 1,672 

Upper Bound (MW) 600 400 -- 1,800 1,200 -- 3,000 2,000 -- 

13 Offshore Wind Adder ($/kW) -- 1,304 3,373 -- 1,304 3,373 -- 1,304 3,373 

Note:

The term “Advanced Coal with Carbon Capture” is used here and in the output files for EPA Base Case v.4.10 to represent 

technologies that are expected to provide carbon capture capabilities. These include both supercritical steam generators wintegrated gasification combined cycle (IGCC) with carbon capture. Although IGCC with carbon capture was used to define 

performance parameters that are implemented in EPA Base Case v.4.10 and shown in Table 4-13, projections of “Advance

Capture” in EPA Base Case v.4.10 are not limited to this technology. 
4-25 

Table 4-15 Regional Cost Adjustment Factors for Conventional and Renewable Generating 

Technologies in EPA Base Case v.4.10 

Model 

Region Region Description or Reliability Council Name Regional Factor 

AZNM Western Electricity Coordinating Council - Arizona, New Mexico 1.003 

CA-N Western Electricity Coordinating Council - California North 1.058 

CA-S Western Electricity Coordinating Council - California South 1.058 

COMD Commonwealth Edison 1.004 

DSNY Downstate New York 1.043 

ENTG Entergy 0.960 

ERCT Texas Regional Entity 0.986 

FRCC Florida Reliability Coordinating Council 0.961 

GWAY Gateway 1.004 

LILC Long Island Company 1.879 

MACE Legacy Mid-Atlantic Area Council - East 0.996 

MACS Legacy Mid-Atlantic Area Council - South 0.996 

MACW Legacy Mid-Atlantic Area Council - West 0.996 

MECS Michigan Electric Coordination System 1.004 

MRO Midwest Regional Planning Organization 1.004 

NENG New England Power Pool 1.145 

NWPE Western Electricity Coordinating Council - Northwest Power Pool 

East 1.026 

NYC New York City 1.989 

PNW Western Electricity Coordinating Council - Pacific Northwest 1.026 

RFCO Reliability First Corporation - MISO 1.004 

RFCP Reliability First Corporation - PJM 1.004 

RMPA Western Electricity Coordinating Council - Rocky Mountain Power 

Area 1.003 

SNV Western Electricity Coordinating Council - Southern Nevada 1.003 

SOU Southern Company 0.960 

SPPN Southwest Power Pool - North 0.997 

SPPS Southwest Power Pool - South 0.997 

TVA Tennessee Valley Authority 0.960 

TVAK Tennessee Valley Authority - MISO-KY 1.004 

UPNY Upstate New York 1.043 

VACA Virginia-Carolinas 0.960 

VAPW Dominion Virginia Power 0.960 

WUMS Wisconsin-Upper Michigan 1.004 

4.4.5 Cost and Performance for Potential Renewable Generating and Non-Conventional 

Technologies 

The renewable and non-conventional generating technologies included as potential units in the 

EPA Base Case v.4.10 are conventional biomass boilers, biomass gasification combined cycle 

(BGCC), onshore and offshore wind (shallow and deep), geothermal, fuel cells, solar photovoltaic, 

solar thermal, and landfill gas. Table 4-16 summarizes the cost and performance assumptions in 

EPA Base Case v.4.10 for these potential units. Except for biomass, the parameters shown in 

Table 4-16 are based on AEO 2009. The size (MW) presented in Table 4-16 represents the 

capacity on which unit cost estimates were developed and does not indicate the total potential 

capacity that the model can build of a given technology. Due to the distinctive nature of generation 

from renewable resources, some of the values shown in Table 4-16 are averages or ranges that 

are discussed in further detailed in the following subsections. Also discussed below are additional 
4-26 

types of data from sources other than AEO 2009 that play a role in the representation of these 

types of generation in EPA Base Case v.4.10. 
4-27 

Table 4-16 Performance and Unit Cost Assumptions for Potential (New) Renewable and Non-Conventional Techno

Base Case v4.10 

Biomass Landfill Gas 

Conventional 

Boiler1

Biomass 

Gasification 

Combined 

Cycle1

Fuel 

Cells Geothermal 

LGHI LGLo LGVLo 

Solar 

Photovoltaic 

Solar 

Therm

Size (MW) 35 120 10 50 30 5 100 

First Year Available 2013 2019 2013 2014 2013 2012 2013 

Lead Time (Years) 3 4 3 4 3 2 3 

Vintage #1 

(years covered) 

2012 - 

2019 

2012 - 

2019 

2012 - 

2019 2012 - 2019 2012 - 2019 

Vintage #2 

(years covered) 

2020 - 

2029 

2020 - 

2029 

2020 - 

2029 2020 - 2029 2020 - 2029 

Vintage #3 

(years covered) 

2012 - 2054 2020 - 2054 2012 - 2054 2012 - 2054 

2030 - 

2054 

2030 - 

2054 

2030 - 

2054 2030 - 2054 2030 - 2054 

Availability 85% 85% 87% 87% 90% 90% 90% 

Generation Capability Economic Dispatch Genera

Vintage #1 

Heat Rate (Btu/kWh) 13,500 - 7,930 29,655 - 397,035 13,648 13,648 13,648 0 0 

Capital (2007$/kW)2 4,698 - 6,259 1,624 - 20,674 2,596 3,270 5,035 5,765 5,156 

Fixed O&M (2007$/kW/yr) 85.2 - 5.7 151 - 219 114.3 114.3 114.3 11.7 56.8 

Variable O&M (2007$/MWh) 11.60 - 47.92 0.00 0.01 0.01 0.01 0 0 

Vintage #2 

Heat Rate (Btu/kWh) - 9,800 - - 13,648 13,648 13,648 0 0 

Capital (2007$/kW) 2 - 4,071 - - 2,505 3,156 4,859 5,350 4,641 

Fixed O&M (2007$/kW/yr) - 48.3 - - 114.3 114.3 114.3 11.7 56.8 

Variable O&M (2007$/MWh) - 8.83 - - 0.01 0.01 0.01 0 0 

Vintage #3 

Heat Rate (Btu/kWh) - - - - 13,648 13,648 13,648 0 0 

Capital (2007$/kW) 2 - - - - 2,019 2,544 3,916 3,777 4,383 

Fixed O&M (2007$/kW/yr) - - - - 114.3 114.3 114.3 11.7 56.8 

Variable O&M (2007$/MWh) - - - - 0.01 0.01 0.01 0 0 

Note:1 The biomass generating technologies shown in this table represent new capacity designed to burn biomass only. Assumptions for biomass co-firing at found in Table 5-14. 2Capital cost represents overnight capital cost. 
4-28 

It should be noted that the short term capital cost adder in Table 4-14 and the regional cost 

adjustment factors in Table 4-15 apply to the renewable and non-conventional generation 

technologies as they did to the conventional generation technologies 

Biomass Electricity Generation 

Two biomass generation technologies with separate vintage periods are offered as new (potential) 

units in EPA Base Case v.4.10. Conventional direct fired biomass boilers are offered in vintage 

period 1, i.e., 2012-2019. Based on engineering and market analysis that indicated that biomass 

gas combined cycle (BGCC) units will become commercially available by 2020, BGCC with its 

much more favorable heat rate and cost characteristics is provided as a potential unit from 2020 

onward. Prepared by EPA’s power sector engineering staff, the cost and performance 

characteristics of these two technology options are shown in Table 4-16. 

