3-1 

3 Power System Operation Assumptions 

This section describes the assumptions pertaining to the North American electric power system as 

represented in EPA Base Case v.4.10. 

3.1 Model Regions 

EPA Base Case v.4.10 models the US power sector in the contiguous 48 states and the District of 

Columbia and the Canadian power sector in the 10 provinces (with Newfoundland and Labrador 

represented as two regions on the electricity network even though politically they constitute a 

single province4

) as an integrated network. Alaska, Hawaii, Puerto Rico, and US Virgin Islands 

are represented in Base Case v.4.10 as separate entities with their own self contained electricity 

grids. 

There are 32 IPM model regions covering the US 48 states and District of Columbia. The IPM 

model regions are approximately consistent with the configuration of the 8 NERC regions, being 

disaggregations of North American Reliability Council (NERC) control areas. An attempt has been 

made to have the US IPM model regions reflect the administrative structure of regional 

transmission organizations (RTOs) and independent system operators (ISOs). Further 

disaggregation into 32 model regions allows a more accurate characterization of the operation of 

the US power markets by providing the ability to represent transmission bottlenecks within the 8 

NERC regions and across RTOs and ISOs. 

Disaggregations that were made in the most recent previous IPM base case were retained in 

Base Case 2010. Notable disaggregations include 

• NERC region RFC (Reliability First Corporation) includes three portions of former NERC 

regions — the non-Kentucky part of ECAR, MAAC, and a portion of MAIN. The remaining 

portion of MAIN has been renamed COMD. ECAR has been disaggregated into RFCO, 

MECS, and RFCP and MAAC has been disaggregated into MACE, MACS, and MACW. 

 

• NERC subregion WECC-AZ-NM-SNV has been disaggregated into AZNM and SNV 

• NERC subregion WECC-California ISO has been disaggregated into CA-N and CA-S 

• NERC Region SERC has been disaggregated into 7 IPM regions (ENTG, SOU, VACA, 

VAPW, TVA, TVAK (formerly ECAK), and GWAY (formerly a portion of MANO). 

Several region boundaries were adjusted to reflect recent organizational changes. There were 

also several name changes: MANO to GWAY, ECAM to RFCO, ECAP to RFCP, and ECAK to 

TVAK. 

The 11 Canadian model regions are defined strictly along provincial political boundaries. 

Figure 3-1 contains a map showing all the EPA Base Case 2010 model regions. Table 3-1 

defines the abbreviated region names appearing on the map and gives an approximate crosswalk 

between the IPM model regions, the NERC regions, and regions used in the Energy Information 

Administration’s (EIA’s) National Energy Model System (NEMS) which is the basis for EIA’s 

Annual Energy Outlook (AEO) reports. 

3.2 Electric Load Modeling 

Net energy for load and net internal demand are inputs to IPM that together are used to represent 

the grid-demand for electricity. Net energy for load is the projected annual electric grid-demand, 

prior to accounting for intra-regional transmission and distribution losses. Net internal demand 

 

4

This results in a total of 11 Candian model regions being represented in EPA Base Case v.4.10 
3-2 

(peak demand) is the maximum hourly demand within a given year after removing interruptible 

demand. Table 3-2 shows the electric demand assumptions (expressed as net energy for load) 

used in EPA Base Case v.4.10. It is based on the net energy for load in AEO 20105

. 

Figure 3-1 EPA Base Case v.4.10 Model Regions 

For purposes of documentation, Table 3-2 presents the national net energy for load. However, 

EPA Base Case v.4.10 models regional breakdowns of net energy for load. The regional net 

energy for load is derived from the national net energy for load based on the regional demand 

distribution in NERC electric demand forecasts. Model regions that represent subregions of a 

NERC region are apportioned their net energy for load based on the regional load shapes, which 

are developed by aggregating load for control areas within each model region. 

 

5

The electricity demand in EPA Base Case v.4.10 for the U.S. lower 48 states and the District of 

Columbia is obtained by summing the "Total Net Energy for Load" for the NEMS Electric Market 

Module regions as reported in the "Electric Power Projections for Electricity Market Module 

Regions -- Electricity and Renewable Fuel Tables 72-84" at 

http://www.eia.doe.gov/oiaf/aeo/aeoref_tab.html. 
3-3 

Table 3-1 Mapping of NERC Regions and NEMS Regions with EPA Base Case v.4.10 Model 

Regions 

NERC 

Region 

NEMS 

Region 

Model 

Region Model Region Description 

TRE ERCOT ERCT Texas Regional Entity 

FRCC FL FRCC Florida Reliability Coordinating Council 

MAPP MRO Midwest Regional Planning Organization MRO 

MAIN WUMS Wisconsin-Upper Michigan 

NE NENG New England Power Pool 

DSNY Downstate New York 

LILC Long Island Company 

NYC New York City 

NPCC NY 

UPNY Upstate New York 

RFCO Reliability First Corporation - MISO 

ECAR MECS Michigan Electric Coordination System 

RFCP Reliability First Corporation - PJM 

MACE Legacy Mid-Atlantic Area Council - East 

MAAC MACS Legacy Mid-Atlantic Area Council - South 

MACW Legacy Mid-Atlantic Area Council - West 

RFC 

MAIN COMD Commonwealth Edison 

MAIN GWAY Gateway 

ECAR TVAK Tennessee Valley Authority - MISO-KY 

SOU Southern Company 

TVA Tennessee Valley Authority 

ENTG Entergy 

VACA Virginia-Carolinas 

SERC 

STV 

VAPW Dominion Virginia Power 

SPPN Southwest Power Pool - North SPP SPP 

SPPS Southwest Power Pool - South 

AZNM Western Electricity Coordinating Council - Arizona, New 

Mexico 

WECCAZ-NMSNV 

RA 

SNV Western Electricity Coordinating Council - Southern Nevada 

WECC- CA-N Western Electricity Coordinating Council - California North 

California 

ISO 

CNV 

CA-S Western Electricity Coordinating Council - California South 

PNW Western Electricity Coordinating Council - Pacific Northwest WECCNWPP NWP 

NWPE Western Electricity Coordinating Council - Northwest Power 

Pool East 

WECCRMPA RA RMPA Western Electricity Coordinating Council - Rocky Mountain 

Power Area 

CNAB Alberta 

CNBC British Columbia 

CNMB Manitoba 

CNNB New Brunswick 

CNNF Newfoundland 

CNNL Labrador 

CNNS Nova Scotia 

Canada 

CNON Ontario 
3-4 

NERC 

Region 

NEMS 

Region 

Model 

Region Model Region Description 

CNPE Prince Edward Island 

CNPQ Quebec 

CNSK Saskatchewan 

ALSK Alaska 

HAWI Hawaii 

VIUS U.S. Virgin Islands Other 

PRCW Puerto Rico 

 

 

Table 3-2 Electric Load Assumptions in EPA Base Case v.4.10 

Year Net Energy for Load 

(Billions of kWh) 

2012 4,043 

2015 4,086 

2020 4,302 

2030 4,703 

2040 5,113 

2050 5,568 

Note:

This data is an aggregation of the model-region-specific net energy loads 

used in the EPA Base Case v.4.10. 

3.2.1 Demand Elasticity 

EPA Base Case v.4.10 has the capability to model the impact of the price of power on electricity 

demand. However, this capability is typically only exercised for sensitivity analyses where 

different price elasticities of demand are specified for purposes of comparative analysis. The 

default base case assumption is that the electricity demand shown in Table 3-2 is not affected by 

price and must be met, i.e., the price elasticity of demand is zero6

. 

3.2.2 Net Internal Demand (Peak Demand) 

EPA Base Case v.4.10 has separate regional winter and summer peak demand values, as 

derived from each region’s seasonal load duration curve (found in Appendix 2-1). Peak projections 

were estimated based on AEO 2010 load factors and the estimated energy demand projections 

shown in Table 3-2. Table 3-3 (“National Non-Coincidental Net Internal Demand”) illustrates the 

national sum of each region’s winter and summer peak demand. Because each region’s seasonal 

peak demand need not occur at the same time, the national peak demand is defined as noncoincidental.

 

6

Occasionally, e.g., when performing modeling of climate policies, the demand assumptions 

shown in Table 3-2 will be replaced with projections of demand from economy-wide computable 

general equilibrium (CGE) models which themselves take into account demand elasticity. 

However, even in such cases the IPM demand elasticity capabilities will not be utilized and the 

resulting IPM runs will be considered “policy” rather than “base case” runs. 
3-5 

Table 3-3 National Non-Coincidental Net Internal Demand 

Peak Demand (GW) Year 

Winter Summer 

2012 646 758 

2015 655 771 

2020 693 816 

2030 768 908 

2040 843 1,001 

2050 929 1,105 

Note:

This data is an aggregation of the model-region-specific peak 

demand loads used in the EPA Base Case v.4.10. 

3.2.3 Regional Load Shapes 

EPA uses year 2007 as the meteorological year in its air-quality modeling. In order for EPA Base 

Case v.4.10 to be consistent, the year 2007 was selected as the “normal weather year”7

 for all 

IPM regions. The proximity of the 2007 cumulative annual heating degree days (HDDs) and 

cooling degree days (CDDs) to the long-term average cumulative annual HHDs and CDDs over 

the period 1971 to 2000 was estimated and found to be reasonable close. The 2007 

chronological hourly load data were assembled by aggregating individual utility load curves taken 

from Federal Energy Regulatory Commission Form 714 data. 

3.3 Transmission 

The United States and Canada can be broken down into several power markets that are 

interconnected by a transmission grid. As discussed earlier, EPA Base Case 4.10 characterizes 

the U.S. lower 48 states, the District of Columbia, and Canada into 43 different power market 

regions by means of 32 model regions in the U.S. and 11 in Canada. EPA Base Case 4.10 

includes explicit assumptions regarding the transmission grid connecting these modeled power 

markets. This section details the assumptions about the transfer capabilities, wheeling costs and 

inter-regional transmission used in EPA Base Case 4.10. 

3.3.1 Inter-regional Transmission Capability 

Table 3-48

 shows the firm and non-firm Total Transfer Capabilities (TTCs) between model regions. 

TTC is a metric that represents the capability of the power system to import or export power 

reliably from one region to another. The purpose of TTC analysis is to identify the sub-markets 

created by key commercially significant constraints. Firm TTCs, also called Capacity TTCs, 

specify the maximum power that can be transferred reliably, even after the contingency loss of a 

single transmission system element such as a transmission line or a transformer (N-1). Firm 

TTCs provide a high level of reliability and are therefore used for capacity transfers. Non-firm 

TTCs, also called Energy TTCs, represent the maximum power that can be transferred reliably 

when all facilities are under normal operation (N-0). They specify the sum of the maximum firm 

transfer capability between sub-regions plus incremental curtailable non-firm transfer capability. 

Non-firm TTCs are used for energy transfers since they provide a lower level of reliability than 

 

7

The term “normal weather year” refers to a representative year whose weather is closest to the 

long-term (e.g., 35 year) average weather. The selection of a “normal weather year” can be 

made, for example, by comparing the cumulative annual heating degree days (HDDs) and cooling 

degree days (CDDs) in a candidate year to the long-term average. For any individual day, heating 

degree days indicate how far the average temperature fell below 65 degrees F; cooling degree 

days indicate how far the temperature averaged above 65 degrees F. Cumulative annual heating 

and cooling degree days are the sum of all the HDDs and CDDs, respectively, in a given year. 

8

In the column headers in Table 3-4 the term “Energy (MW)” is equivalent to non-firm TTCs and 

the term “Capacity (MW)” is equivalent to firm TTCs. 
3-6 

Firm TTCs, and transactions using Non-firm TTCs can be curtailed under emergency or 

contingency conditions. 

Table 3-4 Annual Transmission Capabilities of U.S. Model Regions in EPA Base Case 

v.4.10 

From To Energy 

(MW) 

Capacity 

(MW) 

Wheeling Charge 

(mills/kWh) 

CA-S 3,627 2,428 2.9 

NWPE 300 300 -- 

RMPA 690 690 -- 

SNV 4,634 4,634 -- 

AZNM 

SPPS 400 400 2.9 

CA-S 3,700 3,700 -- 

CA-N NWPE 150 100 2.9 

PNW 3,675 3,675 2.9 

AZNM 3,627 2,428 2.9 

CA-N 3,000 2,400 -- 

NWPE 1,400 1,400 2.9 

PNW 3,100 3,100 2.9 

CA-S 

SNV 4,688 4,688 2.9 

GWAY 2,050 2,050 2.9 

MRO 825 825 2.9 

RFCO 1,620 1,110 2.9 

RFCP 4,500 788 -- 

COMD 

WUMS 825 825 2.9 

LILC 1,290 1,290 -- 

MACE 2,000 2,000 2.9 

NENG 1,120 1,120 2.9 

NYC 3,700 3,700 -- 

DSNY 

UPNY 3,400 3,400 -- 

GWAY 910 140 2.9 

MRO 150 150 2.9 

SOU 2,250 2,250 2.9 

SPPN 1,120 140 2.9 

SPPS 4,494 735 2.9 

ENTG 

TVA 1,681 1,681 2.9 

ENTG 1,001 1,001 2.9 ERCT SPPS 979 979 2.9 

FRCC SOU 2,000 2,000 2.9 

COMD 1,100 1,100 2.9 

ENTG 2,804 2,100 2.9 

MRO 405 405 -- 

RFCO 6,299 1,848 -- 

SPPN 285 285 2.9 

TVA 1,812 1,812 2.9 

GWAY 

TVAK 200 200 2.9 

DSNY 530 530 -- 

MACE 650 590 2.9 

LILC 

NENG 616 616 2.9 
3-7 

From To Energy 

(MW) 

Capacity 

(MW) 

Wheeling Charge 

(mills/kWh) 

NYC 420 420 -- 

DSNY 500 500 2.9 

LILC 650 521 2.9 

MACW 2,000 2,000 -- MACE 

NYC 1,200 600 2.9 

MACW 3,500 3,000 -- 

MACS RFCP 2,500 750 -- 

VAPW 2,600 2,600 -- 

MACE 6,200 5,800 -- 

MACS 5,000 1,350 -- 

RFCO 2,208 504 2.9 

RFCP 3,300 2,044 -- 

MACW 

UPNY 1,085 1,085 2.9 

CNON 1,968 1,968 2.9 

MECS RFCO 2,776 1,904 -- 

RFCP 3,900 683 2.9 

COMD 610 610 2.9 

CNON 100 100 2.9 

CNSK 165 165 2.9 

ENTG 2,000 2,000 2.9 

GWAY 320 320 -- 

NWPE 200 200 2.9 

RMPA 310 310 2.9 

SPPN 1,494 1,494 2.9 

MRO 

WUMS 800 800 -- 

CNNB 1,000 1,000 2.9 

CNPQ 803 803 2.9 

DSNY 980 980 2.9 NENG 

LILC 616 473 2.9 

AZNM 265 265 -- 

CA-N 160 120 2.9 

CA-S 1,920 1,920 2.9 

MRO 150 150 2.9 

PNW 2,002 2,002 -- 

RMPA 749 749 -- 

NWPE 

SNV 300 250 -- 

DSNY 1,999 1,999 -- NYC LILC 175 175 -- 

CA-N 4,000 4,000 2.9 

CA-S 3,100 3,100 2.9 

CNBC 2,000 1,000 2.9 PNW 

NWPE 1,505 1,505 -- 

COMD 2,760 1,360 2.9 

GWAY 7,078 3,504 -- 

MACW 3,100 2,274 2.9 

RFCO 

MECS 4,603 825 -- 
3-8 

From To Energy 

(MW) 

Capacity 

(MW) 

Wheeling Charge 

(mills/kWh) 

RFCP 12,908 7,951 2.9 

TVAK 815 270 2.9 

COMD 3,100 3,100 -- 

MACS 2,500 350 -- 

MACW 3,900 1,075 -- 

MECS 3,700 1,762 2.9 

RFCO 15,041 8,525 2.9 

TVA 1,000 1,000 2.9 

TVAK 1,000 537 2.9 

VACA 3,002 2,042 2.9 

RFCP 

VAPW 3,080 953 -- 

AZNM 690 690 -- 

RMPA MRO 310 310 2.9 

NWPE 735 735 -- 

AZNM 4,785 4,785 -- 

SNV CA-S 4,688 4,688 2.9 

NWPE 300 300 -- 

ENTG 2,950 2,950 2.9 

FRCC 3,600 3,600 2.9 

TVA 3,742 3,742 2.9 SOU 

VACA 1,358 1,358 2.9 

ENTG 3,745 1,260 2.9 

GWAY 1,200 1,200 2.9 

MRO 600 600 2.9 SPPN 

SPPS 700 700 -- 

AZNM 400 400 2.9 

ENTG 9,030 2,310 2.9 

ERCT 650 650 2.9 SPPS 

SPPN 1,200 1,200 -- 

ENTG 2,919 2,919 2.9 

GWAY 1,550 1,550 2.9 

RFCP 1,500 263 2.9 

SOU 2,258 2,258 2.9 

TVAK 2,000 1,073 -- 

TVA 

VACA 664 664 2.9 

GWAY 200 200 2.9 

RFCO 3,365 1,225 2.9 

RFCP 1,000 175 2.9 TVAK 

TVA 1,500 632 -- 

CNON 2,000 1,325 2.9 

CNPQ 1,000 1,000 2.9 

DSNY 4,550 4,550 -- 

MACW 735 735 2.9 

 UPNY 

NENG 150 150 2.9 

RFCP 4,117 438 2.9 

SOU 3,242 3,242 2.9 

VACA 

TVA 3,586 3,586 2.9 
3-9 

From To Energy 

(MW) 

Capacity 

(MW) 

Wheeling Charge 

(mills/kWh) 

VAPW 1,942 1,942 2.9 

MACS 2,100 2,100 -- 

VAPW RFCP 5,460 1,952 -- 

VACA 1,849 1,849 2.9 

COMD 1,125 1,125 2.9 WUMS MRO 270 270 -- 

The amount of energy and capacity transferred on a given transmission link is modeled on a 

seasonal (summer and winter) basis for all run years in the EPA Base Case 4.10. All of the 

modeled transmission links have the same Total Transfer Capabilities for both the winter and 

summer seasons, which means that the maximum firm and non-firm TTCs for each link is the 

same for both winter and summer. Wherever available, the maximum values for firm and non-firm 

TTCs were obtained from public sources. Where public sources were not available, the maximum 

values for firm and non-firm TTCs are based on ICF’s expert view. 

