# 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 net work even though politically they constitute a single province 4 

# ) 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 reflec t 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 dis aggregated 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 stri ctly 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 2010 5



# .

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

For purposes of documentation, Table 3-2 present s 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 contro l 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 E nergy for Load" for the NEMS Electric Market Module regions as reported in the "Electric Po wer Projections for Electricity Market Module Regions -- Electricity and Renew able 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

MECS Michigan Electric Coordination System ECAR

RFCP Reliability First Corporation - PJM

MACE Legacy Mid-Atlantic Area Council - East

MACS Legacy Mid-Atlantic Area Council - South MAAC

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

MexicoWECCAZ-NMSNV RA

SNV Western Electricity Coordinating Council - Southern Nevada

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

California

ISO CNV CA-S Western Electricity Coordinating Council - California South

PNW Western Electricity Coordinating Council - Pacific NorthwestWECCNWPP 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 specif ied for purposes of comparative analysis. The default base case assumption is that the electric ity demand shown in Table 3-2 is not affected by price and must be met, i.e., the price elasticity of demand is zero 6



# .

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-Co incidental Net Internal Demand”) illustrates the national sum of each region’s winter and summer peak demand. Because each region’s seasonalpeak 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 projec tions of demand from economy-wide computable general equilibrium (CGE) models which themselv es 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 3-4 8 

# 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 constr aints. Firm TTCs, also called Capacity TTCs, specify the maximum power that can be transferr ed 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 repres entative 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 l ong-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
-- NWPE 150 100 2.9 CA-N

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
-- RFCP 2,500 750
-- MACS

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

RFCO 2,776 1,904
-- MECS

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
-- MRO 310 310 2.9 RMPA

NWPE 735 735
-- AZNM 4,785 4,785
-- CA-S 4,688 4,688 2.9 SNV

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
-- RFCP 5,460 1,952
-- VAPW

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 ava ilable, 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 bet ween 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

RFCP to MACS ECAR to MAAC

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

MACW to RFCO MAAC to ECAR

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

GWAY to MRO MAIN to MAPP

WUMS to MRO 962

MRO to COMD

MRO to GWAY MAPP to MAIN

MRO to WUMS 1,238

MRO to NWPE MAPP to WECC MRO to RMPA 710

NENG to DSNY

NENG to UPNY NENG to NY

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

LILC to NENG NY 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 trans ferring 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 transmissi on between model regions that are within the same market region, such as transmission bet ween 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 electr icity. 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 i nput into IPM, the dispatch of those units is an endogenous decision that the model makes. T he capacity of existing generating units included in EPA Base Case v.4.10 can be found in the National Electrical Energy Data System (NEEDSv.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 di spatch 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 variati ons 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 constr ained by resource limitations. These technologies include hydro, wind and solar. For such technol ogies, 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 ma ximum possible power generated by the unit. For example, a photovoltaic solar unit would have a capac ity factor of 27% if the usable sunlight were only available that percent of the time. For su ch 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 profile s 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 informati on purposes only. It is not directly used in modeling.

Capacity factors are also used to define t he 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, whic h 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 c apacity 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 le ss than 25% of the unit capacity in the five baseand mid-load segments of the LDC in order to dis patch 100% of the unit capacity in the peak load segment of the LDC. These turndown constrai nts 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) require ment. 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 r egion 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 ex pected 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 conv entional 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



# YearCapacity (GW) Retired in Year



# 0 20 40 60 80 100 120Total 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 initia l 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 60 9



# . 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 pas t 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 requirement s which could result in expensive upgrades at nuclear power plants and figure into life ext ension 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 existi ng 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 operati on of existing nuclear facilities, and no particular

technical issues have been identified t hat 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 e xcellent 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 St ation 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 ju st beginning to enter their first period of license renewal, it probably will be at least 5 to 10 years befor e there is any clear indication as to whether plant operators will be likely to seek further extensi ons of their plants’ operating lives.” The EIA

review also observes “. . . the NRC and the nucl ear power industry are preparing applications for license renewals that would allow continued operat ion 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. D epartment 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

.
10 

# Supreme 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.

11 

# EIA, op.cit.

12 

# EIA, ibid.

# 3-17 

# 3.8 Heat Rates

Heat rates, expressed in BTUs per KWh. are a me tric 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 refl ects 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, com bustion 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 SO 2 

# , NO

x 

# , mercury, and CO 2 

# emissions regulations that are represented in the EPA Base Case v.4.10. The first three subsections discuss national and regional regulati ons. 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 SO 2 

# and NO

x 

# 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 SO 2 

# Regulations

Unit-level Regulatory SO 2 

# Emission Rates and Coal Assignments: Before discussing the national and regional regulations affecting SO 2 

# , it is important to note that unit-level SO 2 

# 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 SO 2

# 3-18 emission rates.” Since SO 2 

# emissions are dependent on the sulfur content of the fuel used, the regulatory SO 2 

# emission rates are used in IPM to define fuel capabilities.

For instance, a unit with a regulatory SO 2 

# emission rate of 3.0 lbs/MMBtu would be provided only

with those combinations of fuel choices and SO 2 

# 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 SO 2 

# 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 SO 2 

# scrubber options for coal units. Further discussion of fuel types and sulfur content is contained in Chapter 9. Further discussion of SO 2 

# control technologies is contained in Chapter 5.

National and Regional SO 2 

# Regulations: The national program affecting SO 2 

# emissions in EPA

Base Case v.4.10 is the SO 2 

# allowance trading program established under Title IV of the Clean Air Act Amendments (CAAA) of 1990, which set a goal of reducing annual SO 2 

# emissions by 10 million tons below 1980 levels. The program, which became fully operational in year 2000,

affects all SO 2 

# emitting electric generating units greater than 25 MWs. The program provides trading and banking of allowances over time acro ss all affected electric generation sources.

The annual SO 2 

# 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 thr ough 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 SO 2 

# cap of 8.95 million tons. The surrenders totaled 270.6 thousand tons in allowances, leaving 8.679 million of 2012 allowances remaini ng. Table 7-4 shows the initial bank and 2012 allowance specification along with the SO 2 

# 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 involv ing Arizona, New Mexico, Oregon, Utah, Wyoming directed toward addressing visibility issues in the Grand Canyon and affecting SO 2 

# emissions starting in 2018. The WRAP specifications for SO 2 

# are presented in Table 7-4.

3.9.2 NO

x 

# Regulations

Much like SO 2 

# regulations, existing NO

x 

# regulations are represented in EPA Base Case v.4.10 through a combination of system level NO

x 

# programs and generation unit-level NO

x 

# limits.

The system level NO

x 

# regulation represented in EPA Base Case v.4.10 is the NO

x 

# SIP Call trading program. This trading program affects all fossil units in 20 northeastern states 13 

# and the District of Columbia. The program is only in effect during the ozone season (May - September). The program includes state-specific NO

x 

# budgets. However, since the program allows for trading among units in different states, the total annual NO X 

# 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.

13 

# The states included in the SIP Call program are Alabama, Connecticut, Delaware, Illinois, Indiana, Kentucky, Maryland, Massachusetts, Mich igan, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Rhode Island, S outh Carolina, Tennessee, Virginia, and West Virginia.