Wind Generation 

Previous EPA base cases only represented onshore wind generation. In addition to onshore 

wind, EPA Base Case v.4.10 includes offshore-shallow and offshore-deep wind generation. The 

following sections describe four key aspects of the representation of wind generation: wind quality 

and resource potential, generation profiles, reserve margin contribution, and capital cost 

calculation. 

Wind Quality and Resource Potential: Wind resources are conventionally categorized into wind 

quality classes, ranging from class 1 (designated to be the least productive and reliable class for 

wind generation) to class 7 (designated to be the most productive and reliable class for wind 

generation). Areas designated as wind class 3 or higher are generally suitable for commercial 

wind turbine applications. Whereas previous EPA base cases only included wind classes 4, 5, 

and 6, EPA Base Case v.4.10 also includes class 3 and 7. 

EPA worked with the U.S. Department of Energy’s (DOE) National Renewable Energy Laboratory 

(NREL), on a complete update of the wind resource assumptions for use in EPA Base Case 

v.4.10. The result is a complete representation of the potential onshore, offshore (shallow and 

deep) wind generating capacity (in MW) broken into four cost classes (described in greater detail 

below) in each IPM model region. Table 4-17, Table 4-18 , and Table 4-19 present the onshore, 

offshore shallow, and offshore deep wind resource assumptions that are used in EPA Base Case 

v.4.10.
4-29 

Table 4-17 Onshore Regional Potential Wind Capacity (MW) by Wind and Cost Class in 

EPA Base Case v.4.10 

Cost Class IPM Region Wind Class 

1 2 3 4 

3 707 1,714 44 125,761 

4 42 329 27 33,741 

5 6 2,028 1,612 2,355 

6 214 447 264 512 

AZNM 

7 4 106 144 166 

3 1,269 -- -- 8,646 

4 560 1,069 1,476 1,539 

5 79 631 746 765 

6 286 -- 795 740 

CA-N 

7 12 352 -- 399 

3 1,689 -- -- 18,014 

4 1,323 1,460 1,402 2,536 

5 380 614 653 831 

6 118 -- 435 540 

CA-S 

7 46 -- 231 233 

3 2 -- -- 62,549 COMD 4 19 260 -- 312 

3 98 599 297 500 

4 64 -- -- 268 

5 -- 60 -- 89 

6 -- -- 30 29 

DSNY 

7 -- -- -- 29 

3 1 1 -- 2 ENTG 5 -- 20 -- 30 

3 3,230 -- 1,198 321,950 

4 9,912 32,701 2,796 51,392 

5 396 1,415 899 1,484 

6 207 -- 512 582 

ERCT 

7 5 -- -- 20 

3 10 -- -- 275,467 GWAY 4 -- 621 580 922 

3 -- -- 872 567 LILC 4 -- 128 -- 194 

3 384 -- 925 1,264 

MACE 4 9 -- -- 163 

5 -- -- -- 2 

3 8 -- -- 57 

MACS 4 2 5 -- 10 

5 -- -- -- 3 

3 700 1,054 1,747 2,412 

4 182 -- 636 477 

5 71 -- 200 161 MACW 

6 -- 26 -- 46 
4-30 

Cost Class IPM Region Wind Class 

1 2 3 4 

3 3,571 -- -- 35,633 

MECS 4 -- -- 467 259 

5 -- 11 -- 12 

3 17 -- -- 2,021,548 

4 7 103 163,083 1,010,547 

5 2,052 22,146 68,431 156,014 MRO 

6 1,310 1,985 1,380 4,489 

3 1,768 -- -- 9,127 

4 737 1,128 -- 1,968 

5 364 442 -- 969 

6 28 356 471 438 

NENG 

7 147 -- -- 478 

3 1,913 -- -- 630,559 

4 1,891 6,167 7,657 236,910 

5 353 1,058 3,600 50,582 

6 122 1,239 3,823 17,728 

NWPE 

7 205 1,517 755 1,755 

3 216 902 354 74,323 

4 69 322 208 15,515 

5 11 86 122 3,483 

6 34 87 99 1,463 

PNW 

7 18 116 79 190 

3 12,199 22,865 8,334 28,239 RFCO 4 -- -- -- 64 

3 196 289 4,841 2,976 

4 82 354 -- 466 

5 44 -- 169 159 

6 41 -- 148 96 

RFCP 

7 2 24 -- 53 

3 1,327 -- -- 409,831 

4 3,222 4,769 8,447 216,430 

5 2,546 7,038 15,851 58,990 

6 3,149 8,000 11,388 14,741 

RMPA 

7 619 6,188 2,151 6,748 

3 -- -- -- 2,707 

4 -- -- -- 234 

5 9 -- -- 39 SNV 

6 1 -- -- 11 

SOU 3 1 -- 2 2 

3 1 -- -- 454,442 

SPPN 4 1,933 9,618 37,341 163,483 

5 -- -- -- 839 
4-31 

Cost Class IPM Region Wind Class 

1 2 3 4 

3 109 -- 69 452,934 

4 2,945 11,388 44,398 349,741 

5 2,660 13,184 -- 21,167 

6 3 105 111 170 

SPPS 

7 -- -- -- 34 

3 204 -- -- 637 

4 -- 121 166 155 

5 19 -- 56 62 

6 3 -- 19 16 

TVA 

7 -- 5 -- 12 

3 4 -- -- 220 

4 2 -- 17 15 

5 -- -- -- 5 

TVAK 

 

6 -- -- 1 -- 

3 -- 2,822 3,346 3,675 

4 -- 403 -- 555 

5 -- 95 -- 114 UPNY 

6 -- -- 35 25 

3 92 272 -- 879 

4 33 60 -- 124 

5 8 -- 39 44 

6 4 -- 30 27 

VACA 

7 -- 7 -- 18 

3 -- 261 -- 352 

4 13 40 -- 100 

5 5 -- 34 35 

6 5 -- 29 33 

VAPW 

7 -- 11 -- 17 

3 371 -- -- 130,624 

WUMS 4 57 49 64 84 

5 -- -- -- 41 
4-32 

Table 4-18 Offshore Shallow Regional Potential Wind Capacity (MW) by Wind and Cost 