It should be noted that each transmission link between model regions shown in Table 3-4 

represents a one-directional flow of power on that link. This implies that the maximum amount of 

flow of power possible from region A to region B may be more or less than the maximum amount 

of flow of power possible from region B to region A. 

3.3.2 Joint Transmission Capacity and Energy Limits 

Table 3-5 shows the annual joint limits to the transmission capabilities between model regions, 

which are identical for the firm (capacity) and non-firm (energy) transfers. The joint limits were 

developed from the 2004 NERC Summer Assessment and 2004 NERC Winter Assessment. A 

joint limit represents the maximum simultaneous firm or non-firm power transfer capability of a 

group of interfaces. It restricts the amount of firm or non-firm transfers between one model region 

(or group of model regions) and a different group of model regions). For example, the New 

England model region is connected to multiple model regions contained in the state of New York, 

with each link between New England and a New York model region described by its own TTCs. 

However, there is a maximum limit on the total amount of transfers that the New England region 

may transfer to the whole of New York, which is represented by the annual joint capacity limit 

between the New England model region and the relevant New York model regions. 

Table 3-5 Annual Joint Capacity and Energy Limits to Transmission Capabilities Between 

Model Regions in EPA Base Case v.4.10 

Region Connections Transmission Path Joint Constraint Limit 

RFCO to MACW 

ECAR to MAAC RFCP to MACS 

RFCP to MACW 

1,385 

RFCO to COMD 

RFCP to COMD 

RFCO to GWAY ECAR to MAIN 

TVAK to GWAY 

2,593 

TVAK to TVA ECAR to TVA RFCP to TVA 3,561 

RFCP to VACA ECAR to VACAR RFCP to VAPW 2,022 

ENTG to SPPN ENTG to SPP ENTG to SPPS 338 
3-10 

Region Connections Transmission Path Joint Constraint Limit 

LILC to DSNY LILC to NYC & DSNY LILC to NYC 530 

MACS to RFCP 

MAAC to ECAR MACW to RFCO 

MACW to RFCP 

4,715 

MACE to DSNY 

MACE to LILC 

MACE to NYC MAAC to NPCC 

MACW to UPNY 

1,708 

COMD to RFCO 

COMD to RFCP 

GWAY to TVAK MAIN to ECAR 

GWAY to RFCO 

3,649 

COMD to MRO 

MAIN to MAPP GWAY to MRO 

WUMS to MRO 

962 

MRO to COMD 

MAPP to MAIN MRO to GWAY 

MRO to WUMS 

1,238 

MRO to NWPE MAPP to WECC MRO to RMPA 710 

NENG to DSNY 

NENG to NY NENG to UPNY 

NENG to LILC 

1,550 

DSNY to MACE 

LILC to MACE 

NYC to MACE NPCC to MAAC 

UPNY to MACW 

2,353 

DSNY to NENG 

NY to NENG LILC to NENG 

UPNY to NENG 

1,750 

DSNY to LILC NYC & DSNY to LILC NYC to LILC 1,465 

SPPN to ENTG SPP to ENTG SPPS to ENTG 1,362 

TVA to TVAK TVA to ECAR TVA to RFCP 1,226 

VACA to RFCP VACAR to ECAR VAPW to RFCP 4,278 

NWPE to MRO WECC to MAPP RMPA to MRO 660 

Note: 

Source: 2004 NERC Summer Assessment, 2004 NERC Winter Assessment 

3.3.3 Transmission Link Wheeling Charge 

Transmission wheeling charge is the cost of transferring electric power from one region to another 

using the transmission link. The EPA Base Case 4.10 assumes a wheeling charge of 2.9 mills per 

kWh for electricity transmission between IPM model regions that fall within different market 
3-11 

regions, such as transmission between Northern California and the Pacific Northwest. However, 

the wheeling charge is not applied to transmission between model regions that are within the 

same market region, such as transmission between Northern California (model region CA-N) and 

Southern California (model region CA-S). The wheeling charge applied between IPM model 

regions can be found in Table 3-4. 

3.3.4 Transmission Losses 

The EPA Base Case 4.10 assumes a two percent inter-regional transmission loss of energy 

transferred, in line with EIA’s Annual Energy Outlook (AEO) 2010. 

3.4 International Imports 

The U.S. electric power system is connected with the transmission grids in Canada and Mexico 

and the three countries actively trade in electricity. The Canadian power market is endogenously 

modeled in EPA Base Case v.4.10 but Mexico is not. International electric trading between the 

U.S. and Mexico is represented by an assumption of net imports based on information from AEO 

2010. Table 3-6 summarizes the assumptions on net imports into the US from Mexico. 

Table 3-6 International Electricity Imports in EPA Base Case v.4.10 

 2012 2015 2020 2030 2040 2050 

Net Imports from Mexico 

(billions kWh) 1.57 1.57 1.11 0.89 0.89 0.89 

Notes:

Imports & exports transactions from Canada are endogenously modeled in IPM. 

Source: AEO 2010 

3.5 Capacity, Generation, and Dispatch 

While the capacity of existing units is an exogenous input into IPM, the dispatch of those units is 

an endogenous decision that the model makes. The capacity of existing generating units included 

in EPA Base Case v.4.10 can be found in the National Electrical Energy Data System (NEEDS 

v.4.10), a database which provides IPM with information on all currently operating and plannedcommitted electric generating units. NEEDS v.4.10 is discussed in full in Chapter 4. 

A unit’s generation over a period of time is defined by its dispatch pattern over that duration of 

time. IPM determines the optimal economic dispatch profile given the operating and physical 

constraints imposed on the unit. In EPA Base Case v.4.10 unit specific operational and physical 

constraints are generally represented through availability and turndown constraints. However, for 

some unit types, capacity factors are used to capture the resource or other physical constraints on 

generation. The two cases are discussed in more detail in the following sections. 

3.5.1 Availability 

Power plant “availability” is the percentage of time that a generating unit is available to provide 

electricity to the grid. Availability takes into account both scheduled maintenance and forced 

outages; it is formally defined as the ratio of a unit’s available hours adjusted for derating of 

capacity (due to partial outages) to the total number of hours in a year when the unit was in an 

active state. For most types of units in IPM, availability parameters are used to specify an upper 

bound on generation to meet demand. Table 3-7 summarizes the availability assumptions used in 

EPA Base Case v.4.10. They are based on data from North American Electric Reliability 

Council’s Generating Availability Data System (NERC GADS) 2001 to 2005 and AEO 2010. 

Appendix 3-9 shows the availability assumptions for all generating units in EPA Base Case v.4.10. 
3-12 

Table 3-7 Availability Assumptions in the EPA Base Case v.4.10 

Unit Type Annual Availability (%) 

Biomass 83 

Coal Steam 32 - 95 

Combined Cycle 85 

Combustion Turbine 89 - 91 

Gas/Oil Steam 78 - 92 

Geothermal 87 

IGCC 85 

Pumped Storage 90 

Solar 90 

Wind 95 

Notes:

Values shown are a range of all of the values modeled within the EPA Base Case v.4.10. 

Availabilities of coal steam units are based on historical capacity factors. 

In the EPA Base Case v.4.10, separate seasonal (summer and winter) availabilities are defined. 

For the fossil and nuclear unit types shown in Table 3-7, summer and winter availabilities differ 

only in that no planned maintenance is assumed to be conducted during the on-peak summer 

(June, July and August) months. Characterizing the availability of hydro, solar and wind 

technologies is more complicated due to the seasonal and locational variations of the resources. 

The procedures used to represent seasonal variations in hydro are presented in section 3.5.2 and 

of wind and solar in section 4.4.5. 

3.5.2 Capacity Factor 

Generation from certain types of units is constrained by resource limitations. These technologies 

include hydro, wind and solar. For such technologies, IPM uses capacity factors or generation 

profiles, not availabilities, to define the upper bound on the generation obtainable from the unit. 

The capacity factor is the percentage of the maximum possible power generated by the unit. For 

example, a photovoltaic solar unit would have a capacity factor of 27% if the usable sunlight were 

only available that percent of the time. For such units, explicit capacity factors or generation 

profiles mimic the resource availability. The seasonal capacity factor assumptions for hydro 

facilities contained in Table 3-8 were derived from EIA Form 906 from 2002 through 2006 data. A 

discussion of capacity factors and generation profiles for wind and solar technologies is contained 

in section 4.4.5 and Appendices 4-1 and 4-2. 

Table 3-8 Seasonal Hydro Capacity Factors (%) in the EPA Base Case v.4.10 

Model 

Region 

Winter Capacity 

Factor 

Summer Capacity 

Factor 

Annual Capacity 

Factor 

AZNM 27.4% 32.2% 29.4% 

CA-N 36.7% 50.1% 42.3% 

CA-S 38.7% 50.4% 43.6% 

COMD 40.6% 45.5% 42.6% 

DSNY 57.8% 50.2% 54.6% 

ENTG 35.4% 32.5% 34.2% 

ERCT 13.5% 19.6% 16.1% 

FRCC 48.4% 47.4% 48.0% 

GWAY 19.2% 22.5% 20.6% 

MACE 30.9% 29.2% 30.2% 

MACS 14.8% 18.7% 16.4% 

MACW 47.5% 33.7% 42.3% 

MECS 54.1% 56.9% 55.3% 
3-13 

Model 

Region 

Winter Capacity 

Factor 

Summer Capacity 

Factor 

Annual Capacity 

Factor 

MRO 31.8% 43.7% 36.8% 

NENG 44.9% 41.1% 43.3% 

NWPE 28.7% 47.6% 36.6% 

PNW 40.6% 44.0% 42.0% 

RFCO 66.0% 89.2% 75.6% 

RFCP 32.7% 30.9% 31.9% 

RMPA 18.0% 31.5% 23.7% 

SNV 18.0% 23.3% 20.2% 

SOU 25.3% 22.1% 24.0% 

SPPN 16.5% 17.8% 17.0% 

SPPS 21.2% 27.2% 23.7% 

TVA 43.2% 37.1% 40.7% 

TVAK 32.4% 38.6% 35.0% 

UPNY 66.8% 63.1% 65.2% 

VACA 23.7% 22.8% 23.3% 

VAPW 22.8% 19.0% 21.2% 

WUMS 52.6% 57.3% 54.6% 

Note: 

Annual capacity factor is provided for information purposes only. It is not directly used in 

modeling. 

Capacity factors are also used to define the upper bound on generation obtainable from nuclear 

units. This rests on the assumption that nuclear units will dispatch to their availability, and, 

consequently, capacity factors and availabilities are equivalent. The capacity factors (and, 

consequently, the availabilities) of existing nuclear units in EPA Base Case v.4.10 vary from 

region to region and over time. Further discussion of the nuclear capacity factor assumptions in 

EPA Base Case v.4.10 is contained in Section 4.5. 

3.5.3 Turndown 

Turndown assumptions in EPA Base Case v.4.10 are used to prevent coal and oil/gas steam units 

from operating strictly as peaking units, which would be inconsistent with their operating 

capabilities. Specifically, the turndown constraints in EPA Base Case v.4.10 require coal steam 

units to dispatch no less than 50% of the unit capacity in the five base- and mid-load segments of 

the load duration curve in order to dispatch 100% of the unit in the peak load segment of the LDC. 

 Oil/gas steam units are required to dispatch no less than 25% of the unit capacity in the five baseand mid-load segments of the LDC in order to dispatch 100% of the unit capacity in the peak load 

segment of the LDC. These turndown constraints were developed by ICF International through 

detailed assessments of the historical experience and operating characteristics of the existing fleet 

of coal steam and oil/gas steam units’ capacities. 

3.6 Reserve Margins 

A reserve margin is a measure of the system’s generating capability above the amount required to 

meet the net internal demand (peak load) requirement. It is defined as the difference between 

total dependable capacity and annual system peak load divided by annual system peak load. It is 

expressed in percent. In practice, each NERC region has a reserve margin requirement, or 

comparable reliability standard, which is designed to encourage electric suppliers in the region to 

build beyond their peak requirements to ensure the reliability of the electric generation system 

within the region. 

In IPM reserve margins are used to depict the reliability standards that are in effect in each NERC 

region. Individual reserve margins for each NERC region are derived either directly or indirectly 
3-14 

from NERC’s electric reliability reports. They are based on reliability standards such as loss of 

load expectation (LOLE), which is defined as the expected number of days in a specified period in 

which the daily peak load will exceed the available capacity. EPA Base Case v.4.10 reserve 

margin assumptions are shown in Table 3-9. 

Table 3-9 Planning Reserve Margins in EPA Base Case v.4.10 

Model Region Reserve Margin 

AZNM 15.7% 

CA-N 16.7% 

CA-S 16.7% 

CNAB 12.8% 

CNBC 12.8% 

CNMB 15.0% 

CNNB 20.0% 

CNNF 20.0% 

CNNL 20.0% 

CNNS 20.0% 

CNON 18.3% 

CNPE 20.0% 

CNPQ 10.0% 

CNSK 15.0% 

COMD 15.0% 

DSNY 16.5% 

ENTG 15.0% 

ERCT 12.5% 

FRCC 15.0% 

GWAY 15.0% 

LILC 16.5% 

MACE 15.0% 

MACS 15.0% 

MACW 15.0% 

MECS 15.0% 

MRO 15.0% 

NENG 16.0% 

NWPE 10.8% 

NYC 16.5% 

PNW 10.8% 

RFCO 15.0% 

RFCP 15.0% 

RMPA 14.3% 

SNV 15.7% 

SOU 15.0% 

SPPN 13.6% 

SPPS 13.6% 

TVA 12.0% 

TVAK 15.0% 

UPNY 16.5% 

VACA 15.0% 

VAPW 15.0% 

WUMS 16.0% 
3-15 

3.7 Power Plant Lifetimes 

EPA Base Case v.4.10 does not include any pre-specified assumptions about power plant 

lifetimes, except for nuclear units. All conventional fossil units (i.e., coal, oil/gas steam, 

combustion turbines, and combined cycle) and nuclear units can be retired during a model run for 

economic reasons. Other types of units are not provided an economic retirement option. 

Nuclear Retirement at Age 60: Existing nuclear units are forced to retire in EPA Base Case 

v.4.10 at the completion of age 60. Today’s nuclear fleet totals more than 100 GW. A 60-year 

lifetime reduces the current fleet to under 5 GW in 2050. This is illustrated in Figure 3-2. For a 

complete listing of the existing nuclear units represented in EPA Base Case v.4.10, including their 

online year and other characteristics, see Appendix 4-3. 

Figure 3-2 Scheduled Retirements of Existing Nuclear Capacity Under 60-Year Life 

Assumption 

Impact of 60-Year Lifetime on Existing Nuclear Fleet

0

1

2

3

4

5

6

7

8

9

10

2010 2015 2020 2025 2030 2035 2040 2045 2050

Year

Capacity (GW) Retired in Year

0

20

40

60

80

100

120

Total Capacity (GW) Remaining

Retired in Year Remaining Capacity

The 60-year lifetime assumption is based on several factors. At the time that this base case was 

prepared there were many instances of the U.S. Nuclear Regulatory Commission (NRC) granting 

license extensions of 20 years beyond the initial 40 year operating licenses authorized by the 

NRC for commercial nuclear power plants under the Atomic Energy Act of 1954. At the time of 

the release of EPA Base Case v.4.10, the NRC had granted license renewals to 50 operating 

reactors allowing them to operate for 60 years with fifteen additional applications under review and 

the owners of 21 other units announcing their intention to file for 20-year license extensions. All of 

these applications would allow the units to operate to age 60. 
3-16 

At the same time, there were no units in the U.S. nuclear fleet licensed to operate past age 609

. 

In keeping with the practice of the EPA base case representing legal provisions that are on the 

books or immediately pending, a conservative approach was adopted of reflecting the current 

maximum licensing period of 60 years for the nuclear units in EPA Base Case v.4.10. 

Another factor in the decision to implement the 60-year nuclear life assumption is the degree of 

uncertainty surrounding nuclear life extensions past age 60. As noted in EIA’s review of the 60 

year nuclear life question, uncertainties include: 

• The absence, to date, of publicly available plans and cost estimates for potential major capital 

expenditures involved with extensions to age 80 such as the replacement of reactor vessels, 

containment structures, or buried piping and cables. 

• Possible future additional regulatory requirements which could result in expensive upgrades at 

nuclear power plants and figure into life extension decisions. Among those mentioned in 

EIA’s review was a rule that was recently the subject of the Supreme Court case Entergy Corp 

v. Riverkeeper10, which focused on whether or not the EPA could conduct cost-benefit 

analyses to determine whether a plant needed to replace open-cycle cooling water systems 

with closed-cycle systems. 

