4-1 

## 4 Generating Resources “Existing”, “planned-committed”, and “potential” ar e 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 brok en ground (initiated construction) or secured financing are termed “planned-committed”. “Potentia l” units refer to new generating options used in IPM for capacity expansion projections of t he 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 informa tion 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 summari zes 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 th rough 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 confi guration. 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 Source 1 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; boileridentification, location, status, and design information; and postcombustion NO X 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 Administra tion (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, SO 2 and NO X controls, and SO 2 and NO X 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 wher e 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 14,468 950,8894-4 4.2.2 Capacity The NEEDS unit capacity values implemented in EPA Base Case v.4.10 reflect net summer dependable capacity 16 , 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 theboiler 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 4-5summarizes the algorithm used for parsing capacity with data on maximum steam flow and boilergenerator mapping. In Table 4-5 MFB i refers to the maximum steam flow of boiler i and MW G j refers to the capacity of generator j . The algorithm uses the available data to derive the capacity of a boiler, referred to as MW B j in Table 4-5.

Table 4-5 Capacity-Parsing Algorithm for Steam Units in NEEDS v.4.10 Type of Boiler-Generator Links One-to-One One-to-Many Many-to-One Many-to-Many For Boiler B 1 to B N linked to Generators G 1 to G N MW B i = MW G j MW B i = Σ

j MW G j MW B i = (MF B i / Σ i MF Bi ) * MW G j MW B i = (MF B i / Σ i MF B i ) * Σ j MW G j

Notes: MF B i = maximum steam flow of boiler i MW G j = electric generation capacity of generator j

16 As used here, net summer dependable capacity is the net capability of a generating unit in megawatts (MW) for daily planning and operation pur poses 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 wa s 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 associ ated 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 mu st 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 m odel 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 obligati ons 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 specificat ion 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. NEED S 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 sim ilar 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 obtai n state-level results directly from IPM outputs. In addition, the aggregation scheme supports m odeling 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, SO 24-6 emission rates and environmental regulations am ong 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

SO 2 Pollution Control NSR Settlement or Utility/RPO Comments EPA’s Emission Tracking System (ETS) - 2006 2005 EIA 767 See Note No Control

NO x 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

17 For 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 chapt er 5 for a detailed description of the sulfur dioxide (scrubber) and mercury (ACI) retrofit opti ons.) (2) The “Number of IPM Model Plants” shown for many of the “Plant Types” in the “Retro fits” block in Table 4-7 exceeds the “Number of IPM Model Plants” shown for “Plant Type” “C oal 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 technologi es simultaneously in Stage 1). (3) Since only a subset of coal plants is eligible for certain retrof its, many of the “Plant Types” in the “Retrofits” block that represent only a single retrofit te chnology (e.g., “Retrofit Coal with Selective Noncatalytic Reduction (SNCR)”) have a “Number of of IPM Model Plants” that is a smaller than4-7 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_Other 1 241 73
Nuclear 2 105 105
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 technol ogy 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, convent ional 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 Selectiv e 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 munici pal 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 c ontains 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 associat ed with producing a unit of electricity. If the generating unit contains pollution control equipm ent, 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 we re 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 SO 2 Control Hg Control NO x Control Variable O&M Range (mills/kWh)
No NO x 2.63 - 7.67 Combined Cycle -- -- SCR 2.75 - 7.79
No NO x 3.66 - 5.05