# 3-19 The representation of unit-level NO

x 

# limits includes Title IV unit specific rate limits and Clean Air Act Reasonable Available Control Technology (RACT) requirements for controlling NO

x 

# emissions from electric generating units in ozone non-attainment areas or in the Ozone Transport Region 14



# (OTR). Both of these limits are captured in the specific NO

x 

# emission rates assigned to each unit represented in the base case. Unlike SO 2 

# emission rates, NO

x 

# 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 NO

x 

# emission rate of a unit can only change if the unit is retrofitted with

NO

x 

# pollution control equipment.

NO

x 

# Rates in NEEDS, v.4.10 Database: The NO

x 

# rates in the current base case were derived, wherever possible, directly from actual monitored NO

x 

# emission rate data reported to EPA under

the Acid Rain and NO

x 

# Budget Program in 2007. The emission rates themselves reflect the impact of the applicable NO

x 

# regulations. For coal-fired units, NO X 

# rates were used in combination with detailed engineering assessments of NO X 

# combustion control performance to prepare a set of four possible starting NO

x 

# rates to assign to a unit depending on the specific policy affecting that

unit in a model run.

The reason for having four NO

x 

# rates in NEEDS is to allow all possible modeling scenarios involving NO

x 

# controls to be set up. The four NO

x 

# rates are designated as Mode 1–4, and are designed to include all the NO

x 

# rates possible for a unit with its current configuration of NO

x 

# combustion and post-combustion controls. The four NO

x 

# rates are:

• Mode 1: Applies to units not covered by a NO X 

# control policy. Specifically, this is the NO X 

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

their uncontrolled NO X 

# 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 NO X 

# rate for units affected by a seasonal NO X 

# policy. For units with post-combustion controls, this is the NO X 

# rate with post-combustion controls shut off. For units without post-combustion controls, it’s the NO X 

# 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: NO X 

# rate applicable under a NO X 

# policy. For SCR units, it’s the NO X 

# rate with the SCR operating. For SNCR units, it’s the NO X 

# rate with SNCR operating plus state-of-the-artcombustion controls operating if required to attain rate limits. For units without postcombustion controls, it’s the NO X 

# 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 NO X 

# rates is selected:

• A unit covered under an annual NO X 

# emission limit is assigned the Mode 4 NO X 

# rate (winter and summer seasons).

• A unit covered by a summer season NO X 

# emission limit, but not an annual NO X 

# limit, is assigned the Mode 4 NO X 

# rate in the summer season but the Mode 3 NO X 

# rate in the winter

season.

• A unit covered by a mercury emission limit and not by a NO X 

# emission limit is assigned the

Mode 2 NO X 

# 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 SO 2 

# 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, P ennsylvania, Delaware, Maryland, District of Columbia, and northern Virginia.

# 3-20 of mercury. See Chapter 5 in the v.4.10 doc umentation for a discussion of the calculation mercury emission modification factors (EMF).)

• A unit not covered by either an annual or a summer NO X 

# limit nor mercury control requirements is assigned the Mode 1 NO X 

# rate in both winter and summer seasons.

The Mode 1-4 NO

x 

# rates for each generating unit are included in the NEEDS, v.4.10 database, described in Chapter 4. Appendix 3-1 and accom panying Tables 3-1.1, 3-1.2, and 3-1.3 give further information on the procedures employed to derive the four NO X 

# rate modes and give specific examples of generating units that fit each of the Mode 1-4 specifications.

Additional NO X 

# rate assumptions include default NO X 

# rates of 0.25 lbs/MMBtu for existing biomass units and 0.09 lbs/MMBtu for existing landfill gas units.

3.9.3 CO 2 

# Regulations and Renewable Portfolio Standards

The Regional Greenhouse Gas Initiative (RGGI) is a year-round CO 2 

# 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, R hode 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 spec ified 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 2010 15 

# as shown in Appendix 3-6. This appendix shows t he 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 provis ions 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 refe r to legal agreements with companies resultingfrom the permitting process under the CAAA which requires industry to undergo an EPA preconstruction review of proposed environmental contro ls 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 emi ssions 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 uni ts are modeled as additional capacity and generation that may come on line in each model region. Across all model regions the emission and removal

15 

# Energy 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 sa me. 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 constraint s 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 t he 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 t he skilled engineering and construction labor force, replacement challenges caused by an agi ng 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 particu lar 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 capacit y in later periods when there has been little or no build up in preceding periods by tying the am ount 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 deploym ent 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.3-23Table 3-11 Emission and Removal Rate Assumptions for Potential (New) Units in EPA Base Case v.4.10GasControls,Removal,andEmissionsRatesSupercriticalPulverizedCoal - WetScrubberSupercriticalPulverizedCoal - DryScrubberIntegratedGasificationCombinedCycleAdvancedCoal withCarbonCaptureAdvancedCombinedCycleAdvancedCombustion TurbineBiomassConventionalDirect-FiredBoilerBiomassGasificationCombinedCycleGeothermalLandfillGasSO2Removal /EmissionsRate98% with afloor of 0.06lbs/MMBtu93% with afloor of 0.065lbs/MMBtu99% 99% None None0.08lbs/MMBtu0.08lbs/MMBtuNone NoneNOxEmissionRate0.06lbs/MMBtu0.06lbs/MMBtu0.013lbs/MMBtu0.013lbs/MMBtu0.011lbs/MMBtu0.011lbs/MMBtu0.36lbs/MMBtu0.102lbs/MMBtuNone0.09lbs/MMBtuHgRemoval /EmissionsRate90% 90% 90% 90%NaturalGas:0.000138lbs/MMBtuOil:0.483lbs/MMBtuNaturalGas:.000138lbs/MMBtuOil:0.483lbs/MMBtu0.57lbs/MMBtu0.57lbs/MMBtu3.70 NoneCO2Removal /EmissionsRate205.2 - 217.3lbs/MMBtu205.2 - 217.3lbs/MMBtu205.2 - 217.3lbs/MMBtu90%NaturalGas:117.08lbs/MMBtuOil:161.39lbs/MMBtuNaturalGas:117.08lbs/MMBtuOil:161.39lbs/MMBtuNone None None None

# Appendix 3-1.1 

# Appendix 3-1 NO

x



# 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 NO X 

# rates found in the NEEDS, v.4.10 database.

Q1: Why are four NO X 

# rates included in NEEDS?

A1: The four NO X 

# rates in NEEDS represent a menu of all the NO X 

# rates applicable to a specific generating unit with only its current configuration of NO

x 

# combustion and post-combustion controls under all the conceivable policies involving NO

x 

# 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 exis ting set of combustion and post-combustion NO

x 

# controls.

Q2: What operational states do the four NO

x 

# rates represent?

A2: Before answering this question, let’s name the four NO

x 

# 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 NO

x 

# rates are shown in the second and

third columns in the table below.