The assumption of nuclear retirements at age 60 in EPA Base Case v.4.10 contrasts to a certain 

degree with the assumption made in AEO 2010. Due to AEO 2010’s shorter time horizon 

compared to the EPA base case (i.e., 2035 compared to 2050), EIA did not have to explicitly 

adopt an 80 year nuclear life assumption (as would have been necessary in EPA Base Case 

v.4.10), only that “the operating lives of existing nuclear power plants would be extended at least 

through 2035.11” The basis for the decision appears to be that “The nuclear industry has 

expressed strong interest in continuing the operation of existing nuclear facilities, and no particular 

technical issues have been identified that would impede their continued operation.12” 

Although the adopted assumptions differ in EPA Base Case v.4.10 and AEO 2010, there is 

agreement on the importance of performing side cases using the alternative assumptions. In the 

case of EPA Base Case v.4.10 this will mean performing sensitivity analysis runs with an 80 

nuclear lifetime assumption. 

 

9 The Energy Information Administration has an excellent review and summary of the issues 

involved in the 60 year nuclear life question. Although EPA’s base case does not adopt the same 

assumption as AEO 2010, the text in this section relied heavily on the EIA review. With respect to 

the status of applications for renewals beyond age 60, the EIA review notes the following: “In 

December 2009, the Oyster Creek Generating Station in Lacey Township, New Jersey, became 

the first nuclear power plant in the United States to begin its 40th year of operation. With Oyster 

Creek and other nuclear plants of similar vintage just beginning to enter their first period of license 

renewal, it probably will be at least 5 to 10 years before there is any clear indication as to whether 

plant operators will be likely to seek further extensions of their plants’ operating lives.” The EIA 

review also observes “. . . the NRC and the nuclear power industry are preparing applications for 

license renewals that would allow continued operation beyond 60 years, the first of which is 

scheduled to be submitted by 2013. In February 2008, DOE and the NRC hosted a joint workshop 

titled “Life Beyond 60,” with a broad group of nuclear industry stakeholders meeting to discuss this 

issue. The workshop’s summary report outlined many of the technical research needs that 

participants agreed were important to extending the life of the existing fleet of U.S. nuclear plants.” 

Energy Information Administration (EIA), U.S. Department of Energy, “U.S. nuclear power plants: 

Continued life or replacement after 60?” Annual Energy Outlook 2010 with Projections to 2035

(DOE/EIA-0383(2010)), May 11, 2010, www.eia.doe.gov/oiaf/aeo/nuclear_power.html. 

10Supreme Court of the United States, “Entergy Corp. v. Riverkeeper, Inc., et al.,” No. 07-588 

(October Term, 2008 www.supremecourtus.gov/opinions/ 08pdf/07-588.pdf. 

11EIA, op.cit. 

12EIA, ibid. 
3-17 

3.8 Heat Rates 

Heat rates, expressed in BTUs per KWh. are a metric of the efficiency of a generating unit. As in 

previous versions of NEEDS, it is assumed in NEEDS v.4.10 that heat rates of existing units will 

remain constant over time. This assumption reflects two offsetting factors: (1) plant efficiencies 

tend to degrade over time and (2) increased maintenance and component replacement work to 

maintain or improve plant efficiency. 

The heat rates in EPA Base Case v.4.10 are based on values from AEO 2008. These values were 

screened and adjusted using a procedure developed by EPA to ensure that the heat rates used in 

EPA Base Case v.4.10 are within the engineering capabilities of the generating unit types. Based 

on engineering analysis, the upper and lower heat rate limits shown in Table 3-10 were applied to 

coal steam, oil/gas steam, combined cycle, combustion turbine, and internal combustion engines. 

 If the reported heat rate for such a unit was below the applicable lower limit or above the upper 

limit, the limit was substituted for the reported value. 

Table 3-10 Lower and Upper Limits Applied to Heat Rate Data in NEEDS v.4.10 

Heat Rate (Btu/kWh) 

Plant Type Lower 

Limit 

Upper 

Limit 

Coal Steam 8,300 14,500 

Oil/Gas Steam 8,300 14,500 

Combined Cycle - Natural Gas 5,500 15,000 

Combined Cycle - Oil 6,000 15,000 

Combustion Turbine - Natural Gas - 80 MW and above 8,700 18,700 

Combustion Turbine - Natural Gas < 80 MW 8,700 36,800 

Combustion Turbine - Oil and Oil/Gas - 80 MW and above 6,000 25,000 

Combustion Turbine - Oil and Oil/Gas < 80 MW 6,000 36,800 

IC Engine - Natural Gas 8,700 18,000 

IC Engine - Oil and Oil/Gas - 5 MW and above 8,700 20,500 

IC Engine - Oil and Oil/Gas < 5 MW 8,700 42,000 

3.9 Existing Environmental Regulations 

This section describes the existing federal, regional, and state SO2, NOx, mercury, and CO2

emissions regulations that are represented in the EPA Base Case v.4.10. The first three 

subsections discuss national and regional regulations. The next two subsections describe state 

level environmental regulations and a variety of legal settlements. The last subsection presents 

emission assumptions for potential units. 

Note on Clean Air Interstate Rule (CAIR): In December 2008 the U.S. Court of Appeals for the 

District of Columbia Circuit remanded CAIR to EPA to correct legal flaws in the proposed 

regulations as cited in the Court’s July 2008 ruling. Until EPA’s work was completed, CAIR, which 

includes a cap-and-trade system for SO2 and NOx emissions, was temporarily reinstated. 

However, although CAIR’s provisions were still in effect when EPA Base Case v.4.10 was 

released, it is not included in the base case to allow EPA Base Case v.4.10 to be used to analyze 

the regulations proposed to replace CAIR. 

3.9.1 SO2 Regulations 

Unit-level Regulatory SO2 Emission Rates and Coal Assignments: Before discussing the 

national and regional regulations affecting SO2, it is important to note that unit-level SO2

regulations arising out of State Implementation Plan (SIP) requirements, which are not only state 

specific but also county specific, are captured at model set-up in the coal choices given to coal 

fired existing units in EPA Base Case v.4.10. The SIP requirements define “regulatory SO2
3-18 

emission rates.” Since SO2 emissions are dependent on the sulfur content of the fuel used, the 

regulatory SO2 emission rates are used in IPM to define fuel capabilities. 

For instance, a unit with a regulatory SO2 emission rate of 3.0 lbs/MMBtu would be provided only 

with those combinations of fuel choices and SO2 emission control options that would allow the unit 

to achieve an out-of-stack rate of 3.0 lbs/MMBtu or less. If the unit finds it economical, it may 

elect to burn a fuel that would achieve a lower SO2 rate than its specified regulatory emission limit. 

 In EPA Base Case v.4.10 there are 6 different sulfur grades of bituminous coal, 3 different grades 

of sub-bituminous coal, 3 different grades of lignite, and 1 sulfur grade of residual fuel oil. There 

are 2 different SO2 scrubber options for coal units. Further discussion of fuel types and sulfur 

content is contained in Chapter 9. Further discussion of SO2 control technologies is contained in 

Chapter 5. 

National and Regional SO2 Regulations: The national program affecting SO2 emissions in EPA 

Base Case v.4.10 is the SO2 allowance trading program established under Title IV of the Clean Air 

Act Amendments (CAAA) of 1990, which set a goal of reducing annual SO2 emissions by 10 

million tons below 1980 levels. The program, which became fully operational in year 2000, 

affects all SO2 emitting electric generating units greater than 25 MWs. The program provides 

trading and banking of allowances over time across all affected electric generation sources. 

The annual SO2 caps over the modeling time horizon in EPA Base Case v.4.10 reflect the 

provisions in Title IV. Since EPA Base Case v.4.10 uses year 2012 as the first analysis year, a 

projection of allowance banking behavior through the end of 2011 and specification of the 

available 2012 allowances are needed to initialize the modeling. EPA developed the projection of 

the banked allowances (11 million) going into 2012. Calculating the available 2012 allowances 

involved deducting allowance surrenders due to NSR settlements and state regulations from the 

2012 SO2 cap of 8.95 million tons. The surrenders totaled 270.6 thousand tons in allowances, 

leaving 8.679 million of 2012 allowances remaining. Table 7-4 shows the initial bank and 2012 

allowance specification along with the SO2 caps for the entire modeling time horizon. Specifics of 

the allowance surrender requirements under state regulations and NSR settlements can be found 

in Appendices 3-2 and 3-3. 

EPA Base Case v.4.10 also includes a representation of the Western Regional Air Partnership 

(WRAP) Program, a regional initiative involving Arizona, New Mexico, Oregon, Utah, Wyoming 

directed toward addressing visibility issues in the Grand Canyon and affecting SO2 emissions 

starting in 2018. The WRAP specifications for SO2 are presented in Table 7-4. 

3.9.2 NOx Regulations 

Much like SO2 regulations, existing NOx regulations are represented in EPA Base Case v.4.10 

through a combination of system level NOx programs and generation unit-level NOx limits. 

The system level NOx regulation represented in EPA Base Case v.4.10 is the NOx SIP Call trading 

program. This trading program affects all fossil units in 20 northeastern states13 and the District of 

Columbia. The program is only in effect during the ozone season (May - September). The 

program includes state-specific NOx budgets. However, since the program allows for trading 

among units in different states, the total annual NOX SIP Call budget of 527,580 tons is used in 

EPA Base Case v.4.10, rather than the state-specific budgets. The specifications for the SIP Call 

are presented in Table 7-4. 

 

13The states included in the SIP Call program are Alabama, Connecticut, Delaware, Illinois, 

Indiana, Kentucky, Maryland, Massachusetts, Michigan, Missouri, New Jersey, New York, North 

Carolina, Ohio, Pennsylvania, Rhode Island, South Carolina, Tennessee, Virginia, and West 

Virginia. 
3-19 

The representation of unit-level NOx limits includes Title IV unit specific rate limits and Clean Air 

Act Reasonable Available Control Technology (RACT) requirements for controlling NOx emissions 

from electric generating units in ozone non-attainment areas or in the Ozone Transport Region14

(OTR). Both of these limits are captured in the specific NOx emission rates assigned to each unit 

represented in the base case. Unlike SO2 emission rates, NOx emission rates are assumed not to 

vary with fuel, but are dependent on the combustion properties of the generating unit. Under the 

EPA Base Case v.4.10 the NOx emission rate of a unit can only change if the unit is retrofitted with 

NOx pollution control equipment. 

NOx Rates in NEEDS, v.4.10 Database: The NOx rates in the current base case were derived, 

wherever possible, directly from actual monitored NOx emission rate data reported to EPA under 

the Acid Rain and NOx Budget Program in 2007. The emission rates themselves reflect the 

impact of the applicable NOx regulations. For coal-fired units, NOX rates were used in combination 

with detailed engineering assessments of NOX combustion control performance to prepare a set of 

four possible starting NOx rates to assign to a unit depending on the specific policy affecting that 

unit in a model run. 

The reason for having four NOx rates in NEEDS is to allow all possible modeling scenarios 

involving NOx controls to be set up. The four NOx rates are designated as Mode 1–4, and are 

designed to include all the NOx rates possible for a unit with its current configuration of NOx

combustion and post-combustion controls. The four NOx rates are: 

• Mode 1: Applies to units not covered by a NOX control policy. Specifically, this is the NOX

rate with post-combustion controls shut off. For units without post-combustion controls, it’s 

their uncontrolled NOX rate. 

• Mode 2: A unit, which has post-combustion controls, runs them, but a unit without postcombustion controls operates as usual. 

• Mode 3: Applies to the off-season NOX rate for units affected by a seasonal NOX policy. For 

units with post-combustion controls, this is the NOX rate with post-combustion controls shut 

off. For units without post-combustion controls, it’s the NOX rate with state-of-the-art 

combustion controls operating. (Exception: In the SIP Call region current combustion controls 

are assumed to be retained.) 

• Mode 4: NOX rate applicable under a NOX policy. For SCR units, it’s the NOX rate with the 

SCR operating. For SNCR units, it’s the NOX rate with SNCR operating plus state-of-the-art 

combustion controls operating if required to attain rate limits. For units without postcombustion controls, it’s the NOX rate with state-of-the-art combustion controls operating. 

(Exception: In the SIP Call region current combustion controls are assumed to be retained.) 

The program that sets up a new model run uses a series of algorithms (decision rules) to 

determine which of the four NOX rates is selected: 

• A unit covered under an annual NOX emission limit is assigned the Mode 4 NOX rate (winter 

and summer seasons). 

• A unit covered by a summer season NOX emission limit, but not an annual NOX limit, is 

assigned the Mode 4 NOX rate in the summer season but the Mode 3 NOX rate in the winter 

season. 

• A unit covered by a mercury emission limit and not by a NOX emission limit is assigned the 

Mode 2 NOX rate in both winter and summer seasons. (Note: In the case of mercury limits, 

Mode 2 applies since it implies operation of an SCR or SNCR. This equipment, in 

combination with SO2 and particulate controls, offers as a co-benefit the reduction and capture 

 

14 The OTR consists of the following states: Maine, New Hampshire, Vermont, Massachusetts, 

Rhode Island, Connecticut, New York, New Jersey, Pennsylvania, Delaware, Maryland, District of 

Columbia, and northern Virginia. 
3-20 

of mercury. See Chapter 5 in the v.4.10 documentation for a discussion of the calculation 

mercury emission modification factors (EMF).) 

• A unit not covered by either an annual or a summer NOX limit nor mercury control 

requirements is assigned the Mode 1 NOX rate in both winter and summer seasons. 

The Mode 1-4 NOx rates for each generating unit are included in the NEEDS, v.4.10 database, 

described in Chapter 4. Appendix 3-1 and accompanying Tables 3-1.1, 3-1.2, and 3-1.3 give 

further information on the procedures employed to derive the four NOX rate modes and give 

specific examples of generating units that fit each of the Mode 1-4 specifications. 

Additional NOX rate assumptions include default NOX rates of 0.25 lbs/MMBtu for existing biomass 

units and 0.09 lbs/MMBtu for existing landfill gas units. 

3.9.3 CO2 Regulations and Renewable Portfolio Standards 

The Regional Greenhouse Gas Initiative (RGGI) is a year-round CO2 cap and trade program 

affecting fossil fired electric power plants 25 MW or larger in Connecticut, Delaware, Maine, New 

Hampshire, New Jersey, New York, Vermont, Rhode Island, Massachusetts, and Maryland. Table 

7-4 shows the specifications for RGGI that are implemented in EPA Base Case v.4.10. 

Renewable Portfolio Standards (RPS) generally refer to various state-level policies that require 

the addition of renewable generation to meet a specified share of state-wide generation In EPA 

Base Case v.4.10 the state RPS requirements are represented at a regional level utilizing the 

aggregate regional representation of RPS requirements that is implemented in AEO 201015 as 

shown in Appendix 3-6. This appendix shows the RPS requirements that apply to the NEMS 

(National Energy Modeling System) regions used in AEO. The RPS requirement for a particular 

NEMS region applies to all IPM regions that are predominantly contained in that NEMS region. 

3.9.4 State Specific Environmental Regulations 

EPA Base Case v.4.10 represents laws and regulations in 25 states affecting emissions from the 

electricity sector. The laws and regulations had to either be on the books or expected to come 

into force. Appendix 3-2 summarizes the provisions of state laws and regulations that are 

represented in EPA Base Case 4.10. 

3.9.5 New Source Review (NSR) Settlements 

The New Source Review, (NSR) settlements refer to legal agreements with companies resulting 

from the permitting process under the CAAA which requires industry to undergo an EPA preconstruction review of proposed environmental controls either on new facilities or as modifications 

to existing facilities where there would result a “significant increase” in a regulated pollutant. EPA 

Base Case v.4.10 includes NSR settlements with 20 electric power companies. A summary of the 

units affected and how the settlements were modeled can be found in Appendix 3-3. 

Seven state settlements and five citizen settlements are also represented in EPA Base Case 

v.4.10. These are summarized in Appendices 3-4 and 3-5 respectively. 

3.9.6 Emission Assumptions for Potential (New) Units 

Emissions from existing and planned/committed units vary from installation to installation based 

on the performance of the generating unit and the emissions regulations that are in place. In 

contrast, there are no location-specific variations in the emission and removal rate capabilities of 

potential new units. In IPM, potential new units are modeled as additional capacity and generation 

that may come on line in each model region. Across all model regions the emission and removal 

 

15Energy Information Administration, U.S. Department of Energy, Assumptions to Annual Energy 

Outlook 2010: Renewable Fuels Module (DOE/EIA-0554(2010)), April 9, 2010, Table 13.4 

“Aggregate Regional RPS Requirements, www.eia.doe.gov/oiaf/aeo/assumption/renewable.html

and www.eia.doe.gov/oiaf/aeo/assumption/pdf/renewable_tbls.pdf
3-21 

rate capabilities of potential new units are the same. It should be noted that, new coal units cannot 

be built in the CA-N, CA-S, NYC, LILC, or NENG model regions due to particularly stringent state 

emission limits placed on fossil fired units. The specific assumptions regarding the emission and 

removal rates of potential new units in EPA Base Case v.4.10 are presented in Table 3-11. (Note: 

 Nuclear, wind, solar, and fuel cell technologies are not included in Table 3-11 because they do 

not emit any of the listed pollutants.) For additional details on the modeling of potential new units 

see Chapter 4. 

3.10 Capacity Deployment Constraints 

Due to its extended time horizon and the policies that EPA Base Case v.4.10 is expected to be 

used to analyze, capacity deployment constraints for the more capital intensive generation 

technologies and retrofits (new nuclear, advanced coal with carbon capture, and carbon capture 

retrofits) were incorporated into the base case. The deployment constraints are intended to 

capture factors that are likely to place an upper bound on the amount of these technologies that 

can be built in any given model run year over the modeling time horizon. Such limiting factors 

include: 

• production capacity limitations (including the number of engineering and construction (E/C) 

firms capable of executing large power projects in the U.S., the number of large projects each 

such firm can handle, and the number of multi-billion dollar projects a firm can take on in 

parallel), 

• general limitations in the domestic infrastructure for heavy manufacturing, 

• financial limitations (number of projects that can obtain financing simultaneously at an 

acceptable level of risk), 

• workforce limitations (limitations in the skilled engineering and construction labor force, 

replacement challenges caused by an aging workforce, on the one hand, and inadequate 

training infrastructure for new entrants, on the other). 