Class in EPA Base Case v.4.10 

Cost Class IPM Region Wind Class 

1 2 4 

3 497 995 995 

4 281 561 561 

5 43 86 86 

6 29 59 59 

CA-N 

7 1 3 3 

3 280 560 560 

4 139 277 277 

5 139 278 278 

6 114 228 228 

CA-S 

7 1 3 3 

3 393 785 785 COMD 4 981 1,963 1,963 

DSNY 3 11 22 22 

3 43,021 86,041 86,041 ENTG 4 695 1,390 1,390 

3 14,372 28,745 28,745 

ERCT 4 15,191 30,382 30,382 

5 4,457 8,915 8,915 

3 43,305 86,610 86,610 FRCC 4 6,120 12,240 12,240 

3 693 1,385 1,385 

4 1,610 3,220 3,220 

5 1,851 3,703 3,703 LILC 

6 530 1,060 1,060 

3 2,745 5,490 5,490 

4 8,161 16,323 16,323 

5 8,838 17,676 17,676 MACE 

6 5,123 10,246 10,246 

3 1,066 2,132 2,132 MACS 4 187 374 374 

3 160 319 319 

4 136 271 271 

5 1,320 2,640 2,640 MACW 

6 5 11 11 

3 2,349 4,699 4,699 

4 3,850 7,701 7,701 

5 5,451 10,903 10,903 

6 1,886 3,771 3,771 

MECS 

7 6 13 13 

3 399 798 798 

4 952 1,904 1,904 

5 348 696 696 MRO 

6 1 3 3 
4-33 

Cost Class IPM Region Wind Class 

1 2 4 

3 2,326 4,652 4,652 

4 3,134 6,269 6,269 

5 2,989 5,978 5,978 

6 6,157 12,314 12,314 

NENG 

7 334 667 667 

3 99 198 198 

NYC 4 253 506 506 

5 3 5 5 

3 716 1,432 1,432 

4 1,651 3,303 3,303 

5 1,310 2,620 2,620 

6 204 407 407 

PNW 

7 112 224 224 

3 686 1,371 1,371 

4 2,298 4,595 4,595 

5 5,664 11,328 11,328 RFCO 

6 1,963 3,925 3,925 

3 8,466 16,933 16,933 

SOU 4 4,903 9,806 9,806 

5 311 621 621 

3 884 1,768 1,768 

UPNY 4 859 1,718 1,718 

5 659 1,318 1,318 

3 6,229 12,458 12,458 

4 12,064 24,129 24,129 

5 13,709 27,418 27,418 VACA 

6 3,209 6,419 6,419 

3 1,990 3,981 3,981 

4 3,422 6,843 6,843 

5 3,886 7,772 7,772 VAPW 

6 3,660 7,321 7,321 

3 2,272 4,544 4,544 

4 2,902 5,805 5,805 

5 1,832 3,664 3,664 WUMS 

6 680 1,360 1,360 
4-34 

Table 4-19 Offshore Deep Regional Potential Wind Capacity (MW) by Wind and Cost Class 

in EPA Base Case v.4.10 

Cost Class IPM Region Wind Class 

1 2 4 

3 4,039 8,077 8,077 

4 25,846 51,693 51,693 

5 9,947 19,894 19,894 

6 21,282 42,565 42,565 

CA-N 

7 19,318 38,636 38,636 

3 10,721 21,441 21,441 

4 9,247 18,494 18,494 

5 14,402 28,805 28,805 

6 10,140 20,280 20,280 

CA-S 

7 169 339 339 

4 1,028 2,055 2,055 

COMD 5 1,100 2,200 2,200 

6 950 1,900 1,900 

3 13,473 26,945 26,945 ENTG 4 10,730 21,461 21,461 

4 10,501 21,003 21,003 ERCT 5 6,548 13,096 13,096 

3 28,019 56,037 56,037 

FRCC 4 53,858 107,715 107,715 

5 1,109 2,219 2,219 

4 501 1,002 1,002 

5 431 861 861 

6 15,589 31,178 31,178 LILC 

7 5 10 10 

3 11 22 22 

4 140 280 280 

5 1,049 2,099 2,099 MACE 

6 22,490 44,979 44,979 

MACS 4 7 14 14 

4 29 58 58 MACW 5 557 1,114 1,114 

3 220 439 439 

4 701 1,403 1,403 

5 7,710 15,420 15,420 

6 33,394 66,787 66,787 

MECS 

7 45 90 90 

3 354 707 707 

4 4,882 9,765 9,765 

5 3,283 6,566 6,566 MRO 

6 1,535 3,070 3,070 

3 144 287 287 

4 1,754 3,508 3,508 

5 3,683 7,366 7,366 

6 59,338 118,676 118,676 

NENG 

7 1,762 3,524 3,524 
4-35 

Cost Class IPM Region Wind Class 

1 2 4 

NYC 4 58 116 116 

3 241 482 482 

4 813 1,625 1,625 

5 12,502 25,005 25,005 

6 34,795 69,589 69,589 

PNW 

7 25,739 51,477 51,477 

4 9 19 19 

RFCO 5 1,162 2,323 2,323 

6 507 1,014 1,014 

3 8,765 17,529 17,529 

SOU 4 15,055 30,109 30,109 

5 2,169 4,339 4,339 

3 50 100 100 

4 1,506 3,011 3,011 

5 5,993 11,986 11,986 UPNY 

6 465 930 930 

4 2 3 3 

VACA 5 6,536 13,073 13,073 

6 23,687 47,373 47,373 

5 151 302 302 VAPW 6 16,150 32,300 32,300 

3 395 790 790 

4 3,533 7,066 7,066 

5 8,073 16,145 16,145 WUMS 

6 39,059 78,119 78,119 
4-36 

Generation Profiles: Unlike other renewable generation technologies, which dispatch on an 

economic basis subject to their availability constraint, wind and solar technologies can only be 

dispatched when the wind blows and the sun shines. To represent intermittent renewable 

generating sources like wind and solar, EPA Base Case v.4.10 uses generation profiles which 

specify hourly generation patterns for a representative day in winter and summer. Each eligible 

model region is provided with a distinct set of winter and summer generation profiles for wind, 

solar thermal, and solar photovoltaic plants. 

For Hour1 through Hour 24 the generation profile indicates the amount of generation (kWh) per 

MW of available capacity. The wind generation profiles were prepared with data from NREL. This 

provided the separate winter and summer generation profiles for wind classes 3-7 for onshore and 

offshore (shallow and deep) generation in each IPM region. (As an illustrative example Appendix 

4-1 shows the generation profile for onshore wind in model region CA-N.) In IPM the seasonal 

average “kWh of generation per MW” (shown in the last row of the example in Appendix 4-1) is 

used to derive the generation from a particular wind class in a specific model region. 

To obtain the seasonal generation for the units in a particular wind class in a specific region, one 

must multiply the installed capacity by the capacity factor (which represents the ratio of actual 

productivity in a time period to the theoretical maximum in the period). Capacity factor is the 

average “kWh of generation per MW” from the applicable generation profile multiplied by the 

number of days in the time period (i.e., summer or winter) to obtain the level of generation. The 

capacity factors for wind generation that are used in EPA Base Case v.4.10 were obtained from 

AEO 2010 and are shown in Table 4-20, Table 4-21, and. Table 4-22 

Reserve Margin Contribution (also referred to as capacity credit): EPA Base Case v.4.10 uses 

reserve margins, discussed in detail in Section 3.6, to model reliability. Each region has a reserve 

margin requirement which is used to determine the total capacity needed to reliably meet peak 

demand. The ability of a unit to assist a region in meeting its reliability requirements is modeled 

through the unit’s contribution to reserve margin. If the unit has 100 percent contribution towards 

reserve margin, then the entire capacity of the unit is counted towards meeting the region’s 

reserve margin requirement. However, if any unit has less than a 100 percent contribution 

towards reserve margin, then only the designated share of the unit’s capacity counts towards the 

reserve margin requirement. 