Q3: What NO

x 

# policies in a model run result in the assignment of each of the NO

x 

# 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 NO

x 

# Rates in NEEDS

Name Operational State of NO

x 

# Controls NO

x 

# Policies Causing This Rate To be Assigned Units with post combustion

NO

x 

# controls: Do they operate the controls? No

Mode 1 =

Uncontrolled

Base Rate Units without postcombustion controls: Dothey upgrade to state-offthe-art combustion controls? No If the unit is not covered by any NO

x 

# limit in the run, pre-assign this as its NO

x 

# rate

Units with post combustion

NO

x 

# controls: Do they operate the controls? Yes

Mode 2 =

Controlled

Base Rate Units without postcombustion controls: Dothey upgrade to state-offthe-art combustion controls? No If the unit is covered by a mercury policy, pre-assign this as its NO

x 

# rate

Explanation: Post-combustion NO

x 

# controls figure in mercury reduction but

NO

x 

# combustion controls do not, so the operational state (in column 2) fits the requirements of the policy
Units with post combustion

NO

x 

# controls: Do they operate the controls? No Mode 3 =

Uncontrolled Policy Rate Units without postcombustion controls: Dothey upgrade to state-offYes If the unit is covered by a summer NO

x 

# limit pre-assign this as its winter NO

x 

# rate.

# Appendix 3-1.2 Name Operational State of NO

x 

# Controls NO

x 

# Policies Causing This Rate To be Assigned

the-art combustion controls?
Units with post combustion

NO

x 

# controls: Do they operate the controls? Yes

Mode 4 =

Controlled Policy Rate Units without postcombustion controls: Dothey upgrade to state-offthe-art combustion controls? Yes If the unit is covered by a summer NO

x 

# limit pre-assign this as its summer NO

x 

# rate.

If the unit is covered by an annual NO

x 

# limit, pre-assign this as its winter and

summer NO

x 

# rates.

Q4: How are the values of the Mode 1-4 NO

x 

# 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 NO

x 

# Budget Program. Using this data, NO

x 

# 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 cons istent 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 NO

x 

# rate

Mode 2

For coal units without NO

x 

# post-combustion controls

Mode 2 = Mode 1 rate

For coal units with NO

x 

# post-combustion controls

,

Min{max[Mode 1 NO

x 

# rate * (1-removal efficiency), floor rate], ETS Summer NO

x 

# 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 NO

x 

# controls

For units listed as not having combustion controls

Make sure their NO

x 

# 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 NO

x 

# 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 NO

x 

# rate.

For coal units with post-combustion NO

x 

# 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 NO

x 

# rate, i.e., the unit’s

uncontrolled emission rate without combustion cont rols, using the appropriate equation (not in boldface italics) in Table 3-1.3 to back calculate their Base NO

x 

# rate. Use the default Base NO

x 

# rate values if back calculations can’t be performed. Once the Base NO

x 

# rate is obtained, go to Step 3.

Step 3: Use the appropriate equations (in boldface italics) in Table 3-1.3 to calculate the NO

x 

# rate

with SOA combustion controls.

Step 4: Compare the value calculated in Step 3 to the applicable NO

x 

# 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 NO

x 

# rate. Otherwise, use the

floor as the Mode 3 NO

x 

# rate.

For units without post-combustion controls If the value from Step 3 is ≥ floor, use the Step 3 value as the provisional SOA NO

x 

# rate. Otherwise, use the floor as their provisional SOA NO

x 

# rate. Go to Step 5.

Step 5: For units without post combustion controls compare the provisional SOA NO

x 

# rate obtained in previous steps to their Summer NO

x 

# rate.

If Summer NO

x 

# rate < provisional SOA NO

x 

# rate, then Mode 3 = summer NO

x 

# rate.

If Summer NO

x 

# rate ≥ provisional SOA NO

x 

# rate, then Mode 3 = provisional SOA NO

x 

# 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 NO

x 

# rate}

Note: The (1-.35) term in the equation above represents the 35% NO

x 

# removal efficiency of

SNCR.

Q5: Is there anything else that might be useful to understand about the Mode 1 – 4 NO

x 

# 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 NO

x 

# 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-com bustion controls, the controlled and uncontrolled rates will differ. Base and Policy NO

x 

# rates will be same if the unit has state-of-the-art NO

x 

# 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 NO

x 

# policy. Examples of each of

these instances are shown in Table 3-1.1.

Other things worth noting are: (a) In general, winter NO

x 

# rates reported in EPA’s Emission Tracking System were used as proxies for the uncontrolled base NO

x 

# rates. (b) If a unit does not report having combustion contro ls, 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 NO

x 

# rates achievable by state-of-the-art co mbustion 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 NO

x 

# for some actual operating generating units?

A6: Table 3-1.1 gives the Mode 1-4 NO

x 

# rates for real generating units. They are meant to illustrate a range of situations that can arise.Appendix 3-1.5Table 3-1.1 Examples of Base and Policy NOxRates Occurring in EPA Base Case v.4.10PlantNameUnique IDPostCombustionControlUncontrolledNOxBaseRateControlledNOxBaseRateUncontrolledNOxPolicyRateControlledNOxPolicyRateExplanationSituation 1: For generating units thatdo not have post-combustion controls, the controlled and uncontrolled rates will be thesame.FourCorners2442_B_1None0.8090.8090.5240.524Situation 4 also applies, i.e., unit had LNB andnow added OFA so see drop in policy rates.Situation 2: For generating units thatdo have post-combustion controls, the controlled anduncontrolled rates will differ.Big Sandy1353_B_BSU2SCR0.6380.0640.6380.064(1) Has SCR so see difference betweenuncontrolled and controlled rates(2) Situation 3b also applies.Situation 3a: Base and Policy NOxrates will be same if the unit has state-of-the-art NOxcombustion controls or . . .GreeneCounty10_B_2None0.3160.3160.3160.316Situation 1 also applies.Roxboro2712_B_1SCR0.9000.0840.9000.084Situation 2 also applies.Situation 3b: . . . is in the SIP Call region where current combustion controls are assumed to be retained.Thomas Hill2168_B_MB3SCR0.2230.0600.2230.060Situation 2 also applies.Waukegan883_B_17None0.7100.7100.7100.710(1) Has NOxcombustion control and is in SIP sodoesn't get added combustion control. High NOxrate because it is a cyclone unit(2) Situation 1 also applies.Situation 4: Base and policy rates will differ if a unit does notcurrently have state-of-the-art combustion controls and would install such controls inresponse to a NOxpolicy.ClayBoswell1893_B_4SNCR0.2310.1500.1520.099(1) Drop in uncontrolled policy NOxratecompared to uncontrolled base rate is due toaddition of combustion controls. (Note 0.32 isfloor.)(2) Unit has SNCR so Situation #2a also appliesand you see a 35% drop between uncontrolledand controlled NOxrates.