The capacity deployment constraints are based on assessments by EPA power sector 

engineering staff of historical trends and projections of capability going forward. Conceptually, the 

procedure used to develop these constraints consisted of the following steps: 

1. Start by estimating the maximum number of E/C firms that will be available over the time 

horizon. 

2. Estimate the maximum number of a particular type of generating unit (e.g., 600 MW advanced 

coal plant with carbon capture) that a single E/C firm can complete in the first 5-year period 

(2015-2020). 

3. Multiply the number of E/C firms estimated in Step 1 by the number of units per firm found in 

Step 2 to obtain the maximum number of these generating units that can be completed in the 

first period. 

4. Determine if there will be competition from other competing technologies for the same 

productive capacity and labor force used for the technology analyzed in steps 2 and 3. If not, 

go to Step 7. If so, go to Step 5. 

5. Establish an equivalency table showing how much capacity could be built if the effort required 

to build 1 MW of the type of technology analyzed in steps 2 and 3 were instead used to build 

another type of generating technology (e.g., 1600 MW nuclear plant). 

6. Based on these calculations build a production possibility frontier showing the maximum mix 

of the two generating technologies that can be added in the first 5-year period. 

7. Over the subsequent five year periods assume that the E/C firms have increased capabilities 

relative to the previous five year period. Represent the increased capability by a capability 

multiplier. For example, it might be assumed that each succeeding 5-year period the E/C 

firms can design and build 1.4 as much as in the immediately preceding 5-year period. 

Multiply the capacity deployment limit(s) from the preceding period by the capability multiplier 

to derive the capacity deployment limit for the subsequent period. 
3-22 

8. If necessary, prevent sudden spikes in capacity in later periods when there has been little or 

no build up in preceding periods by tying the amount of capacity that can be built in a given 

period to the amount of capacity built in preceding periods. 

Appendix 3-07 shows the joint capacity deployment constraint on advanced coal with carbon 

capture and storage (CCS) and new nuclear. Appendix 3-08 shows the capacity deployment 

constraint on new nuclear in itself. The bar graph in Appendix 3-08 illustrates how building 

capacity in earlier years increases the maximum capacity that can be built over the entire 

modeling time horizon. 
3-23 

Table 3-11 Emission and Removal Rate Assumptions for Potential (New) Units in EPA Base Case 

Gas 

Controls, 

Removal, 

and 

Emissions 

Rates 

Supercritical 

Pulverized 

Coal - Wet 

Scrubber 

Supercritical 

Pulverized 

Coal - Dry 

Scrubber 

Integrated 

Gasification 

Combined 

Cycle 

Advanced 

Coal with 

Carbon 

Capture 

Advanced 

Combined 

Cycle 

Advanced 

Combustio

n Turbine 

Biomass 

Conventional 

Direct-Fired 

Boiler 

Biomass 

Gasification 

Combined 

Cycle 

SO2

Removal / 

Emissions 

Rate 

98% with a 

floor of 0.06 

lbs/MMBtu 

93% with a 

floor of 0.065 

lbs/MMBtu 

99% 99% None None 0.08 lbs/MMBtu 0.08 lbs/MMBtu 

NOx Emission Rate 0.06 lbs/MMBtu 0.06 lbs/MMBtu 0.013 lbs/MMBtu 0.013 lbs/MMBtu 0.011 lbs/MMBtu 0.011 lbs/MMBtu 0.36 lbs/MMBtu 0.102 lbs/MMBtu 

Hg 

Removal / 

Emissions 

Rate 

90% 90% 90% 90% 

Natural 

Gas: 

0.000138 

lbs/MMBtu

Oil: 

0.483 

lbs/MMBtu 

Natural 

Gas: 

.000138 

lbs/MMBtu 

Oil: 

0.483 

lbs/MMBtu 

0.57 

lbs/MMBtu 

0.57 

lbs/MMBtu 

CO2

Removal / 

Emissions 

Rate 

205.2 - 217.3 

lbs/MMBtu 

205.2 - 217.3 

lbs/MMBtu 

205.2 - 217.3 

lbs/MMBtu 90% 

Natural 

Gas: 

117.08 

lbs/MMBtu

Oil: 

161.39 

lbs/MMBtu 

Natural 

Gas: 

117.08 

lbs/MMBtu 

Oil: 

161.39 

lbs/MMBtu 

None None 
Appendix 3-1.1 

Appendix 3-1 NOx Rate Development in EPA Base Case v.4.10 

The following questions (Q) and answers (A) are intended to provide further background on the 

four NOX rates found in the NEEDS, v.4.10 database. 

Q1: Why are four NOX rates included in NEEDS? 

A1: The four NOX rates in NEEDS represent a menu of all the NOX rates applicable to a specific 

generating unit with only its current configuration of NOx combustion and post-combustion controls 

under all the conceivable policies involving NOx controls that might be modeled in the future. By 

defining this menu up front for every generating unit, the program that sets up an IPM run can 

follow a set of decision rules to select the rate(s) appropriate for the unit in the particular policy 

being modeled consistent with the unit’s existing set of combustion and post-combustion NOx

controls. 

Q2: What operational states do the four NOx rates represent? 

A2: Before answering this question, let’s name the four NOx rates that are in NEEDS: 

Mode 1= Uncontrolled Base Rate 

Mode 2= Controlled Base Rate 

Mode 3= Uncontrolled Policy Rate 

Mode 4 = Controlled Policy Rate 

The operational states associated with each of the four NOx rates are shown in the second and 

third columns in the table below. 

Q3: What NOx policies in a model run result in the assignment of each of the NOx rates? 

A3: The policies causing each rate to be assigned are shown in the last column in the table below. 

Interpreting the Mode 1 – 4 NOx Rates in NEEDS

Name Operational State of NOx

Controls 

NOx Policies Causing This Rate 

To be Assigned 

Units with post combustion 

NOx controls: Do they 

operate the controls? 

No 

Mode 1 = 

Uncontrolled 

Base Rate 

Units without postcombustion controls: Do 

they upgrade to state-offthe-art combustion controls? 

No 

If the unit is not covered by any NOx limit 

in the run, pre-assign this as its NOx rate 

Units with post combustion 

NOx controls: Do they 

operate the controls? 

Yes 

Mode 2 = 

Controlled 

Base Rate 

Units without postcombustion controls: Do 

they upgrade to state-offthe-art combustion controls? 

No 

If the unit is covered by a mercury 

policy, pre-assign this as its NOx rate 

Explanation: Post-combustion NOx

controls figure in mercury reduction but 

NOx combustion controls do not, so the 

operational state (in column 2) fits the 

requirements of the policy 

Units with post combustion 

NOx controls: Do they 

operate the controls? 

No Mode 3 = 

Uncontrolled 

Policy Rate Units without postcombustion controls: Do 

they upgrade to state-offYes 

If the unit is covered by a summer NOx

limit pre-assign this as its winter NOx

rate. 
Appendix 3-1.2 

Name Operational State of NOx

Controls 

NOx Policies Causing This Rate 

To be Assigned 

the-art combustion controls? 

Units with post combustion 

NOx controls: Do they 

operate the controls? 

Yes 

Mode 4 = 

Controlled 

Policy Rate 

Units without postcombustion controls: Do 

they upgrade to state-offthe-art combustion controls? 

Yes 

If the unit is covered by a summer NOx

limit pre-assign this as its summer NOx

rate. 

If the unit is covered by an annual NOx

limit, pre-assign this as its winter and 

summer NOx rates. 

Q4: How are the values of the Mode 1-4 NOx rates derived? 

A4: We start with the emission data reported to EPA for a specific year under Title IV of the Clean 

Air Act Amendments of 1990 (Acid Rain Program) and NOx Budget Program. Using this data, NOx

rates are derived for the summer and winter seasons. 

Calculations can get complex, so we’ll illustrate it here for coal units only and with the assumption 

that the data were absolutely complete and consistent with what engineering theory tells us its 

values should be. Otherwise, we apply additional screens. Explaining them is beyond the scope 

of this illustration. Basically, here’s how the values would be derived: 

Mode 1

For all coal units Mode 1 = Winter NOx rate 

Mode 2 

For coal units without NOx post-combustion controls 

Mode 2 = Mode 1 rate 

For coal units with NOx post-combustion controls, 

Min{max[Mode 1 NOx rate * (1-removal efficiency), floor rate], ETS Summer NOx rate} 

 Where 

For an SCR, 

Removal efficiency = 90% 

Floor rate = 0.06 lb/MMBtu; 

For an SNCR, 

Removal efficiency = 35% 

No floor rate is applicable 

Mode 3

Step 1: Pre-screen units that already have state of art (SOA) combustion controls from units that 

have non-SOA combustion controls from units that have no combustion controls 

For coal units without post-combustion NOx controls

For units listed as not having combustion controls 

 Make sure their NOx rates do not indicate that they really do have SOA control 

If Mode 1 > Cut-off (in Table 3-1.2), then Mode 1 = Base rate. Go to Step 3 

 If Mode 1 ≤ Cut-off (in Table 3-1.2), then the unit has SOA control and 

Go to Step 5 using the Mode 1 rate as the provisional SOA NOx rate. 

For coal listed with combustion controls

If Mode 1 > Cut-off (in Table 3-1.2), then unit has non-SOA combustion controls. 

Go to Step 2 
Appendix 3-1.3 

 If Mode 1 ≤ Cut-off (in Table 3-1.2), then the unit has SOA control and 

Go to Step 5 using the Mode 1 rate as the provisional SOA NOx rate. 

For coal units with post-combustion NOx controls

 For coal units with SCR

 Mode 1 = Mode 3 

 For coal units with SNCR

 If Mode 1 ≤ Cut-off (in Table 3-1.2), then the unit has SOA control and 

 Mode 1 = Mode 3 

If Mode 1 > Cut-off (in Table 3-1.2), then unit has non-SOA combustion controls. 

Go to Step 2 

Step 2: For units with non-SOA combustion controls, determine their Base NOx rate, i.e., the unit’s 

uncontrolled emission rate without combustion controls, using the appropriate equation (not in 

boldface italics) in Table 3-1.3 to back calculate their Base NOx rate. Use the default Base NOx

rate values if back calculations can’t be performed. Once the Base NOx rate is obtained, go to 

Step 3. 

Step 3: Use the appropriate equations (in boldface italics) in Table 3-1.3 to calculate the NOx rate 

with SOA combustion controls. 

Step 4: Compare the value calculated in Step 3 to the applicable NOx floor rate in Table 3-1:2. 

For units with post-combustion controls

If the value from Step 3 is ≥ floor, use the Step 3 value as Mode 3 NOx rate. Otherwise, use the 

floor as the Mode 3 NOx rate. 

For units without post-combustion controls

If the value from Step 3 is ≥ floor, use the Step 3 value as the provisional SOA NOx rate. 

Otherwise, use the floor as their provisional SOA NOx rate. 

Go to Step 5. 

Step 5: For units without post combustion controls compare the provisional SOA NOx rate 

obtained in previous steps to their Summer NOx rate. 

 If Summer NOx rate < provisional SOA NOx rate, then Mode 3 = summer NOx rate. 

 If Summer NOx rate ≥ provisional SOA NOx rate, then 

 Mode 3 = provisional SOA NOx rate. 

Mode 4

For units without post-combustion controls

Mode 4 = Mode 3 

For units with SCR post-combustion controls

Mode 4 = Mode 2 

For units with SNCR post-combustion controls

Mode 4 = minimum {(1-.35) * Mode 3, Summer NOx rate} 

Note: The (1-.35) term in the equation above represents the 35% NOx removal efficiency of 

SNCR. 

Q5: Is there anything else that might be useful to understand about the Mode 1 – 4 NOx rates. 
Appendix 3-1.4 

A5: There are several things to note about the Modes 1-4 designations. “Controlled” refers to the 

rates provided by post combustion NOx controls, i.e., selective catalytic reduction (SCR) or 

selective non-catalytic reduction (SNCR), if they are present at the unit. For generating units that 

do not have post-combustion controls, the controlled rate will be the same as the uncontrolled 

rate. For generating units that do have post-combustion controls, the controlled and uncontrolled 

rates will differ. Base and Policy NOx rates will be same if the unit has state-of-the-art NOx

combustion controls or is in the SIP Call region where current combustion controls are assumed to 

be retained. Base and policy rates will differ if a unit does not currently have state-of-the-art 

combustion controls that would be installed in response to a NOx policy. Examples of each of 

these instances are shown in Table 3-1.1. 

Other things worth noting are: 

(a) In general, winter NOx rates reported in EPA’s Emission Tracking System were used as 

proxies for the uncontrolled base NOx rates. 

(b) If a unit does not report having combustion controls, but has an emission rate below a specific 

cut-off rate (shown in Table 3-1.2), it is considered to have combustion controls. 

(c) For units with combustion controls that were not state-of-the-art, emission rates without those 

combustion controls were back-calculated and then policy rates were derived assuming the 

reductions provided by state-of-the art combustion controls. 

(d) The NOx rates achievable by state-of-the-art combustion controls vary by coal rank 

(bituminous and sub-bituminous) and boiler type. The equations used to derive these rates are 

shown in Table 3-1.3. 

Q6: What are examples of the Mode 1-4 NOx for some actual operating generating units? 

A6: Table 3-1.1 gives the Mode 1-4 NOx rates for real generating units. They are meant to 

illustrate a range of situations that can arise. 
Appendix 3-1.5 

Table 3-1.1 Examples of Base and Policy NOx Rates Occurring in EPA Base Case v.4.10 

Plant 

Name Unique ID 

PostCombustion 

Control 

Uncontrolled 

NOx Base 

Rate 

Controlled 

NOx Base 

Rate 

Uncontrolled 

NOx Policy 

Rate 

Controlled 

NOx Policy 

Rate 

Ex

Situation 1: For generating units that do not have post-combustion controls, the controlled and uncontrolled rates will be the 

Four 

Corners 2442_B_1 None 0.809 0.809 0.524 0.524 Situation 4 also app

now added OFA so 

Situation 2: For generating units that do have post-combustion controls, the controlled and uncontrolled rates will differ. 

Big Sandy 1353_B_BSU2 SCR 0.638 0.064 0.638 0.064 

(1) Has SCR so see uncontrolled and co(2) Situation 3b also 

Situation 3a: Base and Policy NOx rates will be same if the unit has state-of-the-art NOx combustion controls or . . . 

Greene 

County 10_B_2 None 0.316 0.316 0.316 0.316 Situation 1 also app

Roxboro 2712_B_1 SCR 0.900 0.084 0.900 0.084 Situation 2 also app

Situation 3b: . . . is in the SIP Call region where current combustion controls are assumed to be retained. 

Thomas Hill 2168_B_MB3 SCR 0.223 0.060 0.223 0.060 Situation 2 also app

Waukegan 883_B_17 None 0.710 0.710 0.710 0.710 

(1) Has NOx combusdoesn't get added corate because it is a c(2) Situation 1 also a

Situation 4: Base and policy rates will differ if a unit does not currently have state-of-the-art combustion controls and would inresponse to a NOx policy. 

Clay 

Boswell 1893_B_4 SNCR 0.231 0.150 0.152 0.099 

(1) Drop in uncontrocompared to uncontaddition of combustifloor.) (2) Unit has SNCR sand you see a 35% and controlled NOx r
Appendix 3-1.6 

Table 3-1.2 Cutoff and Floor NOx Rates (lb/MMBtu) in EPA Base Case v.4.10 

Cutoff Rate (lbs/MMBtu) Floor Rate (lbs/MMBtu) Boiler Type Bituminous Subbituminous Lignite Bituminous Subbituminous Lignite 

Wall-Fired 

Dry-Bottom 0.43 0.33 0.29 0.32 0.18 0.18 

TangentiallyFired 0.34 0.24 0.22 0.24 0.12 0.17 

Cell-Burners 0.43 0.43 0.43 0.32 0.32 0.32 

Cyclones 0.62 0.67 0.67 0.47 0.49 0.49 

VerticallyFired 0.57 0.44 0.44 0.49 0.25 0.25 

Table 3-1.3 NOx Removal Efficiencies for Different Combustion Control Configurations in 

EPA Base Case v.4.10 

(State of the art configurations are shown in bold italic.) 