SCR 4.34 - 5.73 No Hg
SNCR 4.73 - 6.12
No NO x 4.62 - 6.02

SCR 5.30 - 6.69 Scrubbed - Dry

ACI
SNCR 5.70 - 7.09
No NO x 2.48 - 3.87

SCR 3.16 - 4.55 No Hg
SNCR 3.55 - 4.94
No NO x 3.44 - 4.83

SCR 4.12 - 5.51 Scrubbed - Wet
ACI
SNCR 4.51 - 5.91
No NO x 0.90 - 2.29

SCR 1.58 - 2.97 No Hg
SNCR 1.97 - 3.37
No NO x 1.87 - 3.26

SCR 2.54 - 3.94 Coal Steam

Unscrubbed

ACI
SNCR 2.94 - 4.33 Conventional Hydroelectric -- -- -- 6.66

No NO x 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 -- -- -- 8.794-10 Capacity Type SO 2 Control Hg Control NO x Control Variable O&M Range (mills/kWh)
No NO x 0.94 - 5.07 Scrubbed - Wet No Hg SNCR 1.49 - 5.62
No NO x 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 fix ed 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 expr essed 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.

SO 2 Rates Section 3.9.1 contains a detailed discussion of SO 2 rates for existing units.

NO x Rates Section 3.9.2 contains a detailed discussion of NO x rates for existing units.

Mercury Emission Modification Factors (EMF) Mercury EMF refers to the ratio of mercury emi ssions (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 requir ed 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 SO 2 Control Hg Control NO x 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 20-30 years 8.5 Gas Turbine Oil & Gas -- -- -- 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 NO x

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 NO x

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 NO x

Greater than 40 Years 61.8

0 to 20 Years 43.8 Steam Turbine Coal

Scrubbed - Wet No Hg

SCR

20 to 30 Years 45.84-12 Prime Mover Type Primary Fuel SO 2 Control Hg Control NO x 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 NO x

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 NO x

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 NO x

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 NO x

Greater than 40 Years 28.4 Oil & Gas -- --

SCR 0 to 20 Years 19.34-13 Prime Mover Type Primary Fuel SO 2 Control Hg Control NO x 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, NEED S 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 samemodel 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 84-15 IPM Region Plant Type Capacity (MW) Pumped Storage 40 Solar 255 Wind 112 Combined Cycle 573 Landfill Gas 6 COMD Wind 282 DSNY Combined Cycle 635 Biomass 14 Coal Steam 665 ENTG 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 Landfill Gas 5 GWAY Wind 1,177

LILC Combined Cycle 350 Combustion Turbine 105 Landfill Gas 27 O/G Steam 9 MACE

Solar 7 Combustion Turbine 30 Landfill Gas 5 MACS 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 54-16 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 Solar 112 SNV Wind 189 Biomass 116 SOU Combined Cycle 1,2374-17 IPM Region Plant Type Capacity (MW) Non-Fossil Waste 18 Coal Steam 1,172 Combustion Turbine 845 SPPN 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 Combustion Turbine 200 TVAK 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 pl anned-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 y ear 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 A nnual Energy Outlook (AEO) published by the U.S. Department of Energy’s Energy Information Admi nistration. 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, i ndustry, academia, and various non-governmental organizations. The key sources reviewed included:

• U.S. Energy Information Administration: Annual Energy Outlook 2008, 2009, 2010 18

• National Energy Technology Laboratory, Fo ssil Energy Power Plant Desk Reference (Bituminous Coal) 19

18 U.S. Department of Energy, Energy Informati on 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 Informati on 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 Informati on 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, Nati onal 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, Envi ronmental Footprints and Costs of Coal-Based Integrated Gasification Combined Cy cle and Pulverized Coal Technologies 20

• EPRI (Electric Power Research Institute): “Economic Assessment of Advanced Coal-Based Power Plants with CO 2 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 Economy 24

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 Tabl e 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 tec hnologies: supercritical pulverized coal, advanced combined cycle, advanced combustion turbines, in tegrated 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., electric al 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 co st. 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%20Per formance%20Baseline-012908.pdf

20 U.S. EPA, Environmental Footprints and Costs of Coal-Based Integrated Gasification Combined Cycle and Pulverized Coal Technologies. EPA-430/R-06/2006, July 2006.