All units except those that depend on intermittent resources have 100% contributions toward 

reserve margin. This means that all renewable resource technologies except wind and solar, 

have 100 percent contribution towards reserve margin in the EPA Base Case v.4.10. (Note Hydro, 

not considered a renewable technology, also has less than a 100% reserve margin contribution.) 

Reserve margin contribution ratios are based on AEO 2010. Table 4-20, Table 4-21, and Table 

4-22 present the reserve margin contributions apportioned to new wind plants in the EPA Base 

Case v.4.10 as derived from AEO 2010. The tables show the onshore and offshore (shallow and 

deep) reserve margins for each wind class in each model region.
4-37 

Table 4-20 Onshore Reserve Margin Contribution an Average Capacity Factor by Wind 

Class and Model Region 

Wind Class IPM Model Region 3 4 5 6 7 

AZNM 22% 24% 29% 34% 37% 

CA-N 14% 16% 19% 22% 24% 

CA-S 14% 16% 19% 22% 24% 

COMD 18% 20% -- -- -- 

DSNY 18% 20% 24% 28% 30% 

ENTG 26% -- 35% -- -- 

ERCT 19% 21% 25% 29% 32% 

GWAY 18% 20% -- -- -- 

LILC 18% 20% -- -- -- 

MACE 18% 20% 24% -- -- 

MACS 18% 20% 24% -- -- 

MACW 18% 20% 24% 28% -- 

MECS 22% 25% 30% -- -- 

MRO 19% 21% 26% 30% -- 

NENG 15% 16% 20% 23% 25% 

NWPE 25% 28% 33% 39% 42% 

PNW 25% 28% 33% 39% 42% 

RFCO 22% 25% -- -- -- 

RFCP 22% 25% 30% 35% 38% 

RMPA 22% 24% 29% 34% 37% 

SNV 22% 24% 29% 34% -- 

SOU 26% -- -- -- -- 

SPPN 24% 27% 33% -- -- 

SPPS 24% 27% 33% 38% 42% 

TVA 26% 29% 35% 41% 44% 

TVAK 22% 25% 30% 35% -- 

UPNY 18% 20% 24% 28% -- 

VACA 26% 29% 35% 41% 44% 

VAPW 26% 29% 35% 41% 44% 

WUMS 18% 20% 24% -- -- 

Average Annual 

Capacity Factor 29% 33% 39% 46% 50% 

Table 4-21 Offshore Shallow Reserve Margin Contribution an Average Capacity Factor by 

Wind Class and Model Region 

Wind Class IPM Model Region 3 4 5 6 7 

CA-N 15% 17% 20% 24% 25% 

CA-S 15% 17% 20% 24% 25% 

COMD 19% 21% -- -- -- 

DSNY 19% -- -- -- -- 

ENTG 27% 30% -- -- -- 

ERCT 20% 22% 26% -- -- 

FRCC 19% 21% -- -- -- 

LILC 19% 21% 25% 29% -- 
4-38 

Wind Class IPM Model Region 3 4 5 6 7 

MACE 19% 21% 25% 30% -- 

MACS 19% 21% -- -- -- 

MACW 19% 21% 25% 30% -- 

MECS 23% 26% 31% 37% 39% 

MRO 20% 22% 27% 32% -- 

NENG 15% 17% 21% 24% 26% 

NYC 19% 21% 25% -- -- 

PNW 26% 29% 35% 41% 44% 

RFCO 23% 26% 31% 37% -- 

SOU 27% 30% 36% -- -- 

UPNY 19% 21% 25% -- -- 

VACA 27% 30% 36% 43% -- 

VAPW 27% 30% 36% 43% -- 

WUMS 19% 21% 25% 30% -- 

Average Annual 

Capacity Factor 31% 34% 41% 48% 52% 

Table 4-22 Offshore Deep Reserve Margin Contribution an Average Capacity Factor by 

Wind Class and Model Region 

Wind Class IPM Model Region 3 4 5 6 7 

CA-N 15% 17% 20% 24% 26% 

CA-S 15% 17% 20% 24% 26% 

COMD -- 21% 26% 30% -- 

ENTG 27% 30% -- -- -- 

ERCT -- 22% 26% -- -- 

FRCC 18% 21% 25% -- -- 

LILC -- 21% 25% 30% 32% 

MACE 19% 21% 25% 30% -- 

MACS -- 21% -- -- -- 

MACW -- 21% 25% -- -- 

MECS 23% 26% 31% 37% 40% 

MRO 20% 23% 27% 32% -- 

NENG 15% 17% 21% 24% 26% 

NYC -- 21% -- -- -- 

PNW 26% 29% 35% 41% 45% 

RFCO -- 26% 31% 37% -- 

SOU 27% 30% 36% -- -- 

UPNY 19% 21% 25% 30% -- 

VACA -- 30% 36% 43% -- 

VAPW -- -- 36% 43% -- 

WUMS 19% 21% 26% 30% -- 

Average Annual 

Capacity Factor 31% 35% 41% 49% 53% 
4-39 

Capital cost calculation: EPA Base Case v.4.10 uses multipliers similar to the LT (long term) 

multipliers from the Energy Information Administration’s NEMS model25 to capture differences in 

the capital cost of new wind capacity caused by such factors as distance from existing 

transmission, terrain variability, slope and other causes of resource degradation, site accessibility 

challenges, population proximity, competing land uses, aesthetics, and environmental factors. 

Four cost classes are used in EPA Base Case v.4.10 with class 1 having the lowest cost 

adjustment factor (1) and class 4 having the highest adjustment factor (ranging from 2.48 to 2.67 

depending on the model region and whether the wind resource is onshore, offshore shallow or 

offshore deep), as shown in Table 4-23. To the obtain the capital cost for a particular new wind 

model plant, the base capital costs shown in Table 4-16 are multiplied by the cost adjustment 

factor for the wind cost class applicable to the new plant. 

Table 4-23 Capital Cost Adjustment Factors for New Wind Plants in Base Case v.4.10 

Cost Class 1 2 3 4 

Onshore 1 1.2 1.5 2.51

Offshore Deep Water 1 1.35 -- 2.5 

Offshore Shallow Water 1 1.35 -- 2.5 

Note:

1

The Cost Adjustment Factor for Cost Class 4 Onshore is 2.5 for the majority of regions. 