Boiler Type Coal Type Combustion Control 

Technology 

Fraction of 

Removal 

Default 

Removal 

LNB 0.163 + 0.272* 

Base NOx 0.568 Dry Bottom 

Wall-Fired Bituminous 

LNB + OFA 0.313 + 0.272* 

Base NOx 

0.718 

LNB 0.135 + 0.541* 

Base NOx 0.574 Dry Bottom 

Wall-Fired 

Subbituminous

/Lignite LNB + OFA 0.285 + 0.541* 

Base NOx 

0.724 

LNC1 0.162 + 0.336* 

Base NOx 0.42 

LNC2 0.212 + 0.336* 

Base NOx 0.47 TangentiallyFired Bituminous 

LNC3 0.362 + 0.336* 

Base NOx 0.62 

LNC1 0.20 + 0.717* 

Base NOx 0.563 

LNC2 0.25 + 0.717* 

Base NOx 0.613 TangentiallyFired 

Subbituminous

/Lignite 

LNC3 0.35 + 0.717* 

Base NOx 0.713 

Notes:

LNB = Low NOx Burner 

OFA = Overfire Air 

LNC = Low NOx Control 
Appendix 3-2.1 

Appendix 3-2 State Power Sector Regulations included in EPA Base Case 

v.4.10 

State/ Region Bill Emission 

Type Emission Specifications Implementation Status 

Alabama 

Alabama 

Administrative 

Code Chapter 

335-3-8 

NOx

0.02 lbs/MMBtu annual PPMDV for combined 

cycle EGUs which commenced operation after 

April 1, 2003 

2003 

Arizona 

Title 18, 

Chapter 2, 

Article 7 

Hg 

90% removal of Hg content of fuel or 0.0087 

lb/GWH-hr annual reduction for all non-cogen 

coal units > 25 MW 

2017 

NOx

9.68 MTons annual cap for list of entities in 

Appendix A of "Annual RECLAIM Audit Market 

Report for the Compliance Year 2005" (304 

entities) California CA Reclaim 

Market 

SO2

4.292 MTons annual cap for list of entities in 

Appendix A of "Annual RECLAIM Audit Market 

Report for the Compliance Year 2005" (304 

entities) 

1994 

Colorado 40 C.F.R. Part 

60 Hg 

2012 & 2013: 80% reduction of Hg content of 

fuel or 0.0174 lb/GW-hr annual reduction for 

Pawnee Station 1 and Rawhide Station 101 

2014 through 2016: 80% reduction of Hg 

content of fuel or 0.0174 lb/GW-hr annual 

reduction for all coal units > 25 MW 

2017 onwards: 90% reduction of Hg content of 

fuel or 0.0087 lb/GW-hr annual reduction for all 

coal units > 25 MW 

2012 

Executive 

Order 19 and 

Regulations of 

Connecticut 

State Agencies 

(RCSA) 22a174-22 

NOx

0.15 lbs/MMBtu annual rate limit for all fossil 

units > 15 MW 

Executive 

Order 19, 

RCSA 22a-198 

& Connecticut 

General 

Statues (CGS) 

22a-198 

SO2

0.33 lbs/MMBtu annual rate limit for all fossil 

units > 15 MW 

2003 

Connecticut 

Public Act No. 

03-72 & RCSA 

22a-198 

Hg 

90% removal of Hg content of fuel or 0.0087 

lb/GW-hr annual reduction for all coal-fired 

units 

2008 

Regulation 

1148: Control 

of Stationary 

Combustion 

Turbine EGU 

Emissions 

NOx

0.19 lbs/MMBtu ozone season PPMDV for 

stationary, liquid fuel fired CT EGUs >1 MW 

0.39 lbs/MMBtu ozone season PPMDV for 

stationary, gas fuel fired CT EGUs >1 MW 

2009 

NOx

0.125 lbs/MMBtu rate limit of NOx annually for 

all coal and residual-oil fired units > 25 MW 

Delaware 

Regulation No. 

1146: Electric 

Generating 

Unit (EGU) 

Multi-Pollutant 

Regulation 

SO2

0.26 lbs/MMBtu annual rate limit for coal and 

residual-oil fired units > 25 MW 

2009 
Appendix 3-2.2 

State/ Region Bill Emission 

Type Emission Specifications Implementation Status 

Hg 

2012: 80% removal of Hg content of fuel or 

0.0174 lb/GW-hr annual reduction for all coal 

units > 25 MW 

2013 onwards: 90% removal of Hg content of 

fuel or 0.0087 lb/GW-hr annual reduction for all 

coal units > 25 MW 

Georgia 

Multipollutant 

Control for 

Electric Utility 

Steam 

Generating 

Units 

SCR, 

FGD, and 

Sorbent 

Injection 

Baghouse 

controls to 

be 

installed 

The following plants must install controls: 

Bowen, Branch, Hammond, McDonough, 

Scherer, Wansley, and Yates 

Implementation 

from 2008 

through 2015, 

depending on 

plant and control 

type 

Title 35, 

Section 

217.706 

NOx

0.25 lbs/MMBtu summer season rate limit for all 

fossil units > 25 MW 2004 

NOx

0.11 lbs/MMBtu annual rate limit and ozone 

season rate limit for all Dynergy and Ameren 

coal steam units > 25 MW 

2012 

SO2

2013 & 2014: 0.33 lbs/MMBtu annual rate limit 

for all Dynergy and Ameren coal steam units > 

25 MW 

2015 onwards: 0.25 lbs/MMBtu annual rate limit 

for all Dynergy and Ameren coal steam units > 

25 MW 

2013 

Title 35, Part 

225, Subpart 

B: Control of 

Hg Emissions 

from Coal Fired 

Electric 

Generation 

Units 

Hg 

90% removal of Hg content of fuel or 0.08 

lbs/GW-hr annual reduction for all Ameren and 

Dynergy coal units > 25 MW 

2015 

NOx

0.11 lbs/MMBtu ozone season and annual rate 

limit for all specified Midwest Gen coal steam 

units 

2012 

SO2

0.44 lbs/MMBtu annual rate limit in 2013, 

decreasing annually to 0.11 lbs/MMBtu in 2019 

for all specified Midwest Gen coal steam units 

2013 

Illinois 

Title 35 Part 

225; Subpart F: 

Combined 

Pollutant 

Standards 

Hg 

90% removal of Hg content of fuel or 0.08 

lbs/GWh annual reduction for all specified 

Midwest Gen coal steam units 

2015 

Louisiana 

Title 33 Part II - 

Chapter 22, 

Control of 

Nitrogen 

Oxides 

NOx

1.2 lbs/MMBtu ozone season PPMDV for all 

single point sources that emit or have the 

potential to emit 5 tons or more of SO2 into the 

atmosphere 

2005 

Chapter 145 

NOx Control 

Program 

NOx

0.22 lbs/MMBtu annual rate limit for all fossil 

fuel units > 25 MW built before 1995 with a heat 

input capacity < 750 MMBtu/hr 

0.15 lbs/MMBtu annual rate limit for all fossil 

fuel units > 25 MW built before 1995 with a heat 

input capacity > 750 MMBtu/hr 

0.20 lbs/MMBtu annual rate limit for all fossil 

fuel fired indirect heat exchangers, primary 

boilers, and resource recovery units with heat 

input capacity > 250 MMBtu/hr 

2005 

Maine 

Statue 585-B 

Title 38, 

Chapter 4: 

Protection and 

Improvement 

of Air 

Hg 25 lbs annual cap for any facility including 

EGUs 2010 
Appendix 3-2.3 

State/ Region Bill Emission 

Type Emission Specifications Implementation Status 

NOx

7.3 MTons summer cap and 16.7 MTons 

annual cap for 15 specific existing coal steam 

units 

SO2

2009 through 2012: 48.6 MTons annual cap for 

15 specific existing coal steam units 

2013 onwards: 37.2 MTons annual cap for 15 Maryland specific existing coal steam units Maryland 

Healthy Air Act 

Hg 

2010 through 2012: 80% removal of Hg content 

of fuel for 15 specific existing coal steam units 

2013 onwards: 90% removal of Hg content of 

fuel for 15 specific existing coal steam units 

2009 

NOx

1.5 lbs/MWh annual GPS for Bayton Point, 

Mystic Generating Station, Somerset Station, 

Mount Tom, Canal, and Salem Harbor 

SO2

3.0 lbs/MWh annual GPS for Bayton Point, 

Mystic Generating Station, Somerset Station, 

Mount Tom, Canal, and Salem Harbor 

Massachusetts 310 CMR 7.29 

Hg 

2012: 85% removal of Hg content of fuel or 

0.00000625 lbs/MWh annual GPS for Brayton 

Point, Mystic Generating Station, Somerset 

Station, Mount Tom, Canal, and Salem Harbor 

2013 onwards: 95% removal of Hg content of 

fuel or 0.00000250 lbs/MWh annual GPS for 

Brayton Point, Mystic Generating Station, 

Somerset Station, Mount Tom, Canal, and 

Salem Harbor 

2006 

Michigan 

Part 15. 

Emission 

Limitations and 

Prohibitions - 

Mercury 

Hg 90% removal of Hg content of fuel annually for 

all coal units > 25 MW 2015 

Minnesota 

Minnesota Hg 

Emission 

Reduction Act 

Hg 90% removal of Hg content of fuel annually for 

all coal units > 250 MW 2008 

Missouri 10 CSR 10-

6.350 NOx

0.25 lbs/MMBtu annual rate limit for all fossil 

fuel units > 25 MW in the following counties: 

Bollinger, Butler, Cape Girardeau, Carter, 

Clark, Crawford, Dent, Dunklin, Gasconade, 

Iron, Lewis, Lincoln, Madison, Marion, 

Mississippi, Montgomery, New Madrid, Oregon, 

Pemiscot, Perry, Phelps, Pike, Ralls, Reynolds, 

Ripley, St. Charles, St. Francois, Ste. 

Genevieve, Scott, Shannon, Stoddard, Warren, 

Washington and Wayne 

0.18 lbs/MMBtu annual rate limit for all fossil 

fuel units > 25 MW the following counties: City 

of St. Louis, Franklin, Jefferson, and St. Louis 

0.35 lbs/MMBtu annual rate limit for all fossil 

fuel units > 25 MW in the following counties: 

Buchanan, Jackson, Jasper, Randolph, and 

any other county not listed 

2004 

Montana 

Montana 

Mercury Rule 

Adopted 

10/16/06 

Hg 

0.90 lbs/TBtu annual rate limit for all non-lignite 

coal units 

1.50 lbs/TBtu annual rate limit for all lignite coal 

units 

2010 
Appendix 3-2.4 

State/ Region Bill Emission 

Type Emission Specifications Implementation Status 

RSA 125-O: 

11-18 Hg 

80% reduction of aggregated Hg content of the 

coal burned at the facilities for Merrimack Units 

1 & 2 and Schiller Units 4, 5, & 6 

2012 

NOx

2.90 MTons summer cap for all fossil steam 

units > 250 MMBtu/hr operated at any time in 

1990 and all new units > 15 MW 

3.64 MTons annual cap for Merrimack 1 & 2, 

Newington 1, and Schiller 4 through 6 

New 

Hampshire 

ENV-A2900 

Multiple 

pollutant 

annual budget 

trading and 

banking 

program SO2

7.29 MTons annual cap for Merrimack 1 & 2, 

Newington 1, and Schiller 4 through 6 

2007 

N.J.A.C. 7:27-

27.5, 27.6, 

27.7, and 27.8 

Hg 

90% removal of Hg content of fuel annually for 

all coal-fired units 

95% removal of Hg content of fuel annually for 

all MSW incinerator units 

2007 

N.J. A. C. Title 

7, Chapter 27, 

Subchapter 19, 

Table 1 

NOx

Annual rate limits in lbs/MMBtu for the following 

technologies: 

1.0 for tangential and wall-fired wet-bottom coal 

boilers serving an EGU 

0.60 for cyclone-fired wet-bottom coal boilers 

serving an EGU 

0.38 for tangential dry-bottom coal boilers 

serving an EGU 

0.45 for wall-fired dry-bottom coal boilers 

serving an EGU 

0.55 for cyclone-fired dry-bottom coal boilers 

serving an EGU 

0.20 for tangential oil and/or gas boilers serving 

an EGU 

0.28 for wall-fired oil and/or gas boilers serving 

an EGU 

0.43 for cyclone-fired oil and/or gas boilers 

serving an EGU 

2007 

New Jersey 

N.J. A. C. Title 

7, Chapter 27, 

Subchapter 19, 

Table 4 

NOx

2.2 lbs/MWh annual GPS for gas-burning 

simple cycle combustion turbine units 

3.0 lbs/MWh annual GPS for oil-burning simple 

cycle combustion turbine units 

1.3 lbs/MWh annual GPS for gas-burning 

combined cycle CT or regenerative cycle CT 

units 

2.0 lbs/MWh annual GPS for oil-burning 

combined cycle CT or regenerative cycle CT 

units 

2007 

Part 237 NOx

39.91 MTons non-ozone season cap for fossil 

fuel units > 25 MW 2004 

Part 238 SO2

131.36 MTons annual cap for fossil fuel units > 

25 MW 2005 

New York 

Mercury 

Reduction 

Program for 

Coal-Fired 

Electric Utility 

Steam 

Generating 

Units 

Hg 

786 lbs annual cap through 2014 for all coal 

fired boiler or CT units >25 MW after Nov. 15, 

1990. 

0.60 lbs/TBtu annual rate limit for all coal units 

> 25 MW developed after Nov.15 1990 

2010 

NOx

25 MTons annual cap for Progress Energy coal 

plants > 25 MW and 31 MTons annual cap for 

Duke Energy coal plants > 25 MW 

2007 

North Carolina 

NC Clean 

Smokestacks 

Act: Statute 

143-215.107D 

SO2

2012: 100 MTons annual cap for Progress 

Energy coal plants > 25 MW and 150 MTons 

annual cap for Duke Energy coal plants 

>25MW 

2013 onwards: 50 MTons annual cap for 

Progress Energy coal plants > 25 MW and 80 

2009 
Appendix 3-2.5 

State/ Region Bill Emission 

Type Emission Specifications Implementation Status 

MTons annual cap for Duke Energy coal plants 

> 25 MW 

Oregon 

Administrative 

Rules, Chapter 

345, Division 

24 

CO2

675 lbs/MWh annual rate limit for new 

combustion turbines burning natural gas with a 

CF >75% and all new non-base load plants 

(with a CE <= 75%) emitting CO2

1997 

Oregon Utility 

Mercury Rule - 

Existing Units 

Hg 

90% removal of Hg content of fuel reduction or 

0.6 lbs/TBtu limitation for all existing coal units 

>25 MW 

2012 

Oregon 

Oregon Utility 

Mercury Rule - 

Potential Units 

Hg 25 lbs rate limit for all potential coal units > 25 

MW 2009 

Pacific 

Northwest 

Washington 

State House 

Bill 3141 

CO2

$1.45/Mton cost (2004$) for all new fossil-fuel 

power plant 2004 

SO2

273.95 MTons cap of SO2 for all grandfathered 

units built before 1971 in East Texas Region Senate Bill 7 

Chapter 101 

NOx

Annual cap for all grandfathered units built 

before 1971 in MTons: 84.48 in East Texas, 

18.10 in West Texas, 1.06 in El Paso Region 

2003 

East and Central Texas annual rate limits in 

lbs/MMBtu for units that came online before 

1996: 

Gas fired units: 0.14 

Coal fired units: 0.165 

Stationary gas turbines: 0.14 

Dallas/Fort Worth Area annual rate limit for 

utility boilers, auxiliary steam boilers, stationary 

gas turbines, and duct burners used in an 

electric power generating system except for CT 

and CC units online after 1992: 

0.033 lbs/MMBtu or 0.50 lbs/MWh output or 

0.0033 lbs/MMBtu on system wide heat input 

weighted average for large utility systems 

0.06 lbs/MMBtu for small utility systems 

Houston/Galveston region annual Cap and 

Trade (MECT) for all fossil units: 

17.57 MTons 

Texas 

Chapter 117 NOx

Beaumont-Port Arthur region annual rate limits 

for utility boilers, auxiliary steam boilers, 

stationary gas turbines, and duct burners used 

in an electric power generating system: 0.10 

lbs/MMBtu 

2007 

Utah 

R307-424 

Permits: 

Mercury 

Requirements 

for Electric 

Generating 

Units 

Hg 90% removal of Hg content of fuel annually for 

all coal units > 25 MW 2013 

Wisconsin 

NR 428 

Wisconsin 

Administration 

Code 

NOx

Annual rate limits in lbs/MMBtu for coal fired 

boilers > 1,000 MMBtu/hr : 

Wall fired, tangential fired, cyclone fired, and 

fluidized bed: 2009: 0.15, 2013 onwards: 0.10 

Arch fired: 2009 onwards: 0.18 

2009 
Appendix 3-2.6 

State/ Region Bill Emission 

Type Emission Specifications Implementation Status 

Annual rate limits in lbs/MMBtu for coal fired 

boilers between 500 and 1,000 MMBtu/hr: 

Wall fired: 2009: 0.20; 2013 onwards: 0.17 in 

2013 

Tangential fired: 2009 onwards: 0.15 

Cyclone fired: 2009: 0.20; 2013 onwards: 0.15 

Fluidized bed: 2009: 0.15; 2013 onwards: 0.10 

Arch fired: 2009 onwards: 0.18 

Annual rate limits for CTs in lbs/MMBtu: 

Natural gas CTs > 50 MW: 0.11 

Distillate oil CTs > 50 MW: 0.28 

Biologically derived fuel CTs > 50 MW: 0.15 

Natural gas CTs between 25 and 49 MW: 0.19 

Distillate oil CTs between 25 and 49 MW: 0.41 

Biologically derived fuel CTs between 25 and 

49 MW: 0.15 

Annual rate limits for CCs in lbs/MMBtu: 

Natural gas CCs > 25 MW: 0.04 

Distillate oil CCs > 25 MW: 0.18 

Biologically derived fuel CCs > 25 MWs: 0.15 

Natural gas CCs between 10 and 24 MW: 0.19 

Chapter NR 

446. Control of 

Mercury 

Emissions 

Hg 

2012 through 2014: 40% reduction in total Hg 

emissions for all coal-fired units in electric 

utilities with annual Hg emissions > 100 lbs 

2015 onwards: 90% removal of Hg content of 

fuel or 0.0080 lbs/GW-hr reduction in coal fired 

EGUs > 150 MW 

80% removal of Hg content of fuel or 0.0080 

lbs/GW-hr reduction in coal fired EGUs > 25 

MW 

2010 
Appendix 3-3.1 

Appendix 3-3 New Source Review (NSR) Settlements in EPA Base Case v.4.10 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

Alabama Power 

James H. 

Miller Alabama Units 3 & 4 Install and operate FGD continuously 95% 12/31/2011 Operate existing SCR continuously 0.1 5/1/2008 0.03 12/31/2006 

With 45 days of settlement entry, APC must retire 7,538 SO2 emission allowances. 