21 Booras, 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.

22 Al-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

23 Du, 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

24 Cleetus 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/solu tions/big_picture_solutions/climate-2030- blueprint.html#Download_the_Climate_2030_Blueprint_repo4-20Table 4-13 Performance and Unit Cost Assumptions for Potential (New) Capacity from Conventional Technologies in EPA Base Casev4.10AdvancedCombinedCycleAdvancedCombustionTurbineNuclearIntegratedGasificationCombinedCycle –BituminousIntegratedGasificationCombined Cycle– SubbituminousAdvancedCoal withCarbonCaptureBituminous1Advanced Coalwith CarbonCapture –Subbituminous1SupercriticalPulverizedCoal - WetBituminousSupercriticalPulverizedCoal - DrySubBituminousSize (MW)5601701350600600500500600600First YearAvailable201520122017201320132015201520132013Lead Time (Years)326444444Vintage #1(years covered)2012 -20542012 - 20542012 -20542012 - 20542012 - 20542012 - 20542015 - 20542012 - 20542012 - 2054Availability87%92%90%85%85%85%85%85%85%Vintage #1Heat Rate(Btu/kWh)6,81010,72010,4008,4248,06210,1499,7138,8748,937Capital2(2007$/kW)9766984,6213,2653,3104,7204,7852,9183,008Fixed O&M(2007$/kW/yr)14.412.392.447.948.260.561.028.928.6Variable O&M(2007$/MWh)2.573.590.771.321.151.671.463.432.27Notes:1For The term “Advanced Coal with Carbon Capture” is used here and in the output files for EPA Base Case v.4.10 to represent a variety oftechnologies that are expected to provide carbon capture capabilities. These include both supercritical steam generators withcarbon capture andintegrated gasification combined cycle (IGCC) with carbon capture. Although IGCC with carbon capture was used to define the cost andperformance parameters that are implemented in EPA Base Case v.4.10, projections of “Advanced Coal with Carbon Capture” in EPABase Casev.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 pr oduced 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 te chnological 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, w hereas 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 (k Wh). Availability indicates the percentage of time that a generating unit is available to provide el ectricity 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 cost s. This is done through the application of regional adjustment factors which capture regional differenc es in labor, material, and construction costs. The regional adjustment factors used in EPA Base Case v.4.10 are shown in Table 4-15. They4-22 were developed from AEO and are applied to both c onventional technologies shown in Table 4-13 and to the renewable and non-conventional te chnologies shown in Table 4-16 below.4-23Table 4-14 Short-Term Capital Cost Adders forNew Power Plants in EPA Base Case v.4.10 (2007$)2012201520202030IDNumberPlant TypeStep 1Step 2Step 3Step 1Step 2Step 3Step 1Step 2Step 3Step 1Step 2Step 3Upper Bound (MW)600400--1,8001,200--3,0002,000--6,0004,000--1BiomassAdder ($/kW)--1,4103,646--1,4103,646--1,4103,646--1,4103,646Upper Bound (MW)8,4345,622--25,30116,867--42,16828,112--84,33656,224--2Coal SteamAdder ($/kW)--9672,500--9672,500--9672,500--9672,500Upper Bound (MW)46,46930,979--139,40692,937--232,344154,896--464,687309,791--3CombinedCycleAdder ($/kW)--310801--310801--310801--310801Upper Bound (MW)24,09816,066--72,29548,197--120,49280,328--240,984160,656--4CombustionTurbineAdder ($/kW)--213551--213551--213551--213551Upper Bound (MW)600400--1,8001,200--3,0002,000--6,0004,000--5Fuel CellAdder ($/kW)--1,9875,138--1,9875,138--1,9875,138--1,9875,138Upper Bound (MW)315210--946630--1,5761,051--3,1522,102--6GeothermalAdder ($/kW)--1,9815,123--1,9815,123--1,9815,123--1,9815,123Upper Bound (MW)2,4001,600--7,2004,800--12,0008,000--24,00016,000--7IGCC andAdvancedCoal withCarbonCaptureAdder ($/kW)--1,0722,774--1,0722,774--1,0722,774--1,0722,774Upper Bound (MW)600400--1,8001,200--3,0002,000--6,0004,000--8Landfill GasAdder ($/kW)--1,1352,936--1,1352,936--1,1352,936--1,1352,936Upper Bound (MW)11,2307,487--33,69022,460--56,15137,434--112,30174,867--9NuclearAdder ($/kW)--1,5794,083--1,5794,083--1,5794,083--1,5794,083Upper Bound (MW)10670--317211--528352--1,056704--10SolarThermalAdder ($/kW)--1,6084,158--1,6084,158--1,6084,158--1,6084,158Upper Bound (MW)5436--5436--9060--180120--11Solar PVAdder ($/kW)--1,7334,483--1,7334,483--1,7334,483--1,7334,4834-242012201520202030IDNumberPlant TypeStep 1Step 2Step 3Step 1Step 2Step 3Step 1Step 2Step 3Step 1Step 2Step 3Upper Bound (MW)23,00019,670--29,50519,670--49,17432,783--98,34865,566--12OnshoreWindAdder ($/kW)--6461,672--6461,672--6461,672--6461,672Upper Bound (MW)600400--1,8001,200--3,0002,000--6,0004,000--13OffshoreWindAdder ($/kW)--1,3043,373--1,3043,373--1,3043,373--1,3043,373Note:The term “Advanced Coal with Carbon Capture” is used here and in the output files for EPA Base Case v.4.10 to represent a variety oftechnologies that are expected to provide carbon capture capabilities. These include both supercritical steam generators withcarbon capture andintegrated gasification combined cycle (IGCC) with carbon capture. Although IGCC with carbon capture was used to define the cost andperformance parameters that are implemented in EPA Base Case v.4.10 and shown in Table 4-13, projections of “Advanced Coal withCarbonCapture” 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 tec hnologies 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 tec hnology. 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 followi ng subsections. Also discussed below are additional4-26 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.4.10.4-27Table 4-16 Performance and Unit Cost Assumptions for Potential (New) Renewable and Non-Conventional Technology Capacity in EPABase Case v4.10Landfill GasBiomassConventionalBoiler1BiomassGasificationCombinedCycle1FuelCellsGeothermalLGHILGLoLGVLoSolarPhotovoltaicSolarThermalOnshoreWindOffshoreWindSize (MW)3512010503051005050First Year Available201320192013201420132012201320132013Lead Time (Years)343432333Vintage #1(years covered)2012 -20192012 -20192012 -20192012 - 20192012 -20192012 -20192012 -2019Vintage #2(years covered)2020 -20292020 -20292020 -20292020 - 20292020 -20292020 -20292020 -2029Vintage #3(years covered)2012 - 20542020 - 20542012 -20542012 - 20542030 -20542030 -20542030 -20542030 - 20542030 -20542030 -20542030 -2054Availability85%85%87%87%90%90%90%95%95%Generation CapabilityEconomic DispatchGeneration ProfileVintage #1Heat Rate (Btu/kWh)13,500-7,93029,655 -397,03513,64813,64813,6480000Capital (2007$/kW)24,698-6,2591,624 -20,6742,5963,2705,0355,7655,1561,9543,852 -5,085Fixed O&M (2007$/kW/yr)85.2-5.7151 - 219114.3114.3114.311.756.830.389.5Variable O&M (2007$/MWh)11.60-47.920.000.010.010.01000.000.00Vintage #2Heat Rate (Btu/kWh)-9,800--13,64813,64813,6480000Capital (2007$/kW)2-4,071--2,5053,1564,8595,3504,6411,9123,621 -4,780Fixed O&M (2007$/kW/yr)-48.3--114.3114.3114.311.756.830.389.5Variable O&M (2007$/MWh)-8.83--0.010.010.01000.000.00Vintage #3Heat Rate (Btu/kWh)----13,64813,64813,6480000Capital (2007$/kW)2----2,0192,5443,9163,7774,3831,5802,809 -3,708Fixed O&M (2007$/kW/yr)----114.3114.3114.311.756.830.389.5Variable O&M (2007$/MWh)----0.010.010.01000.000.00Note:1The biomass generating technologies shown inthis table represent new capacity designed to burn biomass only. Assumptions forbiomass co-firing at existing coal plants can befound 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 vi ntage 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 ma rket 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 4 9 -- -- 163 MACE 5 -- -- -- 2 3 8 -- -- 57 4 2 5 -- 10 MACS 5 -- -- -- 3 3 700 1,054 1,747 2,412 4 182 -- 636 477 5 71 -- 200 161 MACW