Exceptions are as follows: 

ERCT has a Cost Adjustment Factor for Cost Class 4 Onshore of 2.62 

AZNM, RMPA, and SNV have a Cost Adjustment Factor for Cost Class 4 Onshore of 2.66 

NWPE, PNW, SPPN, SPPS, and MRO have a Cost Adjustment Factor for Cost Class 4 

Onshore of 2.67 

Many factors figure in whether the model determines that adding wind capacity yields the greatest 

incremental improvement in the system-wide (least cost) solution available to the model at a 

particular point in the solution process. These factors include trade-offs between such items as 

the cost, capacity factor, reserve margin contribution, and dispatch capabilities and constraints on 

the new wind capacity relative to other choices. However, to perform its trade-off computations, 

the model requires the values described above. 

As an illustrative example, Table 4-24 shows the calculations that would be performed to derive 

the potential electric generation, reserve margin contribution, and cost of new (potential) onshore 

capacity in wind class 7, cost class 2 in the CA-N model region in run year 2020. 

 

25Revising the Long Term Multipliers in NEMS: Quantifying the Incremental Transmission Costs 

Due to Wind Power, Report to EIA from Princeton Energy Resources International, LLC. May 

2007. 
4-40 

Table 4-24 Example Calculations Of Wind Generation Potential, Reserve Margin 

Contribution, And Capital Cost For Onshore Wind In CA-N At Wind Class 7, Cost Class 2 

Solar Generation 

Solar Resource Potential: No explicit constraint limit is placed on solar electric capacity in EPA 

Base Case v.4.10. However, since solar thermal is only feasible in areas with sufficient direct 

isolation, EPA Base Case v.4.10 includes the assumption that new solar thermal plants can only 

be built west of the Mississippi River. Solar photovoltaic is not limited to specific parts of the 

country. 

Generation profiles: Like wind, solar is an intermittent renewal technology. Since it can only be 

dispatched when the sun shines, not on a strictly economic basis, it is represented in EPA Base 

Case v.4.10 with generation profiles which specify hourly generation patterns for typical winter and 

summer days in each eligible region. The generation profiles were prepared with data from AEO 

2010, which provided separate winter and summer generation profiles for solar thermal and 

photovoltaic in each eligible IPM region. As an illustrative example, Appendix 4-2 shows the solar 

thermal and solar photovoltaic winter and summer generation profiles in model region AZNM. 

Reserve margin contribution: The procedure described above for calculating the reserve margin 

contributions for wind generation was also used for solar generation. Table 4-25 presents the 

winter and summer average capacity factors (CFs) and reserve margin contributions by model 

Required Data

Table 4-17 Potential wind capacity (C) = 352 MW 

Appendix 4-1 Winter average generation (GW) per available MW per hour = 559 kWh/MW 

Appendix 4-1 Summer average generation (GS) per available MW per hour = 422 kWh/MW 

 Hours in Winter (HW) season (October – April) = 5,088 hours 

 Hours in Summer (HS)season (May – September) = 3,672 hours 

Table 4-20 Reserve Margin Contribution (RM) CA-N, Wind Class 7 = 24 percent 

Table 4-16 Capital Cost (Cap2020) in vintage range for year 2020 = $1,912/kW 

Table 4-23 Capital Cost Adjustment Factor (CAFON,C2) for onshore cost class 2 = 1.2 

Table 4-15 Regional Factor (RF) 1.058 

Calculations

GWh

MW kWh MW hours

MW kWh MW hours

Generation Potential C GW Hw C GS Hs

1,546

352 422 / 3672

352 559 / 5088

=

× ×

= × × +

= × × + × ×

MW

MW

RM C

84

24% 352

Reserve Margin Contribution

=

= ×

= ×

million dollars

MW

Capital Cost RF C

$854

$1,912/MW 1.2 1.058 352

Cap2020 CAFON,C2

=

= × × ×

= × × ×
4-41 

region for new solar thermal and photovoltaic units in EPA Base Case v.4.10. The region-specific 

summer and winter capacity factors included in this table are metrics that provide a shorthand 

depiction of the hourly specific generation profiles for each region. They are based on AEO 2010 

data. The assumptions in EPA Base Case v.4.10 for capacity factors and reserve margin 

contributions for existing units are also based on AEO 2010. 

Table 4-25 Solar Reserve Margin Contribution and Average Capacity Factor by Model 

Region 

Solar Thermal Solar Photovoltaic 

Model 

Region 

Winter 

Average 

Capacity 

Factor 

Summer 

Average 

Capacity 

Factor 

Reserve 

Margin 

Contribution 

Winter 

Average 

Capacity 

Factor 

Summer 

Average 

Capacity 

Factor 

Reserve 

Margin 

Contribution 

AZNM 30% 42% 43% 25% 28% 28% 

CA-N 32% 51% 53% 23% 28% 28% 

CA-S 32% 51% 53% 23% 28% 28% 

COMD 19% 23% 24% 

DSNY 17% 22% 22% 

ENTG 21% 23% 23% 

ERCT 26% 35% 36% 22% 24% 25% 

FRCC 23% 23% 23% 

GWAY 19% 23% 24% 

LILC 17% 22% 22% 

MACE 18% 22% 23% 

MACS 18% 22% 23% 

MACW 18% 22% 23% 

MECS 17% 23% 23% 

MRO 18% 34% 36% 20% 23% 24% 

NENG 19% 22% 23% 

NWPE 23% 41% 18% 18% 25% 16% 

NYC 17% 22% 22% 

PNW 23% 41% 18% 18% 25% 16% 

RFCO 17% 23% 23% 

RFCP 17% 23% 23% 

RMPA 30% 42% 43% 25% 28% 28% 

SNV 30% 42% 43% 25% 28% 28% 

SOU 21% 23% 23% 

SPPN 22% 35% 37% 22% 24% 25% 

SPPS 22% 35% 37% 22% 24% 25% 

TVA 21% 23% 23% 

TVAK 17% 23% 23% 

UPNY 17% 22% 22% 

VACA 21% 23% 23% 

VAPW 21% 23% 23% 

WUMS 19% 23% 24% 

Geothermal Generation 

Geothermal Resource Potential: Six model regions in EPA Base Case v.4.10 have geothermal 

potential. The potential capacity in each of these regions is shown in Table 4-26. The values are 

based on AEO 2010 data. 
4-42 

Table 4-26 Regional Assumptions on Potential Geothermal Electric Capacity 

IPM Model Region Capacity (MW) 

AZNM 2,216 

CA-N 662 

CA-S 124 

NWPE 4,555 

PNW 1,336 

RMPA 70 

Grand Total 8,963 

Note:

This data is a summary of the geothermal data used in EPA Base 

Case v.4.10 

Cost Calculation: EPA Base Case v.4.10 does not contain a single capital cost, but multiple 

geographically-dependent capital costs for geothermal generation. The assumptions for 

geothermal were developed using AEO 2010 cost and performance estimates for 88 known sites. 

 Both dual flash and binary cycle technologies26 were represented. In EPA Base Case v.4.10 the 

88 sites were collapsed into 26 different options based on geographic location and cost and 

performance characteristics of geothermal sites in each of the six eligible IPM regions where 

geothermal generation opportunities exist. Table 4-27 shows the potential geothermal capacity 

and cost characteristics for applicable model regions. 