APC shall trade, or oexchange Miller excemission allowanceof the APC 

Minnkota Power Cooperative Beginning 1/01/2006, Minnkota shall not emit more than 31,000 tons of SO2/year, no more than 26,000 tons beginning 2011, no more than 11,500 tons beginning 1/01/2012. If Unit 3 is not operational by 12/31/2015, then beginning 1/01/2014, the 

Unit 1 

Install and 

continuously 

operate FGD 

95% if wet 

FGD, 90% 

if dry 

12/31/2011

Install and 

continuously operate 

Over-fire AIR, or 

equivalent 

technology with 

emission rate < .36 

0.36 12/31/2009

0.03 if 

wet 

FGD, 

.015 if 

dry FGD

Milton R. 

Young Minnesota 

Unit 2 

Design, 

upgrade, and 

continuously 

operate FGD 

90% 12/31/2010

Install and 

continuously operate 

over-fire AIR, or 

equivalent 

technology with 

emission rate < .36 

0.36 12/31/2007 0.03 Before 2008 

Plant will surrender 4,346 allowances for each year 2012 – 2015, 8,693 allowances for years 2016 – 2018, 12,170 allowances for year 2019, and 14,886 allowances/year thereafter if Units 1 – 3 are operational by 12/31/2015. If only Units 1 and 2 are operational by12/31/2015, the plant shall retire 17,886 units in 2020 and thereafter. 

Minnkota sell or tradallowanceallocated 2, or 3 thaotherwise available ftrade as a the actionthe settlindefendantcomply wirequireme

SIGECO 

FB Culley Indiana Unit 1 

Repower to 

natural gas 

(or retire) 

12/31/2006 

The provision did not specify an amount of SO2 allowances to be surrendered. It only provided that excess allowances resulting from compliance with NSR settlement provisions must be retired. 
Appendix 3-3.2 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

Unit 2 

Improve and 

continuously 

operate existing 

FGD (shared by 

Units 2 and 3) 

95% 6/30/2004 

Unit 3 

Improve and 

continuously 

operate existing 

FGD (shared by 

Units 2 and 3) 

95% 6/30/2004 Operate Existing SCR Continuously 0.1 9/1/2003 Install and continuously operate a Baghouse 0.015 6/30/2007 

PSEG FOSSIL 

Bergen New Jersey Unit 2 

Repower to 

combined 

cycle 

12/31/2002 

The provision did not specify an amount of SO2 allowances to be surrendered. It only provided that excess allowances resulting from compliance with NSR settlement provisions must be retired. 

Hudson New Jersey Unit 2 

Install Dry FGD 

(or approved alt. 

technology) and 

continually 

operate 

0.15 12/31/2006

Install SCR (or 

approved tech) and 

continually operate 

0.1 5/1/2007 

Install Baghouse (or 

approved 

technology) 

0.015 12/31/2006 

Mercer New Jersey Units 1 & 2 

Install Dry FGD 

(or approved alt. 

technology) and 

continually 

operate 

0.15 12/31/2010

Install SCR (or 

approved tech) and 

continually operate 

0.13 5/1/2006 

TECO 

Units 1 & 

2 

Existing 

Scrubber 

(shared by Units 

1 & 2) 

95% (95% 

or .25) 

09/1/00 

(01/01/13) Big Bend Florida Install SCR 0.1 5/1/2009 

Unit 3 Existing Scrubber 93% if Units 3 & 4 2000 Install SCR 0.1 5/1/2009 

The provision did not 

specify an amount of 

SO2 allowances to be 

surrendered. It only 

provided that excess 

allowances resulting 
Appendix 3-3.3 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

(shared by Units 

3 & 4) 

are 

operating (01/01/10) 

Unit 4 

Existing 

Scrubber 

(shared by Units 

3 & 4) 

93% if 

Units 3 & 4 

are 

operating 

6/22/2005 Install SCR 0.1 7/1/2007 

from compliance with 

NSR settlement 

provisions must be 

retired. 

Gannon Florida Six units 

Retire all six 

coal units 

and 

repower at 

least 550 

MW of coal 

capacity to 

natural gas 

12/31/2004 

WEPCO WEPCO shall comply with the following system wide average NOx emission rates and total NOx tonnage permissible: by 1/1/2005 an emission rate of 0.27 and 31,500 tons, by 1/1/2007 an emission rate of 0.19 and 23,400 tons, and by 1/1/2013 aand 17, 400 tons. For SO2 emissions, WEPCO will comply with: by 1/1/2005 an emission rate of 0.76 and 86,900 tons, by 1/1/2007 an emission rate of 0.61 and 74,400 tons, by 1/1/2008 an emission rate of 0.45 and 55,400 tons, and by 1/1/201and 33,300 tons. 

Units 1 – 

4 

Retire or 

install SO2

and NOx

controls 

12/31/2012 

Install and 

continuously 

operate FGD (or 

approved equiv. 

tech) 

95% or 0.1 12/31/2012

Install SCR (or 

approved tech) and 

continually operate 

0.1 12/31/2012

Units 5 & 

6 

Install and operate 

low NOx burners 12/31/2003

Units 7 & 

8 

Operate existing low 

NOx burners 12/31/2005 Install Baghouse 

Presque Isle Wisconsin 

Unit 9 Operate existing low NOx burners 12/31/2006 Install Baghouse 

1 

Install and 

continuously 

operate FGD (or 

approved control 

tech) 

95% or 0.1 12/31/2006

Install and 

continuously operate 

SCR (or approved 

tech) 

0.1 12/31/2006

Pleasant 

Prairie Wisconsin 

2 

Install and 

continuously 

operate FGD (or 

approved control 

tech) 

95% or 0.1 12/31/2007

Install and 

continuously operate 

SCR (or approved 

tech) 

0.1 12/31/2003

The provision did not 

specify an amount of 

SO2 allowances to be 

surrendered. It only 

provided that excess 

allowances resulting 

from compliance with 

NSR settlement 

provisions must be 

retired. 
Appendix 3-3.4 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

Units 5 & 

6 

Install and 

continuously 

operate FGD (or 

approved control 

tech) 

95% or 0.1 12/31/2012

Install and 

continuously operate 

SCR (or approved 

tech) 

0.1 12/31/2012

Unit 7 

Install and 

continuously 

operate FGD (or 

approved control 

tech) 

95% or 0.1 12/31/2012

Install and 

continuously operate 

SCR (or approved 

tech) 

Oak Creek Wisconsin 0.1 12/31/2012

Unit 8 

Install and 

continuously 

operate FGD (or 

approved control 

tech) 

95% or 0.1 12/31/2012

Install and 

continuously operate 

SCR (or approved 

tech) 

0.1 12/31/2012

Port 

Washington Wisconsin Units 1 – 4 Retire 

12/31/04 for 

Units 1 – 3. 

 Unit 4 by 

entry of 

consent 

decree 

Valley Wisconsin Boilers 1 – 4 Operate existing low NOx burner 

30 days 

after entry 

of consent 

decree 

VEPCO The Total Permissible NOx Emissions (in tons) from VEPCO system are: 104,000 in 2003, 95,000 in 2004, 90,000 in 2005, 83,000 in 2006, 81,000 in 2007, 63,000 in 2008 – 2010, 54,000 in 2011, 50,000 in 2012, and 30,250 each year there afterwill have a system wide emission rate no greater then 0.15 lb/MMBtu. 

Mount Storm West Virginia Units 1 – 3 Construct or improve FGD 95% or 0.15 1/1/2005 Install and continuously operate SCR 0.11 1/1/2008 

Unit 4 

Install and 

continuously operate 

SCR 

0.1 1/1/2013 

Unit 5 Construct or improve FGD 95% or 0.13 10/12/2012 Install and continuously operate SCR Chesterfield Virginia 0.1 1/1/2012 Unit 6 Construct or improve FGD 95% or 0.13 1/1/2010 Install and continuously operate SCR 0.1 1/1/2011 

Chesapeake 

Energy Virginia Units 3 & 4 Install and continuously operate SCR 0.1 1/1/2013 

On or before March 

31 of every year 

beginning in 2013 

and continuing 

thereafter, VEPCO 

shall surrender 

45,000 SO2

allowances. 
Appendix 3-3.5 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

Clover Virginia Units 1 & 2 Improve FGD 95% or 0.13 9/1/2003 

Possum 

Point Virginia Units 3 & 4 Retire and repower to natural gas 5/2/2003 

Santee Cooper Santee Cooper shall comply with the following system wide averages for NOx emission rates and combined tons for emission of: by 1/01/2005 facility shall comply with an emission rate of 0.3 and 30,000 tons, by 1/1/2007 an emission rate of 0.18 1/1/2010 and emission rate of 0.15 and 20,000 tons. For SO2 emission the company shall comply with system wide averages of: by 1/1/2005 an emission rate of 0.92 and 95,000 tons, by 1/1/2007 and emission rate of 0.75 and 85,000 tons, by 1of 0.53 and 70 tons, and by 1/1/2011 and emission rate of 0.5 and 65 tons. 

Unit 1 

Upgrade and 

continuously 

operate FGD 

95% 6/30/2006 

Install and 

continuously operate 

SCR 

0.1 5/31/2004 

Cross South Carolina 

Unit 2 

Upgrade and 

continuously 

operate FGD 

87% 6/30/2006 

Install and 

Continuously 

operate SCR 

0.11/0.1 

05/31/04 

and 

05/31/07 

Unit 1 

Install and 

continuously 

operate FGD 

95% 12/31/2008

Install and 

continuously operate 

SCR 

0.11/0.1 

11/30/04 

and 

11/30/04 

Unit 2 

Install and 

continuously 

operate FGD 

95% 12/31/2008

Install and 

continuously operate 

SCR 

0.12 11/30/2004

Unit 3 

Upgrade and 

continuously 

operate existing 

FGD 

90% 12/31/2008

Install and 

continuously operate 

SCR 

0.14/0.12 

11/30/2005 

and 

11/30/08 

Winyah South Carolina 

Unit 4 

Upgrade and 

continuously 

operate existing 

FGD 

90% 12/31/2007

Install and 

continuously operate 

SCR 

0.13/0.12 

11/30/05 

and 

11/30/08 

Unit 1 

Operate low NOx

burner or more 

stringent technology

6/25/2004 

Grainger South Carolina 

Unit 2 

Operate low NOx

burner or more 

stringent technology

5/1/2004 

The provision did not 

specify an amount of 

SO2 allowances to be 

surrendered. It only 

provided that excess 

allowances resulting 

from compliance with 

NSR settlement 

provisions must be 

retired. 
Appendix 3-3.6 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

Jeffries South Carolina Units 3, 4 Operate low NOx burner or more stringent technology 6/25/2004 

Ohio Edison Ohio Edison shall achieve reductions of 2,483 tons NOx between 7/1/2005 and 12/31/2010 using any combination of: 1) low sulfur coal at Burger Units 4 and 5, 2) operating SCRs currently installed at Mansfield Units 1 – 3 during the months of Oand/or 3) emitting fewer tons than the Plant-Wide Annual Cap for NOx required for the Sammis Plant. Ohio Edison must reduce 24,600 tons system-wide of SO2 by 12/31/2010. No later than 8/11/2005, Ohio Edison shall install and operate low NOx burners on Sammis Units 1 - 7 and overfired air on Sammis Units 1,2,3,6, and 7. No later than 12/1/2005, Ohio Edison shall install advanced combustion control optimization NOx emissions from Sammis Units 1 – 5. 

Install Induct 50% removal Install SNCR 

Scrubber (or or 1.1 lb/MMBtu (or approved 

approved equiv. alt. tech) & 

control tech) operate 

Unit 1 12/31/2008

continuously 

0.25 10/31/2007

Install Induct 50% removal Operate 

Scrubber (or or 1.1 lb/MMBtu existing SNCR 

approved equiv. continuously 

Unit 2 

control tech) 

12/31/2008 0.25 2/15/2006 

Install Induct 50% removal 

Operate low NOx

burners and overfire 

air by 12/1/05; install 

SNCR 

12/1/2005 

Scrubber (or or 1.1 lb/MMBtu (or approved and 

approved equiv. alt. tech) & 10/31/2007

control tech) operate 

Unit 3 12/31/2008

continuously by 

12/31/07 

0.25 

Install Induct 50% removal Install SNCR 

W.H. 

Sammis 

Plant 

Ohio 

Unit 4 

Scrubber (or or 1.1 lb/MMBtu 

6/30/2009 

(or approved 

0.25 10/31/2007

Beginning on 

1/1/2006, Ohio 

Edison may use, sell 

or transfer any 

restricted SO2 only to 

satisfy the 

Operational Needs at 

the Sammis, Burger 

and Mansfield Plant, 

or new units within 

the FirstEnergy 

System that comply with a 96% removal 

for SO2. For 

calendar year 2006 

through 2017, Ohio 

Edison may 

accumulate SO2

allowances for use at 

the Sammis, Burger, 

and Mansfield plants, 

or FirstEnergy units 

equipped with SO2

Emission Control 

Standards. 

Beginning in 2018, 

Ohio Edison shall 

surrender unused 

restricted SO2

allowances. 
Appendix 3-3.7 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

approved equiv. alt. tech) & 

control tech) operate 

continuously 

Install Flash 50% removal Install SNCR 

Dryer Absorber or 1.1 lb/MMBtu (or approved 

or ECO2 (or alt. tech) & 

approved equiv. Operate 

control tech) & Continuously 

operate 

Unit 5 

continuously 

6/29/2009 0.29 3/31/2008 

Install FGD3 (or Install SNCR "Minimum Operate 

approved equiv. (or approved Extent Existing 

control tech) & alt. tech) & Practicable" ESP 

operate operate Continuously 

Unit 6 

continuously 

95% 

removal or 

0.13 

lb/MMBtu 

6/30/2011 

continuously 

6/30/2005 0.03 1/1/2010 

Install FGD (or Operate "Minimum Operate 

approved equiv. existing SNCR Extent Existing 

control tech) & Continuously Practicable" ESP 

operate Continuously 

Unit 7 

continuously 

95% 

removal or 

0.13 

lb/MMBtu 

6/30/2011 8/11/2005 0.03 1/1/2010 

Upgrade 

Unit 1 

existing FGD 

95% 12/31/2005

Upgrade 

Mansfield 

Plant 

Pennsylvani

a 

Unit 2 

existing FGD 

95% 12/31/2006
Appendix 3-3.8 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

Upgrade 

Unit 3 

existing FGD 

95% 10/31/2007

Install low NOx

"Minimize 

Emissions to 

the 

burners, over-fired Extent Eastlake Ohio Unit 5 

air and SNCR & 

operate continuously Practicable" 

12/31/2006

Unit 4 12/31/2011 

Burger Ohio 

Unit 5 

Repower 

with at least 

80% 

biomass 

fuel, up to 

20% low 

sulfur coal. 

12/31/2011 

MirantI1,6System-wide NOx Emission Annual Caps: 36,500 tons 2004; 33,840 tons 2005; 33,090 tons 2006; 28,920 tons 2007; 22,000 tons 2008; 19,650 tons 2009; 16,000 tons 2010 onward. System-wide NOx Emission Ozone Season Caps: 14,700 tons 12,590 tons 2006; 10,190 tons 2007; 6,150 tons 2008 – 2009; 5,200 tons 2010 thereafter. Beginning on 5/1/2008, and continuing for each and every Ozone Season thereafter, the Mirant System shall not exceed a System-wide Ozone Season Elb/MMBtu NOx. 

Unit 1 Unit 2 

Install low NOx

burners (or more Unit 3 effective tech) & 

operate continuously 

5/1/2004 

Install low NOx

burners (or more Unit 4 effective tech) & 

operate continuously 

5/1/2004 

Install low NOx

burners (or more 

effective tech) & 

Potomac 

River Plant Virginia 

Unit 5 

operate continuously 

5/1/2004 
Appendix 3-3.9 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

Install SCR 

(or approved 

alt. tech) & 

Unit 1 

operate continuously 

0.1 5/1/2007 

Install SCR 

(or approved 

alt. tech) & 

Morgantown 

Plant Maryland 

Unit 2 

operate continuously 

0.1 5/1/2008 

Unit 1 

Install and 

continuously 

operate FGD (or 

equiv. 

technology) 

95% 6/1/2010 

Chalk Point Maryland 

Unit 2 

Install and 

continuously 

operate FGD (or 

equiv. 

technology) 

95% 6/1/2010 

For each year after 

Mirant commences 

FGD operation at 

Chalk Point, Mirant 

shall surrender the 

number of SO2

Allowances equal to 

the amount by which 

the SO2 Allowances 

allocated to the Units 

at the Chalk Point 

Plant are greater than 

the total amount of 

SO2 emissions 

allowed under this 

Section XVIII. 

Illinois Power System-wide NOx Emission Annual Caps: 15,000 tons 2005; 14,000 tons 2006; 13,800 tons 2007 onward. System-wide SO2 Emission Annual Caps: 66,300 tons 2005 – 2006; 65,000 tons 2007; 62,000 tons 2008 – 2010; 57,000 tons 2011; 49,52013 onward. 