# Appendix 3-1.6 Table 3-1.2 Cutoff and Floor NO

x 

# 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 NO

x 

# 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 NO

x 

# 0.568 Dry Bottom

Wall-Fired Bituminous

LNB + OFA 0.313 + 0.272*

Base NO

x 

# 0.718

LNB 0.135 + 0.541*

Base NO

x 

# 0.574 Dry Bottom

Wall-Fired Subbituminous /Lignite LNB + OFA 0.285 + 0.541*

Base NO

x 

# 0.724

LNC1 0.162 + 0.336*

Base NO

x 

# 0.42

LNC2 0.212 + 0.336*

Base NO

x 

# 0.47TangentiallyFired Bituminous

LNC3 0.362 + 0.336*

Base NO

x 

# 0.62

LNC1 0.20 + 0.717*

Base NO

x 

# 0.563

LNC2 0.25 + 0.717*

Base NO

x 

# 0.613TangentiallyFired Subbituminous /Lignite

LNC3 0.35 + 0.717*

Base NO

x 

# 0.713

Notes:

LNB = Low NO

x 

# Burner

OFA = Overfire Air

LNC = Low NO

x 

# Control

# Appendix 3-2.1 

# Appendix 3-2 State Power Sector Regul ations 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 NO

x 

# 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

NO

x 

# 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

SO 2 

# 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 NO

x 

# 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 SO 2 

# 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 NO

x 

# 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

NO

x 

# 0.125 lbs/MMBtu rate limit of NO

x 

# annually for

all coal and residual-oil fired units > 25 MW Delaware

Regulation No.

1146: Electric

Generating Unit (EGU)

Multi-Pollutant

Regulation

SO 2 

# 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 NO

x 

# 0.25 lbs/MMBtu summer season rate limit for all

fossil units > 25 MW 2004

NO

x 

# 0.11 lbs/MMBtu annual rate limit and ozone season rate limit for all Dynergy and Ameren

coal steam units > 25 MW 2012

SO 2 

# 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

NO

x 

# 0.11 lbs/MMBtu ozone season and annual rate limit for all specified Midwest Gen coal steam

units 2012

SO 2 

# 0.44 lbs/MMBtu annual rate limit in 2013, decreasing annually to 0.11 lbs/MMBtu in 2019 for all specified Midwes t 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 NO

x 

# 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 SO 2 

# into the atmosphere 2005

Chapter 145

NO

x 

# Control

Program NO

x 

# 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

NO

x 

# 7.3 MTons summer cap and 16.7 MTons annual cap for 15 specific existing coal steam

units

SO 2 

# 2009 through 2012: 48.6 MTons annual cap for 15 specific existing coal steam units 2013 onwards: 37.2 MTons annual cap for 15 specific existing coal steam units Maryland 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 ex isting coal steam units 2009

NO

x 

# 1.5 lbs/MWh annual GPS for Bayton Point, Mystic Generating Station, Somerset Station,
Mount Tom, Canal, and Salem Harbor

SO 2 

# 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 NO

x 

# 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

NO

x 

# 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 SO 2 

# 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 NO

x 

# 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 NO

x 

# 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 NO

x 

# 39.91 MTons non-ozone season cap for fossil

fuel units > 25 MW 2004

Part 238 SO 2 

# 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

NO

x 

# 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 SO 2 

# 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 CO 2 

# 675 lbs/MWh annual rate limit for new

combustion turbines burni ng natural gas with a CF >75% and all new non-base load plants (with a CE <= 75%) emitting CO 2 