Table 4-27 Potential Geothermal Capacity and Cost Characteristics by Model Region 

IPM Region Capacity 

(MW) 

Capital Cost 

(2007$) 

FO&M 

(2007$/kW-yr) 

1,404 4,002 185.1 

196 4,675 206.8 

316 5,650 201.1 

294 7,744 192.2 

AZNM 

6 9,199 218.8 

575 1,624 185.1 

CA-N 7 2,873 185.1 

80 4,214 206.2 

71 4,957 185.1 

CA-S 48 5,679 185.1 

5 6,817 185.1 

 

26In dual flash systems, high temperature water (above 400°F) is sprayed into a tank held at a 

much lower pressure than the fluid. This causes some of the fluid to “flash,” i.e., rapidly vaporize 

to steam. The steam is used to drive a turbine, which, in turn, drives a generator. In the binary 

cycle technology, moderate temperature water (less than 400°F) vaporizes a secondary, working 

fluid which drives a turbine and generator. Due to its use of more plentiful, lower temperature 

geothermal fluids, these systems tend to be most cost effective and are expected to be the most 

prevalent future geothermal technology. 
4-43 

IPM Region Capacity 

(MW) 

Capital Cost 

(2007$) 

FO&M 

(2007$/kW-yr) 

9 6,255 164.1 

24 8,337 164.1 

103 9,776 168.6 

1,165 11,465 179.6 

3,001 20,674 181.7 

137 4,523 185.1 

67 5,380 183.0 

12 3,428 218.8 

28 4,594 185.1 

NWPE 

9 8,210 185.1 

268 3,890 151.5 

36 4,782 151.5 

420 5,211 156.3 

PNW 

612 5,625 190.3 

RMPA 70 5,820 185.1 

Landfill Gas Electricity Generation 

Landfill Gas Resource Potential: Estimates of potential electric capacity from landfill gas are 

based on the AEO 2010 inventory. EPA Base Case v.4.10 represents 3 categories of potential 

landfill gas units; “hi”, “low”, and “very low”. The categories refer to the amount and rate of 

methane production from the existing landfill site. Table 4-28 summarizes potential electric 

capacity from landfill gas used in EPA Base Case v.4.10. 

There are several things to note about Table 4-28. Since the potential electric capacity from new 

landfill gas units is based on AEO 2009, the limits listed in Table 4-28 apply to the NEMS 

(National Energy Modeling System) regions indicated in column 1. In EPA Base Case v.4.10 the 

sum of the new landfill gas electric capacity in the corresponding IPM regions shown in column 2 

cannot exceed the limits shown in columns 3-5. As noted earlier, the capacity limits for three 

categories of potential landfill gas units are distinguished in this table based on the rate of 

methane production at three categories of landfill sites: LGHI = high rate of landfill gas production, 

LGLo = low rate of landfill gas production, and LGLVo = very low rate of landfill gas production. 

The values shown in Table 4-28 represent an upper bound on the amount of new landfill capacity 

that can be added in each of the indicated model regions for each of the three landfill categories. 

The cost and performance assumptions for adding new capacity in each of the three landfill 

categories are presented in Table 4-16. 

Table 4-28 Regional Assumptions on Potential Electric Capacity from New Landfill Gas 

Units (MW) 

NEMS Class 

Region IPM Region LGHI LGLo LGLVo 

ECAR RFCO, MECS, RFCP, TVAK 72 30 539 

ERCOT ERCT 12 26 316 

MAAC MACE, MACS, MACW 93 22 311 

MAIN WUMS, COMD, GWAY 83 92 495 

MAPP MRO 43 22 150 

NY DSNY, LILC, NYC, UPNY 54 27 142 

NE NENG 62 6 51 

FL FRCC 14 26 158 
4-44 

NEMS Class 

Region IPM Region LGHI LGLo LGLVo 

STV SOU, TVA, ENG, VACA, VAPW 68 22 447 

SPP SPPN, SPPS 5 - 185 

NWP PNW, NWPE 27 58 185 

RA AZNM, SNV, RMPA - - 91 

CNV NA-N, CA-S 131 250 749 

US 664 581 3,819 

4.5 Nuclear Units 

4.5.1 Existing Nuclear Units 

Population, Plant Location, and Unit Configuration: To provide maximum granularity in forecasting 

the behavior of existing nuclear units, all 105 nuclear units in EPA Base Case v.4.10 are 

represented by separate model plants. As noted in Table 4-7 the 105 nuclear units include 104 

currently operating units plus Watts Bar Nuclear Plant, Unit 2, which is scheduled to come online 

in 2014. All are listed in Appendix 4-3. The population characteristics, plant location, and unit 

configuration data in NEEDS, v.4.10 were obtained primarily from EIA Form 860 and AEO 2010. 

Capacity: Nuclear units are baseload power plants with high fixed (capital and fixed O&M) costs 

and low variable (fuel and variable O&M) costs. Due to their low VOM and fuel costs, nuclear 

units are run to the maximum extent possible, i.e., up to their availability. Consequently, a nuclear 

unit's capacity factor is equivalent to its availability. Thus, EPA Base Case v.4.10 uses capacity 

factor assumptions to define the upper bound on generation from nuclear units. Nuclear capacity 

factor assumptions in EPA Base Case v.4.10 are based on an Annual Energy Outlook projection 

algorithm. The nuclear capacity factor projection algorithm is described below: 

• For each reactor, the capacity factor over time is dependent on the age of the reactor. 

• Capacity factors increase initially due to learning, and decrease in the later years due to 

aging. 

• For individual reactors, vintage classifications (older and newer) are used. 

• For the older vintage (start before 1982) nuclear power plants, the performance peaks at 25 

years: 

o Before 25 years: Performance increases by 0.5 percentage point per year; 

o 25-60 years: Performance remains flat; and 

• • For the newer vintage (start in or after 1982) nuclear power plants, the performance peaks 

at 30 years: 

o Before 30 years: Performance increases by 0.7 percentage points per year; 

o 30-60 years: Performance remains flat; and 

• The maximum capacity factor is assumed to be 90 percent. That is, any given reactor is not 

allowed to grow to a capacity factor higher than 90 percent. However, if a unit began with a 

capacity factor above 90 percent, it is allowed to retain that capacity factor. Given historical 

capacity factors above 90 percent, the projected capacity factors range from 89 percent to 93 

percent. 

Cost and Performance: Unlike non-nuclear existing conventional units discussed in section 4.2.7, 

emission rates are not needed for nuclear units, since there are no SO2, NOX, CO2, or mercury 

emissions from nuclear units. 

As with other generating resources, EPA Base Case v.4.10 uses variable operation and 

maintenance (VOM) costs and fixed operation and maintenance (FOM) costs to characterize the 

cost of operating nuclear units. The heat rate, FOM, and VOM values from AEO 2010, which 

were used to characterize the cost and performance of existing nuclear units in EPA Base Case 

v.4.10 are shown in Appendix 4-03. 
4-45 

EPA Base Case v.4.10 also uses the nuclear capacity uprates from AEO 2010. These are shown 

in Table 4-29. 