Units 1 & 

2 

Install wet or dry 

FGD (or 

approved equiv. 

alt. tech) & 

operate 

continuously 

0.1 12/31/2011

Operate OFA & 

existing SCR 

continuously 

0.1 8/11/2005 

Install & 

continuously 

operate Baghouse 

0.015 12/31/2010 

Baldwin Illinois 

Unit 3 

Install wet or dry 

FGD (or 

approved equiv. 

alt. tech) & 

operate 

continuously 

0.1 12/31/2011 Operate OFA and/or low NOx burners 0.12 until 12/30/12; 0.1 from 12/31/12 08/11/05 and 12/31/12 Install & continuously operate Baghouse 0.015 12/31/2010 

By year end 2008, 

Dynergy will 

surrender 12,000 

SO2 emission 

allowances, by year 

end 2009 it will 

surrender 18,000, by 

year end 2010 it will 

surrender 24,000, 

any by year end 2011 

and each year 

thereafter it will 

surrender 30,000 

allowances. If the 
Appendix 3-3.10 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

8/11/2005 

For 

Baghouse: 

12/31/12; 

and For ESP: Havana 12/31/05 Illinois Unit 6 

Install wet or dry 

FGD (or 

approved equiv. 

alt. tech) & 

operate 

continuously 

1.2 

lb/MMBtu 

until 

12/30/2012

; 0.1 

lb/MMBtu 

from 

12/31/2012 

onward 

12/31/2012

Operate OFA and/or 

low NOx burners & 

operate existing 

SCR continuously 

0.1 8/11/2005 

Install & 

continuously 

operate Baghouse, 

then install ESP or 

alt. PM equip 

For Baghouse: 

0.015 

lb/MMBt

u; For 

ESP: 

0.03 

lb/MMBt

u 

Operate OFA "Minimum 

and/or low NOx

burners Unit 1 1.2 7/27/2005 Extent 

Practicable" 

8/11/2005 

Install ESP (or 

equiv. alt. tech) & 

continuously 

operate ESPs 

0.03 12/31/2006 

Operate OFA "Minimum 

and/or low NOx

burners Extent 

Hennepin Illinois 

Unit 2 1.2 7/27/2005 

Practicable" 

8/11/2005 

Install ESP (or 

equiv. alt. tech) & 

continuously 

operate ESPs 

0.03 12/31/2006 

Operate OFA "Minimum 

and/or low NOx

burners Vermilion Illinois Extent Units 1 & 2 1.2 1/31/2007 

Practicable" 

8/11/2005 

Install ESP (or 

equiv. alt. tech) & 

continuously 

operate ESPs 

0.03 12/31/2010 

Operate OFA "Minimum 

and/or low NOx

burners Wood River Illinois Extent Units 4 & 5 1.2 7/27/2005 

Practicable" 

8/11/2005 

Install ESP (or 

equiv. alt. tech) & 

continuously 

operate ESPs 

0.03 12/31/2005 

surrendered 

allowances result in 

insufficient remaining 

allowances allocated 

to the units 

comprising the DMG 

system, DMG can 

request to surrender 

fewer SO2

allowances. 

Kentucky Utilities Company 

EW Brown 

Generating 

Station 

Kentucky Unit 3 Install FGD 97% or 0.100 12/31/2010

Install and 

continuously operate 

SCR by 12/31/2012, 

continuously operate 

low NOx boiler and 

OFA. 

0.07 12/31/2012 Continuously operate ESP 0.03 12/31/2010 

KU must surrender 

53,000 SO2

allowances of 2008 

or earlier vintage by 

March 1, 2009. All 

surplus NOx

allowances must be 

surrendered through 

2020. 

SO2 a

allowance

be us

complia

emis

decrea

purpo

complyin

Consent 

not earn 

Salt River Project Agricultural Improvement and Power District (SRP) 
Appendix 3-3.11 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

Unit 1 or 

Unit 2 

Immediately 

begin 

continuous 

operation of 

existing FGDs 

on both units, 

install new FGD.

95% or 

0.08 

New FGD 

installed by 

1/1/2012 

Install and 

continuously operate 

low NOx burner and 

SCR 

0.32 prior to 

SCR 

installation, 

0.080 after 

LNB by 

06/01/2009

, SCR by 

06/01/2014

Optimization 

begins 

immediately, 

rate limit 

begins 

01/01/12 

(date of new 

FGD 

installation) Coronado Generating 

Station 

Arizona 

Unit 1 or 

Unit 2 Install new FGD 95% or 0.08 1/1/2013 Install and continuously operate low NOx burner 0.32 6/1/2011 

Optimization and 

continuous 

operation of existing 

ESPs. 

0.03 Optimization 

begins 

immediately, 

rate limit 

begins 

01/01/13 

(date of new 

FGD 

installation) 

Beginning in 2012, all 

surplus SO2

allowances for both 

Coronado and 

Springerville Unit 4 

must be surrendered 

through 2020. The 

allowances limited by 

this condition may, 

however, be used for 

compliance at a 

prospective future 

plant using BACT 

and otherwise 

specified in par. 54 of 

the consent decree. 

SO2 a

allowance

be us

complia

emis

decrea

purpo

complyin

Consent 

not earn 

American Electric Power 

Annual Cap 

(tons) Year Annual Cap (tons) Year 

450,000 2010 96,000 2009 450,000 2011 92,500 2010 420,000 2012 92,500 2011 350,000 2013 85,000 2012 340,000 2014 85,000 2013 275,000 2015 85,000 2014 260,000 2016 75,000 2015 235,000 2017 72,000 2016 and thereafter 184,000 2018 

Eastern System-Wide 

174,000 2019 and thereafter 

NOx and SO2

allowances that 

would have been 

made available by 

emission reductions 

pursuant to the 

Consent Decree 

must be surrendered.

NOx a

allowance

be used 

with any o

impose

Consen

The C

Decree i

formu

calculatin

NOx allo

relative to 

Allocati

restricts 

some. Se

79 for 

Reducing 

below th

System

Annual 

Limitation

and SO

super co

allowa

Sporn West 

Virginia 1 – 4 

Clinch 

River Virginia 

1 – 3 

At least 

600MW from 

various units 

Indiana Tanners Creek 

Retire, 

retrofit, or 

re-power 

12/31/2018 
Appendix 3-3.12 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

1 – 3 

Kammer West 

Virginia 1 – 3 

Unit 1 

Install and 

continuously 

operate FGD 

12/31/2009

Install and 

continuously operate 

SCR 

1/1/2008 

Unit 2 

Install and 

continuously 

operate FGD 

12/31/2010

Install and 

continuously operate 

SCR 

Amos 1/1/2009 West Virginia 

Unit 3 

Install and 

continuously 

operate FGD 

12/31/2009

Install and 

continuously operate 

SCR 

1/1/2008 

Unit 1 

Burn only coal 

with no more 

than 1.75 

lb/MMBtu 

annual average

Date of 

entry 

Continuously 

operate low NOx

burners 

Date of 

entry 

Big Sandy Kentucky 

Unit 2 

Install and 

continuously 

operate FGD 

12/31/2015

Install and 

continuously operate 

SCR 

1/1/2009 

Unit 1 

Install and 

continuously 

operate FGD 

12/31/2008

Install and 

continuously operate 

SCR 

1/1/2009 Continuously operate ESP 0.03 12/31/2009 

Unit 2 

Install and 

continuously 

operate FGD 

12/31/2008

Install and 

continuously operate 

SCR 

1/1/2009 Continuously operate ESP Cardinal Ohio 0.03 12/31/2009 

Unit 3 

Install and 

continuously 

operate FGD 

12/31/2012

Install and 

continuously operate 

SCR 

1/1/2009 

Clinch River Virginia Units 1 – 3 

Plant-wide 

annual cap: 

 21,700 

tons from 

2010 to 

2014, then 

16,300 

after 

1/1/2015 

2010 – 

2014, 2015 

and 

thereafter 

Continuously 

operate low NOx

burners 

Date of 

entry 

Unit 1 

Retire, 

retrofit, or 

re-power 

Date of 

entry Conesville Ohio 

Unit 2 

Retire, 

retrofit, or 

re-power 

Date of 

entry 
Appendix 3-3.13 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

Unit 3 

Retire, 

retrofit, or 

re-power 

12/31/2012 

Unit 4 

Install and 

continuously 

operate FGD 

12/31/2010

Install and 

continuously operate 

SCR 

12/31/2010

Unit 5 Upgrade existing FGD 95% 12/31/2009 Continuously operate low NOx burners Date of entry Unit 6 Upgrade existing FGD 95% 12/31/2009 Continuously operate low NOx burners Date of entry Unit 1 

Install and 

continuously 

operate FGD 

Date of 

entry 

Install and 

continuously operate 

SCR 

1/1/2009 

Gavin Ohio 

Unit 2 

Install and 

continuously 

operate FGD 

Date of 

entry 

Install and 

continuously operate 

SCR 

1/1/2009 

Glen Lyn Virginia Units 5, 6 

Burn only coal 

with no more 

than 1.75 

lb/MMBtu 

annual average

Date of 

entry 

Continuously 

operate low NOx

burners 

Date of 

entry 

Kammer West Virginia Units 1 – 3 Plant-wide annual cap: 35,000 1/1/2010 Continuously operate over-fire air Date of entry 

Kanawha 

River 

West 

Virginia Units 1, 2 

Burn only coal 

with no more 

than 1.75 

lb/MMBtu 

annual average

Date of 

entry 

Continuously 

operate low NOx

burners 

Date of 

entry 

Unit 1 

Install and 

continuously 

operate FGD 

12/31/2007

Install and 

continuously operate 

SCR 

1/1/2009 

Mitchell West Virginia 

Unit 2 

Install and 

continuously 

operate FGD 

12/31/2007

Install and 

continuously operate 

SCR 

1/1/2009 

Mountaineer West Virginia Unit 1 Install and continuously operate FGD 12/31/2007 Install and continuously operate SCR 1/1/2008 

Muskingum 

River Ohio Units 1 – 4 Retire, retrofit, or 

re-power 

12/31/2015 
Appendix 3-3.14 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

Unit 5 

Install and 

continuously 

operate FGD 

12/31/2015

Install and 

continuously operate 

SCR 

1/1/2008 Continuously operate ESP 0.03 12/31/2002 

Picway Ohio Unit 9 

Continuously 

operate low NOx

burners 

Date of 

entry 

Unit 1 

Install and 

continuously 

operate FGD 

12/31/2017

Install and 

continuously operate 

SCR 

12/31/2017

Rockport Indiana 

Unit 2 

Install and 

continuously 

operate FGD 

12/31/2019

Install and 

continuously operate 

SCR 

12/31/2019

Sporn West Virginia Unit 5 Retire, retrofit, or re-power 12/31/2013 

Units 1 - 

3 

Burn only coal 

with no more 

than 1.2 

lb/MMBtu 

annual average

Date of 

entry 

Continuously 

operate low NOx

burners 

Date of 

entry 

Tanners 

Creek Indiana 

Unit 4 

Burn only coal 

with no more 

than 1.2% sulfur 

content annual 

average 

Date of 

entry 

Continuously 

operate over-fire air

Date of 

entry 

East Kentucky Power Cooperative Inc. By 12/31/2009, EKPC shall choose whether to: 1) install and continuously operate NOx controls at Cooper 2 by 12/31/2012 and SO2 controls by 6/30/2012 or 2) retire Dale 3 and Dale 4 by 12/31/2012. 

12-month 

rolling limit 

(tons) 

Start of 12-

month cycle

12-month 

rolling limit 

(tons) 

Start of 12-

month 

cycle 

57,000 10/1/2008 11,500 1/1/2008 40,000 7/1/2011 8,500 1/1/2013 

System-wide 

System-wide 12-

month rolling 

tonnage limits 

apply 

28,000 1/1/2013 

All units must 

operate low NOx

boilers 

8,000 1/1/2015 

PM control devices 

must be operated 

continuously 

system-wide, ESPs 

must be optimized 

within 270 days of 

entry date, or EKPC 

may choose to 

submit a PM 

Pollution Control 

Upgrade Analysis. 

0.03 1 year from entry date 

All surplus SO2

allowances must be 

surrendered each year, beginning in 

2008. 

SO2 a

allowance

be used 

with the 

Decre

allowan

would 

available 

of compl

the Conse

may not 

traded. 

NOx allo

allocated 

must be u

the EKPC 

Allowanc

availab

super co

may be 

trad
Appendix 3-3.15 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

Unit 1 

Install and 

continuously 

operate FGD 

95% or 0.1 6/30/2011 Continuously operate SCR 

0.12 for Unit 1 

until 

01/01/2013, at 

which point the 

unit limit drops 

to 0.1. Prior to 

01/01/2013, the 

combined 

average when 

both units are 

operating must 

be no more 

than 0.1 

60 days 

after entry 

Spurlock Kentucky 

Unit 2 

Install and 

continuously 

operate FGD by 

10/1/2008 

95% or 0.1 1/1/2009 

Continuously 

operate SCR and 

OFA 

0.1 for Unit 2, 

0.1 combined 

average when 

both units are 

operating 

60 days 

after entry 

Unit 1 

Install and 

continuously operate 

low NOx burners by 

10/31/2007 

0.46 1/1/2008 

Unit 2 

Install and 

continuously operate 

low NOx burners by 

10/31/2007 

0.46 1/1/2008 

EKPC must 

surrender 1,000 NOx

allowances 

immediately under 

the ARP, and 3,107 

under the NOx SIP 

Call. EKPC must 

also surrender 

15,311 SO2

allowances. 

Unit 3 

EKPC may 

choose to 

retire Dale 3 

and 4 in lieu 

of installing 

controls in 

Cooper 2 

12/31/2012 

Dale Plant Kentucky 

Unit 4 

Cooper Kentucky Unit 1 
Appendix 3-3.16 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

Unit 2 

If EKPC opts to 

install controls 

rather than 

retiring Dale, it 

must install and 

continuously 

operate FGD or 

equiv. 

technology 

95% or 

0.10 

If EKPC elects to 

install controls, it 

must continuously 

operate SCR or 

install equiv. 

technology 

0.08 (or 90% if 

non-SCR 

technology is 

used) 

12/31/2012

Nevada Power Company Beginning 1/1/2010, combined NOx emissions from Units 5, 6, 7, and 8 must be no more than 360 tons per year. 

Unit 5 5ppm 1-hour 

average 

12/31/08 

(ULNB 

installation)

, 01/30/09 

(1-hour 

average) 

Unit 6 5ppm 1-hour 

average 

12/31/09 

(ULNB 

installation)

, 01/30/10 

(1-hour 

average) 

Unit 7 5ppm 1-hour 

average 

12/31/09 

(ULNB 

installation)

, 01/30/10 

(1-hour 

average) 

Clark 

Generating 

Station 

Nevada 

Unit 8 

Units may only fire 

natural gas 

Increase water 

injection 

immediately, then 

install and operate 

ultra-low NOx

burners (ULNBs) or 

equivalent 

technology. In 2009, 

Units 5 and 8 may 

not emit more than 

180 tons combined 

5ppm 1-hour 

average 

12/31/08 

(ULNB 

installation)

, 01/30/09 

(1-hour 

average) 

Allowance

be used 

with the 

Decree

allowanc

availab

complianc

Consen

may be 

so

Dayton Power & Light Non-EPA Settlement of 10/23/2008 

Owners may not 

purchase any new 

catalyst with SO2 to 

SO3 conversion rate 

greater than 0.5% 

0.17 stationwide 30 days after entry Stuart Generating Station Ohio Station- wide Complete installation of 

FGDs on each 

unit. 

96% or 

0.10 7/31/2009 

0.17 stationwide 60 days after entry date 

0.030 lb 

per unit 7/31/2009 

NOx a

allowance

be used 

with the 

rates sp

the C

Dec
Appendix 3-3.17 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

82% 

including 

data from 

periods of 

malfunction

s 

7/31/09 

through 

7/30/11 

Install control 

technology on one 

unit 

0.10 on any 

single unit 12/31/2012

0.15 stationwide 7/1/2012 82% including 

data from 

periods of 

malfunction

s 

after 

7/31/11 0.10 stationwide 12/31/2014

Install 

rigid-type 

electrodes in 

each 

unit's 

ESP 

12/31/2015 

PSEG FOSSIL, Amended Consent Decree of November 2006 

Unit 7 Retire unit 1/1/2007 

Kearny New Jersey 

Unit 8 Retire unit 1/1/2007 

Allowances allocated 

to Kearny, Hudson, 

and Mercer may only 

be used for the 

operational needs of 

those units, and all 

surplus allowances 

must be surrendered. 

 Within 90 days of 

amended Consent 

Decree, PSEG must 

surrender 1,230 NOx

Allowances and 

8,568 SO2

Allowances not 

already allocated to 

or generated by the 

units listed here. 

Kearny allowances 

must be surrendered 

with the shutdown of 

those units. 

0.15 12/31/2010 0.1 12/31/2010

Annual Cap 

(tons) Year Annual Cap (tons) Year 

5,547 2007 3,486 2007 5,270 2008 3,486 2008 5,270 2009 3,486 2009 

Hudson New Jersey Unit 2 

Install Dry FGD 

(or approved alt. 

technology) and 

continually 

operate 

5,270 2010 

Install SCR (or 

approved tech) and 

continually operate 

3,486 2010 

Install Baghouse (or 

approved 

technology) 

0.015 12/31/2010 
Appendix 3-3.18 

Settlement Actions 

Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement Allo

Company 

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement Restr

Mercer New Jersey Units 1 & 2 

Install Dry FGD 

(or approved alt. 

technology) and 

continually 

operate 

0.15 12/31/2010

Install SCR (or 

approved tech) and 

continually operate 

0.1 1/1/2007 

Install Baghouse (or 

approved 

technology) 

0.015 12/31/2010 

Westar Energy 

Units 1, 2, and 3 have a total annual limit of 

6,600 tons of SO2 starting 2011 

Units 1-3 must continuously operate Low NOx

Combustion Systems by 2012 and achieve and 

maintain a 30-Day Rolling Average Unit Emission 

Rate for NOx of no greater than 0.180 lb/MMBtu. 

Units 1, 2, and 3 must operate each ESP and 

FGD system continuously by 2011 and 

maintain a 0.030 lb/MMBtu PM Emissions 

Rate. 

Units 1, 2, and 3 must all install FGDs by 

2011 and operate them continuously. 

One of the three units must install an SCR by 2015 

and operate it continuously to maintain a 30-Day 

Rolling Average Unit Emission Rate for NOx of no 

greater than 0.080 lb/MMBtu. 