6 -- 26 -- 464-30 Cost Class IPM Region Wind Class 1 2 3 4 3 3,571 -- -- 35,633 4 -- -- 467 259 MECS 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 4 1,933 9,618 37,341 163,483 SPPN 5 -- -- -- 8394-31 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
4 57 49 64 84 WUMS
5 -- -- -- 414-32 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 4 15,191 30,382 30,382 ERCT 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 34-33 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 4 253 506 506 NYC 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 4 4,903 9,806 9,806 SOU 5 311 621 621 3 884 1,768 1,768 4 859 1,718 1,718 UPNY 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 1,3604-34 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 5 1,100 2,200 2,200 COMD 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 4 53,858 107,715 107,715 FRCC 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 3,5244-35 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 5 1,162 2,323 2,323 RFCO 6 507 1,014 1,014 3 8,765 17,529 17,529 4 15,055 30,109 30,109 SOU 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 5 6,536 13,073 13,073 VACA 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 78,1194-36 Generation Profiles : Unlike other renewable generation technologies, which dispatch on an economic basis subject to their availability c onstraint, wind and solar technologies can only be dispatched when the wind blows and the sun shi nes. 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 pr ofiles 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 capacit y 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 determi ne 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 s hare 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 le ss 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 Contribut ion 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 C ontribution 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 C ontribution 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 model 25 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 highes t 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 obt ain the capital cost for a particular new wind model plant, the base capital costs shown in T able 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 2.5 1 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 determi nes that adding wind capacity yields the greatest incremental improvement in the system-wide (leas t 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 contri bution, 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.

25 Revising 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 ( G W ) per available MW per hour = 559 kWh/MW Appendix 4-1 Summer average generation ( G S ) per available MW per hour = 422 kWh/MW Hours in Winter ( H W ) season (October – April) = 5,088 hours Hours in Summer ( H S )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 ( Cap 2020 ) in vintage range for year 2020 = $1,912/kW Table 4-23 Capital Cost Adjustment Factor ( CAF ON,C2 ) for onshore cost class 2 = 1.2 Table 4-15 Regional Factor (RF) 1.058

Calculations



### GWh hours MW kWh MW hours MW kWh MW H G C H G C Potential Generation

s S w W



### 546

, 1 3672 / 422 352 5088 / 559 352

= × × + × × = × × + × × =



### MW MW C RM

84 352 % 24 on Contributi Margin Reserve

= × = × =

dollars million MW C RF Cost Capital



### 54 8 $ 352 058

. 1 1.2 $1,912/MW CAF Cap C2 ON, 2020



### = × × × = × × × =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 r egions 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 technologies 26 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 7 2,873 185.1 CA-N 80 4,214 206.2 71 4,957 185.1 48 5,679 185.1 CA-S
5 6,817 185.1

26 In 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 so me 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) Class NEMS 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 1584-44 Class NEMS 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 populat ion 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. D ue 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 gener ation 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 pr ojection 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 classi fications (older and newer) are used.