# 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 CO 2 

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

SO 2 

# 273.95 MTons cap of SO 2 

# for all grandfathered units built before 1971 in East Texas Region Senate Bill 7 Chapter 101

NO

x 

# 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 NO

x



# 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 NO

x 

# 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-f ired 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 2010Appendix 3-3.1Appendix 3-3 New Source Review (NSR) Settlements in EPA Base Case v.4.10Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReferenceAlabama PowerJames H.MillerAlabamaUnits 3 &4Install andoperate FGDcontinuously95%12/31/2011Operate existingSCR continuously0.15/1/20080.0312/31/2006With 45 days ofsettlement entry,APC must retire7,538 SO2emissionallowances.APC shall not sell,trade, or otherwiseexchange any PlantMiller excess SO2emissionallowances outsideof the APC system1/1/2021http://www.epa.gov/compliance/resources/cases/civil/caa/alabamapower.htmlMinnkota Power CooperativeBeginning 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 by12/31/2015, then beginning 1/01/2014, the plant wide emission shall not exceed 8,500.Unit 1Install andcontinuouslyoperate FGD95% if wetFGD, 90%if dry12/31/2011Install andcontinuously operateOver-fire AIR, orequivalenttechnology withemission rate < .360.3612/31/20090.03 ifwetFGD,.015 ifdry FGDMilton R.YoungMinnesotaUnit 2Design,upgrade, andcontinuouslyoperate FGD90%12/31/2010Install andcontinuously operateover-fire AIR, orequivalenttechnology withemission rate < .360.3612/31/20070.03Before 2008Plant will surrender4,346 allowances foreach year 2012 –2015, 8,693allowances for years2016 – 2018, 12,170allowances for year2019, and 14,886allowances/yearthereafter if Units 1 –3 are operational by12/31/2015. If onlyUnits 1 and 2 areoperationalby12/31/2015, theplant shall retire17,886 units in 2020and thereafter.Minnkota shall notsell or trade NOxallowancesallocated to Units 1,2, or 3 that wouldotherwise beavailable for sale ortrade as a result ofthe actions taken bythe settlingdefendants tocomply with therequirementshttp://www.epa.gov/compliance/resources/cases/civil/caa/minnkota.htmlSIGECOFB CulleyIndianaUnit 1Repower tonatural gas(or retire)12/31/2006The provision did notspecify an amount ofSO2allowances to besurrendered. It onlyprovided that excessallowances resultingfrom compliance withNSR settlementprovisions must beretired.http://www.epa.gov/compliance/resources/cases/civil/caa/sigecofb.htmlAppendix 3-3.2Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReferenceUnit 2Improve andcontinuouslyoperate existingFGD (shared byUnits 2 and 3)95%6/30/2004Unit 3Improve andcontinuouslyoperate existingFGD (shared byUnits 2 and 3)95%6/30/2004Operate ExistingSCR Continuously0.19/1/2003Install andcontinuouslyoperate a Baghouse0.0156/30/2007PSEG FOSSILBergenNew JerseyUnit 2Repower tocombinedcycle12/31/2002The provision did notspecify an amount ofSO2allowances to besurrendered. It onlyprovided that excessallowances resultingfrom compliance withNSR settlementprovisions must beretired.http://www.epa.gov/compliance/resources/cases/civil/caa/psegllc.htmlHudsonNew JerseyUnit 2Install Dry FGD(or approved alt.technology) andcontinuallyoperate0.1512/31/2006Install SCR (orapproved tech) andcontinually operate0.15/1/2007Install Baghouse (orapprovedtechnology)0.01512/31/2006MercerNew JerseyUnits 1 &2Install Dry FGD(or approved alt.technology) andcontinuallyoperate0.1512/31/2010Install SCR (orapproved tech) andcontinually operate0.135/1/2006TECOUnits 1 &2ExistingScrubber(shared by Units1 & 2)95% (95%or .25)09/1/00(01/01/13)Install SCR0.15/1/2009Big BendFloridaUnit 3ExistingScrubber93% ifUnits 3 & 42000Install SCR0.15/1/2009The provision did notspecify an amount ofSO2allowances to besurrendered. It onlyprovided that excessallowances resultinghttp://www.epa.gov/compliance/resources/cases/civil/caa/teco.htmlAppendix 3-3.3Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReference(shared by Units3 & 4)areoperating(01/01/10)Unit 4ExistingScrubber(shared by Units3 & 4)93% ifUnits 3 & 4areoperating6/22/2005Install SCR0.17/1/2007from compliance withNSR settlementprovisions must beretired.GannonFloridaSix unitsRetire all sixcoal unitsandrepower atleast 550MW of coalcapacity tonatural gas12/31/2004WEPCOWEPCO shall comply with the following system wide average NOxemission rates and total NOxtonnage 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 an emission rate of 0.17and 17, 400 tons. For SO2emissions, 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 0.61and 74,400 tons, by 1/1/2008 an emission rate of 0.45 and 55,400 tons, and by 1/1/2013 an emission rate of 0.32and 33,300 tons.http://www.epa.gov/compliance/resources/cases/civil/caa/wepco.htmlUnits 1 –4Retire orinstall SO2and NOxcontrols12/31/2012Install andcontinuouslyoperate FGD (orapproved equiv.tech)95% or 0.112/31/2012Install SCR (orapproved tech) andcontinually operate0.112/31/2012Units 5 &6Install and operatelow NOxburners12/31/2003Units 7 &8Operate existing lowNOxburners12/31/2005Install BaghousePresque IsleWisconsinUnit 9Operate existing lowNOxburners12/31/2006Install Baghouse1Install andcontinuouslyoperate FGD (orapproved controltech)95% or 0.112/31/2006Install andcontinuously operateSCR (or approvedtech)0.112/31/2006PleasantPrairieWisconsin2Install andcontinuouslyoperate FGD (orapproved controltech)95% or 0.112/31/2007Install andcontinuously operateSCR (or approvedtech)0.112/31/2003The provision did notspecify an amount ofSO2allowances to besurrendered. It onlyprovided that excessallowances resultingfrom compliance withNSR settlementprovisions must beretired.Appendix 3-3.4Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReferenceUnits 5 &6Install andcontinuouslyoperate FGD (orapproved controltech)95% or 0.112/31/2012Install andcontinuously operateSCR (or approvedtech)0.112/31/2012Unit 7Install andcontinuouslyoperate FGD (orapproved controltech)95% or 0.112/31/2012Install andcontinuously operateSCR (or approvedtech)0.112/31/2012Oak CreekWisconsinUnit 8Install andcontinuouslyoperate FGD (orapproved controltech)95% or 0.112/31/2012Install andcontinuously operateSCR (or approvedtech)0.112/31/2012PortWashingtonWisconsinUnits 1 –4Retire12/31/04 forUnits 1 – 3.Unit 4 byentry ofconsentdecreeValleyWisconsinBoilers 1– 4Operate existing lowNOxburner30 daysafter entryof consentdecreeVEPCOThe Total Permissible NOxEmissions (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 after. Beginning 1/1/2013 theywill have a system wide emission rate no greater then 0.15 lb/MMBtu.Mount StormWestVirginiaUnits 1 –3Construct orimprove FGD95% or0.151/1/2005Install andcontinuously operateSCR0.111/1/2008Unit 4Install andcontinuously operateSCR0.11/1/2013Unit 5Construct orimprove FGD95% or0.1310/12/2012Install andcontinuously operateSCR0.11/1/2012ChesterfieldVirginiaUnit 6Construct orimprove FGD95% or0.131/1/2010Install andcontinuously operateSCR0.11/1/2011http://www.epa.gov/compliance/resources/cases/civil/caa/vepco.htmlChesapeakeEnergyVirginiaUnits 