Units 1 and 2’s ESPs must be rebuilt by 2014 

in order to meet a 0.030 lb/MMBtu PM 

Emissions Rate 

Jeffrey 

Energy 

Center 

Kansas All units 

FGDs must maintain a 30-Day Rolling 

Average Unit Removal Efficiency for SO2 of 

at least 97% or a 30-Day Rolling Average 

Unit Emission Rate for SO2 of no greater 

than 0.070 lb/MMBtu. 

By 2013 Westar shall elect to either (a) install a 

second SCR on one of the other JEC Units by 

2017 or (b) meet a 0.100 lb/MMBtu Plant-Wide 12-

Month Rolling Average Emission Rate for NOx by 

2015 

Duke Energy 

Units 1 & 

3 

Retire or 

repower as natural gas 

1/1/2012 

Gallagher Indiana 

Units 2 & 

4 

Install Dry 

sorbent injection 

technology 

80% 1/1/2012 

Notes:1) This summary table describes New Source Review settlement actions as they are represented in EPA Base Case v.4.10. The settlement actions are simplified for representation in the model. This table is not intended to be a comprehensive settlement agreements. 2) Settlement actions for which the required emission limits will be effective by the time of the first mapped run year (before 1/1/2012) are built into the database of units used in EPA Base Case v.4.10 ("hardwired"). However, future actions are gemission rates in EPA Base Case v.4.10, allowing the modeled economic situation to dictate whether and when a unit would opt to install controls versus retire. 3) Some control installations that are required by these NSR settlements have already been taken by the affected companies, even if deadlines specified in their settlement haven't occurred yet. Any controls that are already in place are built into 4) If a settlement agreement requires installation of PM controls, then the controls are shown in this table and reflected in EPA Base Case v.4.10. If settlement requires optimization or upgrade of existing PM controls, those actions are not includ5) For units for which an FGD is modeled as an emissions constraint in EPA Base Case v.4.10, EPA used the assumptions on removal efficiencies that are shown in Table 5-4 of this documentation report. 6) For units for which an FGD is hardwired in EPA Base Case v.4.10, unless the type of FGD is specified in the settlement, EPA modeling assumes the most cost effective FGD (wet or dry) and a corresponding 98% removal efficiency for wet an7) For units for which an SCR is modeled as an emissions constraint or is hardwired in EPA Base Case v.4.10, EPA assumed an emissions rate equal to 10% of the unit's uncontrolled rate, with a floor of .06 lb/MMBtu or used the emission limit if 8) The applicable low NOx burner reduction efficiencies are shown in Table A 3-1:3 in the Base Case v.4.10 documentation materials. 9) EPA included in EPA Base Case v.4.10 the requirements of the settlements as they existed at the second quarter of 2010. 10) Some of the NSR settlements require the retirement of SO2 allowances. For EPA Base Case v.4.10, EPA estimates the amount of allowances to be retired from these settlements and adjusted the total Title IV allowances accordingly. 
Appendix 3-4.1 

Appendix 3-4 State Settlements in EPA Base Case v.4.10 

State Enforcement Actions 

Company and Retire/Repower SO2 control NOx Control PM Control 

Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date 

AES 

Unit 4 Install FGD 90% 9/1/2007 Install SCR 0.15 9/1/2007 

Greenidge New York 

Unit 3 Install BACT 12/31/2009 Install BACT 12/31/2009 Unit 8 90% 12/31/2010 Install SCR 0.15 12/31/2010 

Westover New York 

Unit 7 Install BACT 12/31/2009 Install BACT 12/31/2009 

Hickling New York Units 1 & 2 Install BACT 5/1/2007 Install BACT 5/1/2007 

Jennison New York Units 1 & 2 Install BACT 5/1/2007 Install BACT 5/1/2007 

Niagara Mohawk Power NRG shall comply with the below annual tonnage limitations for its Huntley and Dunkirk Stations: 2005 is 59,537 tons of SO2 and 10,777 tons of NOx, 2006 is 34,230 of SO2 and 6,772 of NOx, 2007 is 3022,733 tons of SO2

Huntley New York Units 63 – 66 Retire Before 2008 

Public Service Co. of NM 

Unit 1 10/31/2008 10/31/2008 12/31/2009 Unit 2 3/31/2009 3/31/2009 12/31/2009 Unit 3 4/30/2008 4/30/2008 4/30/2008 

San Juan New Mexico 

Unit 4 

State-of-the-art 

technology 90% 

10/31/2007

State-of-the-art 

technology 0.3 

10/31/2007 

Operate 

Baghouse and 

demister 

technology 

0.02 

10/31/2007

ca

t

Public Service Co of Colorado 

Units 1 & 

2 

Install and 

operate FGD 

0.1 

lb/MMBtu 

combined 

average 

7/1/2009 Install low-NOx emission controls

0.15 

lb/MMBtu 

combined 

average 

7/1/2009 

I

0.1 Comanche Colorado 

Unit 3 Install and operate FGD lb/MMBtu Install and operate SCR 0.08 

Install and 

operate a 

fabric filter 

dust collection 

system 

0.01 

I
Appendix 3-4.2 

State Enforcement Actions 

Company and Retire/Repower SO2 control NOx Control PM Control 

Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date 

TVA 

Bull Run Tennessee Unit 1 Complete FGD installation 0.15 lb/MMBtu, 4,431 TPY 

FGD 

already 

active as of 

date of 

entry 

0.08 

lb/MMBtu, 

2,295 TPY

Unit 1 

0.15 

lb/MMBtu, 

1,023 TPY 

0.05 

lb/MMBtu, 

372 TPY 

Unit 2 

0.15 

lb/MMBtu, 

1,028 TPY 

0.05 

lb/MMBtu, 

374 TPY 

Unit 3 

0.15 

lb/MMBtu, 

1,081 TPY 

0.05 

lb/MMBtu, 

389 TPY 

John Sevier Tennessee 

Unit 4 

Install FGD 

0.15 

lb/MMBtu, 

1,000 TPY 

27 months 

from date 

of entry 

Install SCR 

0.05 

lb/MMBtu, 

360 TPY 

21 months 

from date of 

entry 

Unit 1 

0.15 

lb/MMBtu, 

794 TPY 

0.06 

lb/MMBtu, 

323 TPY 

Unit 2 

0.15 

lb/MMBtu, 

785 TPY 

0.06 

lb/MMBtu, 

320 TPY 

Unit 3 

0.15 

lb/MMBtu, 

822 TPY 

0.06 

lb/MMBtu, 

335 TPY 

Unit 4 

0.15 

lb/MMBtu, 

800 TPY 

0.06 

lb/MMBtu, 

326 TPY 

Unit 5 

0.15 

lb/MMBtu, 

1,021 TPY 

0.06 

lb/MMBtu, 

416 TPY 

Unit 6 

0.15 

lb/MMBtu, 

1,095 TPY 

0.05 

lb/MMBtu, 

365 TPY 

Unit 7 

0.15 

lb/MMBtu, 

1,040 TPY 

0.05 

lb/MMBtu, 

347 TPY 

Unit 8 

0.15 

lb/MMBtu, 

1,048 TPY 

0.05 

lb/MMBtu, 

349 TPY 

Kingston Tennessee 

Unit 9 

Install FGD 

0.15 

lb/MMBtu, 

1,012 TPY 

27 months 

from date 

of entry 

Operate existing 

SCR 

0.05 

lb/MMBtu, 

337 TPY 
Appendix 3-4.3 

State Enforcement Actions 

Company and Retire/Repower SO2 control NOx Control PM Control 

Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date 

Unit 1 

0.15 

lb/MMBtu, 

569 TPY 

0.06 

lb/MMBtu, 

246 TPY 

Unit 2 

0.15 

lb/MMBtu, 

608 TPY 

0.06 

lb/MMBtu, 

263 TPY 

Unit 3 

0.15 

lb/MMBtu, 

663 TPY 

0.06 

lb/MMBtu, 

287 TPY 

Unit 4 

0.15 

lb/MMBtu, 

602 TPY 

0.06 

lb/MMBtu, 

261 TPY 

Unit 5 

0.15 

lb/MMBtu, 

640 TPY 

0.06 

lb/MMBtu, 

277 TPY 

Unit 6 

Install FGD 

0.15 

lb/MMBtu, 

626 TPY 

27 months 

from date 

of entry 

Install SCR 

0.06 

lb/MMBtu, 

271 TPY 

21 months 

from date of 

entry 

Unit 7 

0.56 

lb/MMBtu, 

8950 TPY 

0.06 

lb/MMBtu, 

892 TPY 

Widows Creek Alabama 

Unit 8 

0.30 

lb/MMBtu, 

4,508 TPY 

0.06 

lb/MMBtu, 

860 TPY 

Rochester Gas & Electric 

Russell Plant New York Units 1 – 4 Retire all units 

Mirant New York 

Unit 1 Retire 5/7/2007 

Lovett Plant New York 

Unit 2 Retire 4/30/2008 
Appendix 3-5.1 

Appendix 3-5 Citizen Settlements in EPA Base Case v.4.10 

Citizen Suits Provided by DOJ 

Company Retire/Repower SO2 control NOx Control P

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment 

SWEPCO (AEP) 

Welsh Texas Units 1- 3 Install and operate CEMs 

Allegheny Energy 

Hatfield's 

Ferry Pennsylvania Units 1 - 3 Install and operate wet FGD 6/30/2010 

Install and 

operate sulfur 

trioxide injection 

systems, improve 

ESP 

performance 

2

(f

p

te

Wisconsin Public Service Corp 

Pulliam Wisconsin Units 3 & 4 Retire 12/31/2007

University of Wisconsin 

Charter 

Street 

Heating 

Plant 

Wisconsin 

Repower to 

burn 100% 

biomass 

12/31/2012
Appendix 3-5.2 

Citizen Suits Provided by DOJ 

Company Retire/Repower SO2 control NOx Control P

and Plant State Unit 

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment 

Tucson Electric Power 

Units 1 

& 2 

0.27 

lb/MMBtu 12/31/2006 0.22 lb/MMBtu 12/31/2006 

Unit 3 

Springerville 

Plant Arizona 

Future 

Unit 4 

Dry FGD, 

85% 

reduction 

required 

Four-unit 

cap of 

10,662 

tons per 

year once 

units 3 and 

4 are 

operational

SCR, LNB 

Four-unit 

cap of 

8,940 tons 

per year 

once units 

3 and 4 are 

operational

Baghouse 
Appendix 3-6.1 

Appendix 3-6 Renewable Portfolio Standards in EPA Base Case v.4.10 

NEMS 

Region IPM Regions Covered Units 2012 2015 2020 2030 2035 - 2050 

CNV CA-N and CA-S % 15.7% 17.3% 20.0% 20.0% 20.0%

ECAR MECS, RFCO, RFCP, and 

TVAK % 0.8% 3.0% 4.5% 5.7% 5.7% 

ERCOT ERCT % 3.9% 5.0% 5.0% 5.0% 5.0% 

MAAC MACE, MACS, and MACW % 7.4% 10.1% 14.8% 15.4% 15.4%

MAIN COMD, GWAY, and WUMS % 5.6% 8.9% 13.2% 17.5% 17.5%

MAPP MRO % 3.7% 4.6% 6.1% 7.2% 7.2% 

NE NENG % 7.4% 9.6% 13.4% 13.8% 13.8%

NWP NWPE and PNW % 4.6% 7.3% 12.4% 13.7% 13.7%

NY DSNY, LILC, NYC, and 

UPNY GWh 4,838 5,233 5,097 5,236 5,369 

RA AZNM, RMPA, and SNV % 3.0% 4.2% 6.0% 6.9% 6.9% 

SPP SPPN and SPPS % 1.9% 1.9% 3.8% 3.8% 3.8% 

STV ENTG, SOU, TVA, VACA, 

and VAPW % 0.5% 0.9% 1.7% 1.9% 1.9% 

Notes:

The Renewable Portfolio Standard percentages are applied to modeled electricity sale 

projections. 

The actual renewable portfolio standard targets in GWh are implemented exactly as shown in 

the model. 
Appendix 3-7.1 

Appendix 3-7 Capacity Deployment Limits for Advanced Coal with CCS and 

New Nuclear in EPA Base Case v.4.10 

Run 

Year 

Advanced 

Coal with 

CCS (MW) 

New 

Nuclear 

(MW) 

2012 0 0 

2015 2,000 0 

2020 9,750 7,500 

2030 38,220 29,400 

2040 112,367 86,436 

2050 293,652 225,886 

Note:

The 2020 through 2050 limits for Advanced Coal with 

CCS and New Nuclear technologies are a joint 

constraint, with the maximum amount of possible 

development for each technology shown by run year. If 

the maximum amount of one technology is developed 

in a given run year, zero MW of the other may be 

developed. See the production possibility chart below. 

Production Possibility Curves

(Incremental Capacity in MW by Run Year)

2020

2030

2040

2050

0

50,000

100,000

150,000

200,000

250,000

0 50,000 100,000 150,000 200,000 250,000 300,000

Advanced Coal with CCS

New Nuclear
Appendix 3-8.1 

Appendix 3-8 Nuclear Capacity Deployment Constraint in EPA Base Case v.4.1

Run 

Year 

Base New 

Nuclear 

Capacity 

Base New Nuclear 

Capacity Deployment 

Equation 

Possible Additional New Nuclear 

Capacity Deployment Equation1 Maximum Annual Incremental N

Deployment Allowed 

2020 7,500 7,500 0 7,500 2030 14,700 1.96 * 2020_Base_Capacity + 1.96 * 2020_Incremental_Capacity = 1.96 * (2020_Base_Capacity + 2022040 28,812 1.96 * 2030_Base_Capacity + 1.96 * 2030_Incremental_Capacity = 1.96 * (2030_Base_Capacity + 2032050 56,472 1.96 * 2040_Base_Capacity + 1.96 * 2040_Incremental_Capacity = 1.96 * (2040_Base_Capacity + 204

Maximum Possible New Nuclear Capacity Deployment Allowed 

Deployment Starts 2020 Deployment Starts 2030 Deployment Starts 2040 Deploy

Run Year 

Incremental Cumulative Incremental Cumulative Incremental Cumulative Incrementa

2020 7,500 7,500 0 0 0 0 0 2030 29,400 36,900 14,700 14,700 0 0 0 2040 86,436 123,336 57,624 72,324 28,812 28,812 0 2050 225,886 349,222 169,415 241,739 112,943 141,755 56,472 

Notes:No nuclear deployment is allowed before 2020 1Addtional new nuclear capacity deployment is only possible if nuclear capacity has been built in the previous run year. 
Appendix 3-8.2 

Maximum Possible Cumulative New Nuclear Capacity Each Run Year

0 50,000 100,000 150,000 200,000 250,000 300,000 

2020203020402050

Run Years

Capacity (MW)

Deployment Starts 2020 Deployment Starts 2030 Deployment Starts 2040 Deployment Starts 2050
Appendix 3-9.1 

Appendix 3-9 Complete Availability Assumptions in EPA Base Case v.4.10 

This is a small exerpt of the data in Appendix 3-9. The complete data set in spreadsheet format 

can be downloaded via the link found at 

www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html 

Please see Table 3-7 for summary data

Unit ID Plant Name Plant Type Winter 

Availability 

Summer 

Availability 

Annual 

Availability 

55522_G_CT1 Sundance Combustion 

Turbine 89.2 90.8 89.9 

55522_G_CT10 Sundance Combustion 

Turbine 89.2 90.8 89.9 

55522_G_CT2 Sundance Combustion 

Turbine 89.2 90.8 89.9 

55522_G_CT3 Sundance Combustion 

Turbine 89.2 90.8 89.9 

55522_G_CT4 Sundance Combustion 

Turbine 89.2 90.8 89.9 

55522_G_CT5 Sundance Combustion 

Turbine 89.2 90.8 89.9 

55522_G_CT6 Sundance Combustion 

Turbine 89.2 90.8 89.9 

55522_G_CT7 Sundance Combustion 

Turbine 89.2 90.8 89.9 

55522_G_CT8 Sundance Combustion 

Turbine 89.2 90.8 89.9 

55522_G_CT9 Sundance Combustion 

Turbine 89.2 90.8 89.9 

55257_G_1 Ina Road Water Pollution 

Control Fac 

Combustion 

Turbine 88.4 90.4 89.2 

55257_G_2 Ina Road Water Pollution 

Control Fac 

Combustion 

Turbine 88.4 90.4 89.2 

55257_G_3 Ina Road Water Pollution 

Control Fac 

Combustion 

Turbine 88.4 90.4 89.2 

55257_G_4 Ina Road Water Pollution 

Control Fac 

Combustion 

Turbine 88.4 90.4 89.2 

55257_G_5 Ina Road Water Pollution 

Control Fac 

Combustion 

Turbine 88.4 90.4 89.2 

55257_G_6 Ina Road Water Pollution 

Control Fac 

Combustion 

Turbine 88.4 90.4 89.2 

55257_G_7 Ina Road Water Pollution 

Control Fac 

Combustion 

Turbine 88.4 90.4 89.2 

82755_C_1 AZNM_AZ_Combustion 

Turbine 

Combustion 

Turbine 89.8 92.2 90.8 

6088_G_5 North Loop Combustion 

Turbine 89.2 90.8 89.9 

118_G_GE1 Saguaro Combustion 

Turbine 89.8 92.2 90.8 

124_G_GT2 Demoss Petrie Combustion 

Turbine 89.8 92.2 90.8 

82757_C_1 AZNM_CA_Combustion 

Turbine 

Combustion 

Turbine 89.8 92.2 90.8 

2468_G_6 Raton Combustion 

Turbine 88.4 90.4 89.2 

82759_C_1 AZNM_NM_Combustion 

Turbine 

Combustion 

Turbine 89.8 92.2 90.8 

54814_G_GENA Milagro Cogeneration Plant Combustion 

Turbine 89.2 90.8 89.9