• For the older vintage (start before 1982) nucl ear 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 SO 2 , NO X , CO 2 , 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 pot ential 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 Incor porated 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 1,180Appendix 4-1.1 

### Appendix 4-1 Representative Wind Gene ration Profiles in EPA Base Case v.4.10 Illustrative Hourly Wind Generation Profile (kWh of Generation per MW of Electricity)

Wind Class Wind Class Winter

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.4.10Appendix 4-2.1 

### Appendix 4-2 Representative Solar Gene ration 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.4.10Appendix 4-3.1Appendix 4-3 Characteristicsof Existing Nuclear UnitsRegionStatePlant NameORISCode_UnitIdOn-LineYearCapacity (MW)Heat Rate(Btu/kWh)FOM(2007$/kW-yr)VOM(2007mills/kWh)Palo Verde6008_119861,31110,427117.20.50Palo Verde6008_219861,35210,427117.20.55AZNMArizonaPalo Verde6008_319881,28310,427117.20.52Diablo Canyon6099_119851,12210,427132.10.71CA-NCaliforniaDiablo Canyon6099_219861,11810,427132.10.70San Onofre360_219831,07010,427208.61.00CA-SCaliforniaSan Onofre360_319841,08010,427208.61.05Braidwood Generation Station6022_119881,17810,427129.70.57Braidwood Generation Station6022_219881,15210,427129.70.59Byron Generating Station6023_119851,16410,427126.40.57Byron Generating Station6023_219871,13610,427126.40.56LaSalle Generating Station6026_119841,11810,427157.90.75LaSalle Generating Station6026_219841,12010,427157.90.76Dresden Generating Station869_2197086710,427203.60.89Dresden Generating Station869_3197186710,427203.60.95Quad Cities Generating Station880_1197286710,427177.30.83COMDIllinoisQuad Cities Generating Station880_2197286710,427177.30.83Indian Point 22497_219731,02010,427227.31.40DSNYNew YorkIndian Point 38907_319761,02510,427199.20.96Arkansas Nuclear One8055_1197483610,427152.60.63ArkansasArkansas Nuclear One8055_2198098810,427152.60.65Waterford 34270_319851,15210,427162.70.61LouisianaRiver Bend6462_1198696710,427193.71.03ENTGMississippiGrand Gulf6072_119851,26610,427134.80.54Appendix 4-3.2RegionStatePlant NameORISCode_UnitIdOn-LineYearCapacity (MW)Heat Rate(Btu/kWh)FOM(2007$/kW-yr)VOM(2007mills/kWh)Comanche Peak6145_119901,20210,240120.00.61Comanche Peak6145_219931,20210,317120.00.63South Texas Project6251_119881,28010,427121.60.59ERCTTexasSouth Texas Project6251_219891,28010,427121.60.58St Lucie6045_1197683910,427142.30.64St Lucie6045_2198371410,427142.30.71Turkey Point621_3197269310,427146.80.67Turkey Point621_4197369310,427146.80.66FRCCFloridaCrystal River628_3197785110,427181.50.81IllinoisClinton Power Station204_119871,04310,427200.10.97GWAYMissouriCallaway6153_119841,19010,427139.70.74PSEG Salem Generating Station2410_119771,17410,427159.90.77PSEG Salem Generating Station2410_219811,13010,427159.90.79Oyster Creek2388_1196961910,427255.11.17New JerseyPSEG Hope Creek Generating Station6118_119861,19610,427147.50.84Limerick6105_119861,13410,427127.60.55MACEPennsylvaniaLimerick6105_219901,13410,427127.60.54Calvert Cliffs Nuclear Power Plant6011_1197588510,427155.20.75MACSMarylandCalvert Cliffs Nuclear Power