3 &4Install andcontinuously operateSCR0.11/1/2013On or before March31 of every yearbeginning in 2013and continuingthereafter, VEPCOshall surrender45,000 SO2allowances.Appendix 3-3.5Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReferenceCloverVirginiaUnits 1 &2Improve FGD95% or0.139/1/2003PossumPointVirginiaUnits 3 &4Retire andrepower tonatural gas5/2/2003Santee CooperSantee Cooper shall comply with the following system wide averages for NOxemission rates and combined tons for emission of: by 1/01/2005 facility shall comply with an emission rate of 0.3 and 30,000tons, by 1/1/2007 an emission rate of 0.18 and 25,000 tons, by1/1/2010 and emission rate of 0.15 and 20,000 tons. For SO2emission 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 1/1/2009 an emission rateof 0.53 and 70 tons, and by 1/1/2011 and emission rate of 0.5 and 65 tons.http://www.epa.gov/compliance/resources/cases/civil/caa/santeecooper.htmlUnit 1Upgrade andcontinuouslyoperate FGD95%6/30/2006Install andcontinuously operateSCR0.15/31/2004CrossSouthCarolinaUnit 2Upgrade andcontinuouslyoperate FGD87%6/30/2006Install andContinuouslyoperate SCR0.11/0.105/31/04and05/31/07Unit 1Install andcontinuouslyoperate FGD95%12/31/2008Install andcontinuously operateSCR0.11/0.111/30/04and11/30/04Unit 2Install andcontinuouslyoperate FGD95%12/31/2008Install andcontinuously operateSCR0.1211/30/2004Unit 3Upgrade andcontinuouslyoperate existingFGD90%12/31/2008Install andcontinuously operateSCR0.14/0.1211/30/2005and11/30/08WinyahSouthCarolinaUnit 4Upgrade andcontinuouslyoperate existingFGD90%12/31/2007Install andcontinuously operateSCR0.13/0.1211/30/05and11/30/08Unit 1Operate low NOxburner or morestringent technology6/25/2004GraingerSouthCarolinaUnit 2Operate low NOxburner or morestringent technology5/1/2004The provision did notspecify an amount ofSO2allowances to besurrendered. It onlyprovided that excessallowances resultingfrom compliance withNSR settlementprovisions must beretired.Appendix 3-3.6Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReferenceJeffriesSouthCarolinaUnits 3, 4Operate low NOxburner or morestringent technology6/25/2004Ohio EdisonOhio Edison shall achieve reductions of 2,483 tons NOxbetween 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 October through April,and/or 3) emitting fewer tons than the Plant-Wide Annual Cap for NOxrequired for the Sammis Plant. Ohio Edison must reduce 24,600 tons system-wide of SO2by 12/31/2010.No later than 8/11/2005, Ohio Edison shall install and operate low NOxburners 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 with software to minimizeNOxemissions from Sammis Units 1 – 5.http://www.epa.gov/compliance/resources/cases/civil/caa/ohioedison.htmlInstall Induct50%removalInstall SNCRScrubber (oror 1.1lb/MMBtu(or approvedapproved equiv.alt. tech) &control tech)operateUnit 112/31/2008continuously0.2510/31/2007Install Induct50%removalOperateScrubber (oror 1.1lb/MMBtuexisting SNCRapproved equiv.continuouslyUnit 2control tech)12/31/20080.252/15/2006Install Induct50%removalOperate low NOxburners and overfireair by 12/1/05; installSNCR12/1/2005Scrubber (oror 1.1lb/MMBtu(or approvedandapproved equiv.alt. tech) &10/31/2007control tech)operateUnit 312/31/2008continuously by12/31/070.25Install Induct50%removalInstall SNCRW.H.SammisPlantOhioUnit 4Scrubber (oror 1.1lb/MMBtu6/30/2009(or approved0.2510/31/2007Beginning on1/1/2006, OhioEdison may use, sellor transfer anyrestricted SO2only tosatisfy theOperational Needs atthe Sammis, Burgerand Mansfield Plant,or new units withinthe FirstEnergySystem that complywith a 96% removalfor SO2. Forcalendar year 2006through 2017, OhioEdison mayaccumulate SO2allowances for use atthe Sammis, Burger,and Mansfield plants,or FirstEnergy unitsequipped with SO2Emission ControlStandards.Beginning in 2018,Ohio Edison shallsurrender unusedrestricted SO2allowances.Appendix 3-3.7Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReferenceapproved equiv.alt. tech) &control tech)operatecontinuouslyInstall Flash50%removalInstall SNCRDryer Absorberor 1.1lb/MMBtu(or approvedor ECO2(oralt. tech) &approved equiv.Operatecontrol tech) &ContinuouslyoperateUnit 5continuously6/29/20090.293/31/2008Install FGD3(orInstall SNCR"MinimumOperateapproved equiv.(or approvedExtentExistingcontrol tech) &alt. tech) &Practicable"ESPoperateoperateContinuouslyUnit 6continuously95%removal or0.13lb/MMBtu6/30/2011continuously6/30/20050.031/1/2010Install FGD (orOperate"MinimumOperateapproved equiv.existing SNCRExtentExistingcontrol tech) &ContinuouslyPracticable"ESPoperateContinuouslyUnit 7continuously95%removal or0.13lb/MMBtu6/30/20118/11/20050.031/1/2010UpgradeUnit 1existing FGD95%12/31/2005UpgradeMansfieldPlantPennsylvaniaUnit 2existing FGD95%12/31/2006Appendix 3-3.8Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReferenceUpgradeUnit 3existing FGD95%10/31/2007Install low NOx"MinimizeEmissions totheburners, over-firedExtentEastlakeOhioUnit 5air and SNCR &operate continuouslyPracticable"12/31/2006Unit 412/31/2011BurgerOhioUnit 5Repowerwith at least80%biomassfuel, up to20% lowsulfur coal.12/31/2011MirantI1,6System-wide NOxEmission 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 NOxEmission Ozone Season Caps: 14,700 tons 2004; 13,340 tons 2005;12,590 tons 2006; 10,190 tons 2007; 6,150 tons 2008 – 2009; 5,200 tons 2010 thereafter. Beginning on 5/1/2008, and continuingfor each and every Ozone Season thereafter, the Mirant System shall not exceed a System-wide Ozone Season Emission Rate of 0.150lb/MMBtu NOx.http://www.epa.gov/compliance/resources/cases/civil/caa/mirant.htmlUnit 1Unit 2Install low NOxburners (or moreeffective tech) &Unit 3operate continuously5/1/2004Install low NOxburners (or moreeffective tech) &Unit 4operate continuously5/1/2004Install low NOxburners (or moreeffective tech) &PotomacRiver PlantVirginiaUnit 5operate continuously5/1/2004Appendix 3-3.9Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReferenceInstall SCR(or approvedalt. tech) &Unit 1operate continuously0.15/1/2007Install SCR(or approvedalt. tech) &MorgantownPlantMarylandUnit 2operate continuously0.15/1/2008Unit 1Install andcontinuouslyoperate FGD (orequiv.technology)95%6/1/2010Chalk PointMarylandUnit 2Install andcontinuouslyoperate FGD (orequiv.technology)95%6/1/2010For each year afterMirant commencesFGD operation atChalk Point, Mirantshall surrender thenumber of SO2Allowances equal tothe amount by whichthe SO2Allowancesallocated to the Unitsat the Chalk PointPlant are greater thanthe total amount ofSO2emissionsallowed under thisSection XVIII.Illinois PowerSystem-wide NOxEmission Annual Caps: 15,000 tons 2005; 14,000 tons 2006; 13,800 tons 2007 onward. System-wide SO2Emission Annual Caps: 66,300 tons 2005 – 2006; 65,000 tons 2007; 62,000 tons 2008 – 2010; 57,000 tons 2011; 49,500 tons 2012;29,000 tons2013 onward.http://www.epa.gov/compliance/resources/cases/civil/caa/illinoispower.htmlUnits 1 &2Install wet or dryFGD (orapproved equiv.alt. tech) &operatecontinuously0.112/31/2011Operate OFA &existing SCRcontinuously0.18/11/2005Install &continuouslyoperate