4.5.2 Potential Nuclear Units 

The cost and performance assumptions for nuclear potential units that the model has the option to 

build in EPA Base Case v.4.10 are shown in Table 4-13 above. The cost assumptions were 

updated as part of the comparative analysis performed by EPA’s power sector engineering staff. 

That update is described above in section 4.4.1. 

Table 4-29 Nuclear Upratings (MW) as Incorporated in EPA Base Case v.4.10 from AEO 

2010 

Name Plant ID Unit ID Year Change in MWs 

Arkansas Nuclear One 8055 1 2016 50.0 

Arkansas Nuclear One 8055 2 2016 59.0 

Brunswick 6014 1 2014 56.3 

Brunswick 6014 2 2014 56.2 

Byron Generating Station 6023 1 2019 116.4 

Byron Generating Station 6023 2 2019 11.4 

Catawba 6036 1 2016 67.7 

Catawba 6036 2 2016 67.7 

Duane Arnold 1060 1 2015 34.8 

Fermi 1729 2 2016 67.0 

Grand Gulf 6072 1 2015 76.7 

Harris 6015 1 2017 54.0 

Joseph M Farley 6001 1 2017 51.0 

Joseph M Farley 6001 2 2017 52.0 

Limerick 6105 1 2018 113.4 

Limerick 6105 2 2018 113.4 

McGuire 6038 1 2014 110.0 

McGuire 6038 2 2014 110.0 

Oconee 3265 1 2017 51.0 

Oconee 3265 2 2017 51.0 

Oconee 3265 3 2017 51.0 

Peach Bottom 3166 2 2014 66.7 

Peach Bottom 3166 3 2014 66.7 

Perry 6020 1 2016 74.0 

PSEG Salem Generation 2410 1 2015 70.4 

PSEG Salem Generation 2410 2 2015 67.8 

Quad Cities Generation 880 1 2013 52.0 

Quad Cities Generation 880 2 2013 52.0 

Sequoyah 6152 1 2013 69.0 

Sequoyah 6152 2 2013 68.0 

South Texas Project 6251 1 2013 76.8 

South Texas Project 6251 2 2013 76.8 

Surry 3806 1 2015 47.9 

Surry 3806 2 2015 47.9 

V C Summer 6127 1 2015 58.0 

Waterford 3 4270 3 2016 69.1 

Wolf Creek Generation 210 1 2017 70.0 

Watts Bar Nuclear Plant 7722 2 2014 1,180 
Appendix 4-1.1 

Appendix 4-1 Representative Wind Generation Profiles in EPA Base Case 

v.4.10 

Illustrative Hourly Wind Generation Profile (kWh of Generation per MW of Electricity) 

 

Winter Wind Class Wind Class 

Hour 3 4 5 6 7 

Summer 

Hour 3 4 5 6 7 

01 268 361 492 504 635 01 380 410 456 591 555 

02 268 359 488 503 633 02 374 402 444 583 546 

03 269 355 483 498 629 03 366 391 422 566 523 

04 263 345 464 483 613 04 350 368 387 535 479 

05 253 326 430 454 580 05 326 334 337 489 413 

06 243 310 396 424 544 06 299 295 286 433 344 

07 236 297 374 402 518 07 282 261 250 389 295 

08 233 291 372 395 514 08 292 256 248 384 293 

09 230 282 371 391 511 09 320 270 269 408 316 

10 227 276 372 389 510 10 348 296 298 442 348 

11 225 276 374 391 510 11 368 320 320 466 368 

12 226 280 376 394 508 12 381 340 331 480 373 

13 226 283 376 396 505 13 388 354 334 484 370 

14 228 287 381 400 507 14 393 365 341 489 372 

15 227 288 385 402 511 15 393 372 350 496 383 

16 228 289 390 404 517 16 390 371 361 501 398 

17 231 289 394 406 524 17 384 358 369 501 414 

18 240 296 405 415 538 18 377 340 371 496 421 

19 250 309 423 433 558 19 375 331 378 496 431 

20 259 325 444 453 580 20 374 335 386 500 440 

21 267 339 464 473 601 21 378 354 402 518 464 

22 271 350 479 488 618 22 382 381 424 546 498 

23 271 357 488 498 629 23 384 401 444 572 529 

24 268 360 491 502 633 24 382 409 455 586 547 

Winter 

Average 246 314 421 437 559 Summer Average 362 346 361 498 422 

Notes:

Based on Onshore Wind in Model Region CA-N. 

This is an example of the wind data used in EPA Base Case v.4.10 
Appendix 4-2.1 

Appendix 4-2 Representative Solar Generation Profiles in EPA Base v.4.10 

Illustrative Hourly Solar Generation Profile (kWh of Generation per MW of Electricity) 

 

Winter 

Hour 

Solar 

Thermal 

Solar 

Photovoltaic Summer Hour 

Solar 

Thermal 

Solar 

Photovoltaic 

01 3 0 01 9 0 

02 3 0 02 9 0 

03 3 0 03 9 0 

04 3 0 04 9 0 

05 3 0 05 9 0 

06 181 29 06 284 13 

07 181 29 07 284 13 

08 601 660 08 720 610 

09 601 660 09 720 610 

10 601 660 10 720 610 

11 601 660 11 720 610 

12 601 660 12 720 610 

13 601 660 13 720 610 

14 601 660 14 720 610 

15 601 660 15 720 610 

16 601 660 16 720 610 

17 601 660 17 720 610 

18 601 660 18 720 610 

19 181 29 19 284 13 

20 181 29 20 284 13 

21 181 29 21 284 13 

22 181 29 22 284 13 

23 181 29 23 284 13 

24 181 29 24 284 13 

Winter 

Average 336 312 Summer Average 426 284 

Notes:

Based on model region AZNM. 

This is an example of the solar data used in EPA Base Case v.4.10 
Appendix 4-3.1 

Appendix 4-3 Characteristics of Existing Nuclear Units 

Region State Plant Name 

ORIS 

Code_Unit 

Id 

On-Line 

Year 

Capacit

y (MW) 

Heat Rate 

(Btu/kWh) 

FO

(20

/kW

Palo Verde 6008_1 1986 1,311 10,427 11

AZNM Arizona Palo Verde 6008_2 1986 1,352 10,427 11

Palo Verde 6008_3 1988 1,283 10,427 11Diablo Canyon 6099_1 1985 1,122 10,427 13

CA-N California 

Diablo Canyon 6099_2 1986 1,118 10,427 13San Onofre 360_2 1983 1,070 10,427 20

CA-S California 

San Onofre 360_3 1984 1,080 10,427 20Braidwood Generation Station 6022_1 1988 1,178 10,427 12Braidwood Generation Station 6022_2 1988 1,152 10,427 12Byron Generating Station 6023_1 1985 1,164 10,427 12Byron Generating Station 6023_2 1987 1,136 10,427 12LaSalle Generating Station 6026_1 1984 1,118 10,427 15LaSalle Generating Station 6026_2 1984 1,120 10,427 15Dresden Generating Station 869_2 1970 867 10,427 20Dresden Generating Station 869_3 1971 867 10,427 20Quad Cities Generating Station 880_1 1972 867 10,427 17