Plant6011_2197787410,427155.20.72Peach Bottom3166_219741,11210,427172.70.81Peach Bottom3166_319741,11210,427172.70.80PPL Susquehanna6103_119831,28310,427172.10.89PPL Susquehanna6103_219851,28810,427172.10.88MACWPennsylvaniaThree Mile Island8011_1197478610,427170.90.82Fermi1729_219881,12210,427155.90.80MECSMichiganPalisades1715_1197277810,427197.21.14Appendix 4-3.3RegionStatePlant NameORISCode_UnitIdOn-LineYearCapacity (MW)Heat Rate(Btu/kWh)FOM(2007$/kW-yr)VOM(2007mills/kWh)IowaDuane Arnold1060_1197558110,427208.41.11Monticello1922_1197164610,427187.81.02Prairie Island1925_1197455110,427162.30.82MinnesotaPrairie Island1925_2197454510,427162.30.83Fort Calhoun2289_1197347810,427219.41.19MRONebraskaCooper8036_1197476710,427223.61.29Millstone566_2197588210,427205.41.10ConnecticutMillstone566_319861,23610,427192.21.02MassachusettsPilgrim Nuclear Power Station1590_1197268510,427241.61.06NewHampshireSeabrook6115_119901,24410,427178.70.94NENGVermontVermont Yankee3751_1197262010,427203.81.06PNWWashingtonColumbia Generating Station371_219841,13110,427152.10.73Donald C Cook6000_119751,02910,942174.91.05MichiganDonald C Cook6000_219781,07710,848174.91.08Perry6020_119871,23111,000160.10.80RFCOOhioDavis Besse6149_1197788711,000158.10.90Beaver Valley6040_1197688710,962190.30.96RFCPPennsylvaniaBeaver Valley6040_2198788710,946190.30.90Joseph M Farley6001_1197785111,794138.50.71AlabamaJoseph M Farley6001_2198186011,650138.50.68Edwin I Hatch6051_1197587610,427146.90.77Edwin I Hatch6051_2197988310,427146.90.78Vogtle649_119871,17210,427145.60.66SOUGeorgiaVogtle649_219891,16910,427145.60.65SPPNKansasWolf Creek Generating Station210_119851,16610,427137.70.71Appendix 4-3.4RegionStatePlant NameORISCode_UnitIdOn-LineYearCapacity (MW)Heat Rate(Btu/kWh)FOM(2007$/kW-yr)VOM(2007mills/kWh)Browns Ferry46_119741,22510,55099.90.40Browns Ferry46_219751,28610,21599.90.42AlabamaBrowns Ferry46_319771,33710,21599.90.40Sequoyah6152_119811,15010,123115.40.48Sequoyah6152_219821,12710,202115.40.45Watts Bar Nuclear Plant7722_119961,12110,266139.10.64TVATennesseeWatts Bar Nuclear Plant7722_220141,18010,26692.40.49Nine Mile Point Nuclear Station2589_1196962110,427193.50.98Nine Mile Point Nuclear Station2589_219691,31110,427188.90.97James A Fitzpatrick6110_1197685210,427203.00.90UPNYNew YorkR. E. Ginna Nuclear Power Plant6122_1197049810,427205.80.92Brunswick6014_1197793810,318110.60.46Brunswick6014_2197593710,397110.60.46Harris6015_1198790010,982131.30.60McGuire6038_119811,10010,427119.60.48North CarolinaMcGuire6038_219841,10010,427119.60.50H B Robinson3251_2197171010,697119.80.59Oconee3265_1197384610,427139.60.73Oconee3265_2197484610,427139.60.65Oconee3265_3197484610,427139.60.72Catawba6036_119851,12910,427134.00.64Catawba6036_219861,12910,427134.00.64VACASouth CarolinaV C Summer6127_1198496610,427143.50.80Surry3806_1197279910,427120.70.58Surry3806_2197379910,427120.70.57North Anna6168_1197894010,42798.70.47VAPWVirginiaNorth Anna6168_2198092510,42798.70.50Appendix 4-3.5RegionStatePlant NameORISCode_UnitIdOn-LineYearCapacity (MW)Heat Rate(Btu/kWh)FOM(2007$/kW-yr)VOM(2007mills/kWh)Point Beach4046_1197059910,427202.30.97Point Beach4046_2197260110,427202.31.00WUMSWisconsinKewaunee8024_1197455610,427151.50.85