Baghouse0.01512/31/2010BaldwinIllinoisUnit 3Install wet or dryFGD (orapproved equiv.alt. tech) &operatecontinuously0.112/31/2011Operate OFA and/orlow NOxburners0.12 until12/30/12; 0.1from 12/31/1208/11/05and12/31/12Install &continuouslyoperate Baghouse0.01512/31/2010By year end 2008,Dynergy willsurrender 12,000SO2emissionallowances, by yearend 2009 it willsurrender 18,000, byyear end 2010 it willsurrender 24,000,any by year end 2011and each yearthereafter it willsurrender 30,000allowances. If theAppendix 3-3.10Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReference8/11/2005ForBaghouse:12/31/12;andFor ESP:12/31/05HavanaIllinoisUnit 6Install wet or dryFGD (orapproved equiv.alt. tech) &operatecontinuously1.2lb/MMBtuuntil12/30/2012; 0.1lb/MMBtufrom12/31/2012onward12/31/2012Operate OFA and/orlow NOxburners &operate existingSCR continuously0.18/11/2005Install &continuouslyoperate Baghouse,then install ESP oralt. PM equipFor Baghouse:0.015lb/MMBtu; ForESP:0.03lb/MMBtuOperate OFA"Minimumand/or low NOxburnersExtentUnit 11.27/27/2005Practicable"8/11/2005Install ESP (orequiv. alt. tech) &continuouslyoperate ESPs0.0312/31/2006Operate OFA"Minimumand/or low NOxburnersExtentHennepinIllinoisUnit 21.27/27/2005Practicable"8/11/2005Install ESP (orequiv. alt. tech) &continuouslyoperate ESPs0.0312/31/2006Operate OFA"Minimumand/or low NOxburnersExtentVermilionIllinoisUnits 1 &21.21/31/2007Practicable"8/11/2005Install ESP (orequiv. alt. tech) &continuouslyoperate ESPs0.0312/31/2010Operate OFA"Minimumand/or low NOxburnersExtentWood RiverIllinoisUnits 4 &51.27/27/2005Practicable"8/11/2005Install ESP (orequiv. alt. tech) &continuouslyoperate ESPs0.0312/31/2005surrenderedallowances result ininsufficient remainingallowances allocatedto the unitscomprising the DMGsystem, DMG canrequest to surrenderfewer SO2allowances.Kentucky Utilities CompanyEW BrownGeneratingStationKentuckyUnit 3Install FGD97% or0.10012/31/2010Install andcontinuously operateSCR by 12/31/2012,continuously operatelow NOxboiler andOFA.0.0712/31/2012Continuouslyoperate ESP0.0312/31/2010KU must surrender53,000 SO2allowances of 2008or earlier vintage byMarch 1, 2009. Allsurplus NOxallowances must besurrendered through2020.SO2and NOxallowances may notbe used forcompliance, andemissionsdecreases forpurposes ofcomplying with theConsent Decree donot earn credits.http://www.epa.gov/compliance/resources/cases/civil/caa/kucompany.htmlSalt River Project Agricultural Improvement and Power District (SRP)Appendix 3-3.11Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReferenceUnit 1 orUnit 2Immediatelybegincontinuousoperation ofexisting FGDson both units,install new FGD.95% or0.08New FGDinstalled by1/1/2012Install andcontinuously operatelow NOxburner andSCR0.32 prior toSCRinstallation,0.080 afterLNB by06/01/2009, SCR by06/01/2014Optimizationbeginsimmediately,rate limitbegins01/01/12(date of newFGDinstallation)CoronadoGeneratingStationArizonaUnit 1 orUnit 2Install new FGD95% or0.081/1/2013Install andcontinuously operatelow NOxburner0.326/1/2011Optimization andcontinuousoperation of existingESPs.0.03Optimizationbeginsimmediately,rate limitbegins01/01/13(date of newFGDinstallation)Beginning in 2012, allsurplus SO2allowances for bothCoronado andSpringerville Unit 4must be surrenderedthrough 2020. Theallowances limited bythis condition may,however, be used forcompliance at aprospective futureplant using BACTand otherwisespecified in par. 54 ofthe consent decree.SO2and NOxallowances may notbe used forcompliance, andemissionsdecreases forpurposes ofcomplying with theConsent Decree donot earn credits.http://www.epa.gov/compliance/resources/cases/civil/caa/srp.htmlAmerican Electric PowerAnnual Cap(tons)YearAnnual Cap(tons)Year450,000201096,0002009450,000201192,5002010420,000201292,5002011350,000201385,0002012340,000201485,0002013275,000201585,0002014260,000201675,0002015235,000201772,0002016 andthereafter184,0002018Eastern System-Wide174,0002019 andthereafterNOxand SO2allowances thatwould have beenmade available byemission reductionspursuant to theConsent Decreemust be surrendered.NOxand SO2allowances may notbe used to complywith any of the limitsimposed by theConsent Decree.The ConsentDecree includes aformula forcalculating excessNOxallowancesrelative to the CAIRAllocations, andrestricts the use ofsome. See par. 74-79 for details.Reducing emissionsbelow the EasternSystem-WideAnnual TonnageLimitations for NOxand SO2earnssuper complianceallowances.http://www.epa.gov/compliance/resources/cases/civil/caa/americanelectricpower1007.htmlSpornWestVirginia1 – 4ClinchRiverVirginia1 – 3At least600MW fromvarious unitsIndianaTannersCreekRetire,retrofit, orre-power12/31/2018Appendix 3-3.12Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReference1 – 3KammerWestVirginia1 – 3Unit 1Install andcontinuouslyoperate FGD12/31/2009Install andcontinuously operateSCR1/1/2008Unit 2Install andcontinuouslyoperate FGD12/31/2010Install andcontinuously operateSCR1/1/2009AmosWestVirginiaUnit 3Install andcontinuouslyoperate FGD12/31/2009Install andcontinuously operateSCR1/1/2008Unit 1Burn only coalwith no morethan 1.75lb/MMBtuannual averageDate ofentryContinuouslyoperate low NOxburnersDate ofentryBig SandyKentuckyUnit 2Install andcontinuouslyoperate FGD12/31/2015Install andcontinuously operateSCR1/1/2009Unit 1Install andcontinuouslyoperate FGD12/31/2008Install andcontinuously operateSCR1/1/2009Continuouslyoperate ESP0.0312/31/2009Unit 2Install andcontinuouslyoperate FGD12/31/2008Install andcontinuously operateSCR1/1/2009Continuouslyoperate ESP0.0312/31/2009CardinalOhioUnit 3Install andcontinuouslyoperate FGD12/31/2012Install andcontinuously operateSCR1/1/2009Clinch RiverVirginiaUnits 1 –3Plant-wideannual cap:21,700tons from2010 to2014, then16,300after1/1/20152010 –2014, 2015andthereafterContinuouslyoperate low NOxburnersDate ofentryUnit 1Retire,retrofit, orre-powerDate ofentryConesvilleOhioUnit 2Retire,retrofit, orre-powerDate ofentryAppendix 3-3.13Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReferenceUnit 3Retire,retrofit, orre-power12/31/2012Unit 4Install andcontinuouslyoperate FGD12/31/2010Install andcontinuously operateSCR12/31/2010Unit 5Upgradeexisting FGD95%12/31/2009Continuouslyoperate low NOxburnersDate ofentryUnit 6Upgradeexisting FGD95%12/31/2009Continuouslyoperate low NOxburnersDate ofentryUnit 1Install andcontinuouslyoperate FGDDate ofentryInstall andcontinuously operateSCR1/1/2009GavinOhioUnit 2Install andcontinuouslyoperate FGDDate ofentryInstall andcontinuously operateSCR1/1/2009Glen LynVirginiaUnits 5, 6Burn only coalwith no morethan 1.75lb/MMBtuannual averageDate ofentryContinuouslyoperate low NOxburnersDate ofentryKammerWestVirginiaUnits 1 –3Plant-wideannual cap:35,0001/1/2010Continuouslyoperate over-fire airDate ofentryKanawhaRiverWestVirginiaUnits 1, 2Burn only coalwith no morethan 1.75lb/MMBtuannual averageDate ofentryContinuouslyoperate low NOxburnersDate ofentryUnit 1Install andcontinuouslyoperate FGD12/31/2007Install andcontinuously operateSCR1/1/2009MitchellWestVirginiaUnit 2Install andcontinuouslyoperate FGD12/31/2007Install andcontinuously