COMD Illinois 

Quad Cities Generating Station 880_2 1972 867 10,427 17Indian Point 2 2497_2 1973 1,020 10,427 22

DSNY New York 

Indian Point 3 8907_3 1976 1,025 10,427 19Arkansas Nuclear One 8055_1 1974 836 10,427 15

Arkansas 

Arkansas Nuclear One 8055_2 1980 988 10,427 15Waterford 3 4270_3 1985 1,152 10,427 16

Louisiana 

River Bend 6462_1 1986 967 10,427 19

ENTG 

Mississippi Grand Gulf 6072_1 1985 1,266 10,427 13
Appendix 4-3.2 

Region State Plant Name 

ORIS 

Code_Unit 

Id 

On-Line 

Year 

Capacit

y (MW) 

Heat Rate 

(Btu/kWh) 

FO

(20

/kW

Comanche Peak 6145_1 1990 1,202 10,240 12Comanche Peak 6145_2 1993 1,202 10,317 12South Texas Project 6251_1 1988 1,280 10,427 12

ERCT Texas 

South Texas Project 6251_2 1989 1,280 10,427 12St Lucie 6045_1 1976 839 10,427 14St Lucie 6045_2 1983 714 10,427 14Turkey Point 621_3 1972 693 10,427 14Turkey Point 621_4 1973 693 10,427 14

FRCC Florida 

Crystal River 628_3 1977 851 10,427 18

Illinois Clinton Power Station 204_1 1987 1,043 10,427 20

GWAY 

Missouri Callaway 6153_1 1984 1,190 10,427 13

PSEG Salem Generating Station 2410_1 1977 1,174 10,427 15PSEG Salem Generating Station 2410_2 1981 1,130 10,427 15Oyster Creek 2388_1 1969 619 10,427 25

New Jersey 

PSEG Hope Creek Generating Station 6118_1 1986 1,196 10,427 14Limerick 6105_1 1986 1,134 10,427 12

MACE 

Pennsylvania Limerick 6105_2 1990 1,134 10,427 12

Calvert Cliffs Nuclear Power Plant 6011_1 1975 885 10,427 15

MACS Maryland Calvert Cliffs Nuclear Power Plant 6011_2 1977 874 10,427 15

Peach Bottom 3166_2 1974 1,112 10,427 17Peach Bottom 3166_3 1974 1,112 10,427 17PPL Susquehanna 6103_1 1983 1,283 10,427 17PPL Susquehanna 6103_2 1985 1,288 10,427 17

MACW Pennsylvania 

Three Mile Island 8011_1 1974 786 10,427 17Fermi 1729_2 1988 1,122 10,427 15

MECS Michigan Palisades 1715_1 1972 778 10,427 19
Appendix 4-3.3 

Region State Plant Name 

ORIS 

Code_Unit 

Id 

On-Line 

Year 

Capacit

y (MW) 

Heat Rate 

(Btu/kWh) 

FO

(20

/kW

Iowa Duane Arnold 1060_1 1975 581 10,427 20

Monticello 1922_1 1971 646 10,427 18

Minnesota Prairie Island 1925_1 1974 551 10,427 16

Prairie Island 1925_2 1974 545 10,427 16Fort Calhoun 2289_1 1973 478 10,427 21

MRO 

Nebraska 

Cooper 8036_1 1974 767 10,427 22Millstone 566_2 1975 882 10,427 20

Connecticut 

Millstone 566_3 1986 1,236 10,427 19

Massachusetts Pilgrim Nuclear Power Station 1590_1 1972 685 10,427 24

New 

Hampshire Seabrook 6115_1 1990 1,244 10,427 17

NENG 

Vermont Vermont Yankee 3751_1 1972 620 10,427 20

PNW Washington Columbia Generating Station 371_2 1984 1,131 10,427 15

Donald C Cook 6000_1 1975 1,029 10,942 17

Michigan Donald C Cook 6000_2 1978 1,077 10,848 17

Perry 6020_1 1987 1,231 11,000 16

RFCO 

Ohio 

Davis Besse 6149_1 1977 887 11,000 15Beaver Valley 6040_1 1976 887 10,962 19

RFCP Pennsylvania Beaver Valley 6040_2 1987 887 10,946 19

Joseph M Farley 6001_1 1977 851 11,794 13

Alabama 

Joseph M Farley 6001_2 1981 860 11,650 13Edwin I Hatch 6051_1 1975 876 10,427 14Edwin I Hatch 6051_2 1979 883 10,427 14Vogtle 649_1 1987 1,172 10,427 14

SOU 

Georgia 

Vogtle 649_2 1989 1,169 10,427 14

SPPN Kansas Wolf Creek Generating Station 210_1 1985 1,166 10,427 13
Appendix 4-3.4 

Region State Plant Name 

ORIS 

Code_Unit 

Id 

On-Line 

Year 

Capacit

y (MW) 

Heat Rate 

(Btu/kWh) 

FO

(20

/kW

Browns Ferry 46_1 1974 1,225 10,550 99

Alabama Browns Ferry 46_2 1975 1,286 10,215 99

Browns Ferry 46_3 1977 1,337 10,215 99Sequoyah 6152_1 1981 1,150 10,123 11Sequoyah 6152_2 1982 1,127 10,202 11Watts Bar Nuclear Plant 7722_1 1996 1,121 10,266 13

TVA 

Tennessee 

Watts Bar Nuclear Plant 7722_2 2014 1,180 10,266 92Nine Mile Point Nuclear Station 2589_1 1969 621 10,427 19Nine Mile Point Nuclear Station 2589_2 1969 1,311 10,427 18James A Fitzpatrick 6110_1 1976 852 10,427 20

UPNY New York 

R. E. Ginna Nuclear Power Plant 6122_1 1970 498 10,427 20Brunswick 6014_1 1977 938 10,318 11Brunswick 6014_2 1975 937 10,397 11Harris 6015_1 1987 900 10,982 13McGuire 6038_1 1981 1,100 10,427 11

North Carolina 

McGuire 6038_2 1984 1,100 10,427 11H B Robinson 3251_2 1971 710 10,697 11Oconee 3265_1 1973 846 10,427 13Oconee 3265_2 1974 846 10,427 13Oconee 3265_3 1974 846 10,427 13Catawba 6036_1 1985 1,129 10,427 13Catawba 6036_2 1986 1,129 10,427 13

VACA 

South Carolina 

V C Summer 6127_1 1984 966 10,427 14Surry 3806_1 1972 799 10,427 12Surry 3806_2 1973 799 10,427 12North Anna 6168_1 1978 940 10,427 98

VAPW Virginia 

North Anna 6168_2 1980 925 10,427 98
Appendix 4-3.5 

Region State Plant Name 

ORIS 

Code_Unit 

Id 

On-Line 

Year 

Capacit

y (MW) 

Heat Rate 

(Btu/kWh) 

FO

(20

/kW

Point Beach 4046_1 1970 599 10,427 20

WUMS Wisconsin Point Beach 4046_2 1972 601 10,427 20

Kewaunee 8024_1 1974 556 10,427 15