operateSCR1/1/2009MountaineerWestVirginiaUnit 1Install andcontinuouslyoperate FGD12/31/2007Install andcontinuously operateSCR1/1/2008MuskingumRiverOhioUnits 1 –4Retire,retrofit, orre-power12/31/2015Appendix 3-3.14Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReferenceUnit 5Install andcontinuouslyoperate FGD12/31/2015Install andcontinuously operateSCR1/1/2008Continuouslyoperate ESP0.0312/31/2002PicwayOhioUnit 9Continuouslyoperate low NOxburnersDate ofentryUnit 1Install andcontinuouslyoperate FGD12/31/2017Install andcontinuously operateSCR12/31/2017RockportIndianaUnit 2Install andcontinuouslyoperate FGD12/31/2019Install andcontinuously operateSCR12/31/2019SpornWestVirginiaUnit 5Retire,retrofit, orre-power12/31/2013Units 1 -3Burn only coalwith no morethan 1.2lb/MMBtuannual averageDate ofentryContinuouslyoperate low NOxburnersDate ofentryTannersCreekIndianaUnit 4Burn only coalwith no morethan 1.2% sulfurcontent annualaverageDate ofentryContinuouslyoperate over-fire airDate ofentryEast Kentucky Power Cooperative Inc.By 12/31/2009, EKPC shall choose whether to: 1) install and continuously operate NOxcontrols at Cooper 2 by 12/31/2012 and SO2controls by 6/30/2012 or 2) retire Dale 3 and Dale 4 by 12/31/2012.12-monthrolling limit(tons)Start of 12-month cycle12-monthrolling limit(tons)Start of 12-monthcycle57,00010/1/200811,5001/1/200840,0007/1/20118,5001/1/2013System-wideSystem-wide 12-month rollingtonnage limitsapply28,0001/1/2013All units mustoperate low NOxboilers8,0001/1/2015PM control devicesmust be operatedcontinuouslysystem-wide, ESPsmust be optimizedwithin 270 days ofentry date, or EKPCmay choose tosubmit a PMPollution ControlUpgrade Analysis.0.031 year fromentry dateAll surplus SO2allowances must besurrendered eachyear, beginning in2008.SO2and NOxallowances may notbe used to complywith the ConsentDecree. NOxallowances thatwould becomeavailable as a resultof compliance withthe Consent Decreemay not be sold ortraded. SO2andNOxallowancesallocated to EKPCmust be used withinthe EKPC system.Allowances madeavailable due tosuper compliancemay be sold ortraded.http://www.epa.gov/compliance/resources/cases/civil/caa/nevadapower.htmlAppendix 3-3.15Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReferenceUnit 1Install andcontinuouslyoperate FGD95% or 0.16/30/2011Continuouslyoperate SCR0.12 for Unit 1until01/01/2013, atwhich point theunit limit dropsto 0.1. Prior to01/01/2013, thecombinedaverage whenboth units areoperating mustbe no morethan 0.160 daysafter entrySpurlockKentuckyUnit 2Install andcontinuouslyoperate FGD by10/1/200895% or 0.11/1/2009Continuouslyoperate SCR andOFA0.1 for Unit 2,0.1 combinedaverage whenboth units areoperating60 daysafter entryUnit 1Install andcontinuously operatelow NOxburners by10/31/20070.461/1/2008Unit 2Install andcontinuously operatelow NOxburners by10/31/20070.461/1/2008EKPC mustsurrender 1,000 NOxallowancesimmediately underthe ARP, and 3,107under the NOxSIPCall. EKPC mustalso surrender15,311 SO2allowances.Date of entryhttp://www.epa.gov/compliance/resources/cases/civil/caa/eastkentuckypower-dale0907.htmlUnit 3EKPC maychoose toretire Dale 3and 4 in lieuof installingcontrols inCooper 212/31/2012Dale PlantKentuckyUnit 4CooperKentuckyUnit 1Appendix 3-3.16Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReferenceUnit 2If EKPC opts toinstall controlsrather thanretiring Dale, itmust install andcontinuouslyoperate FGD orequiv.technology95% or0.10If EKPC elects toinstall controls, itmust continuouslyoperate SCR orinstall equiv.technology0.08 (or 90% ifnon-SCRtechnology isused)12/31/2012Nevada Power CompanyBeginning 1/1/2010, combined NOxemissions from Units 5, 6, 7, and 8 must be no more than 360 tons per year.Unit 55ppm 1-houraverage12/31/08(ULNBinstallation), 01/30/09(1-houraverage)Unit 65ppm 1-houraverage12/31/09(ULNBinstallation), 01/30/10(1-houraverage)Unit 75ppm 1-houraverage12/31/09(ULNBinstallation), 01/30/10(1-houraverage)ClarkGeneratingStationNevadaUnit 8Units may only firenatural gasIncrease waterinjectionimmediately, theninstall and operateultra-low NOxburners (ULNBs) orequivalenttechnology. In 2009,Units 5 and 8 maynot emit more than180 tons combined5ppm 1-houraverage12/31/08(ULNBinstallation), 01/30/09(1-houraverage)Allowances may notbe used to complywith the ConsentDecree, and noallowances madeavailable due tocompliance with theConsent Decreemay be traded orsold.http://www.epa.gov/compliance/resources/cases/civil/caa/nevadapower.htmlDayton Power & LightNon-EPA Settlement of 10/23/2008Owners may notpurchase any newcatalyst with SO2toSO3conversion rategreater than 0.5%0.17 stationwide30 daysafter entryStuartGeneratingStationOhioStation-wideCompleteinstallation ofFGDs on eachunit.96% or0.107/31/20090.17 stationwide60 daysafter entrydate0.030 lbper unit7/31/2009NOxand SO2allowances may notbe used to complywith the monthlyrates specified inthe ConsentDecree.Courtlinkdocument providedby EPA in emailAppendix 3-3.17Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReference82%includingdata fromperiods ofmalfunctions7/31/09through7/30/11Install controltechnology on oneunit0.10 on anysingle unit12/31/20120.15 stationwide7/1/201282%includingdata fromperiods ofmalfunctionsafter7/31/110.10 stationwide12/31/2014Installrigid-typeelectrodes ineachunit'sESP12/31/2015PSEG FOSSIL, Amended Consent Decree of November 2006Unit 7Retire unit1/1/2007http://www.epa.gov/compliance/resources/decrees/amended/psegfossilamended-cd.pdfKearnyNew JerseyUnit 8Retire unit1/1/2007Allowances allocatedto Kearny, Hudson,and Mercer may onlybe used for theoperational needs ofthose units, and allsurplus allowancesmust be surrendered.Within 90 days ofamended ConsentDecree, PSEG mustsurrender 1,230 NOxAllowances and8,568 SO2Allowances notalready allocated toor generated by theunits listed here.Kearny allowancesmust be surrenderedwith the shutdown ofthose units.0.1512/31/20100.112/31/2010Annual Cap(tons)YearAnnual Cap(tons)Year5,54720073,48620075,27020083,48620085,27020093,4862009HudsonNew JerseyUnit 2Install Dry FGD(or approved alt.technology) andcontinuallyoperate5,2702010Install SCR (orapproved tech) andcontinually operate3,4862010Install Baghouse (orapprovedtechnology)0.01512/31/2010Appendix 3-3.18Settlement ActionsRetire/RepowerSO2controlNOxControlPM or Mercury ControlAllowanceRetirementAllowance RestrictionCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateReferenceMercerNew JerseyUnits 1 &2Install Dry FGD(or approved alt.technology) andcontinuallyoperate0.1512/31/2010Install SCR (orapproved tech) andcontinually operate0.11/1/2007Install Baghouse (orapprovedtechnology)0.01512/31/2010Westar EnergyUnits 1, 2, and 3 have a total annual limit of6,600 tons of SO2starting 2011Units 1-3 must continuously operate Low NOxCombustion Systems by 2012 and achieve andmaintain a 30-Day Rolling Average Unit EmissionRate for NOxof no greater than 0.180 lb/MMBtu.Units 1, 2, and 3 must operate each ESP andFGD system continuously by 2011 andmaintain a 0.030 lb/MMBtu PM EmissionsRate.Units 1, 2, and 3 must all install FGDs by2011 and operate them continuously.One of the three units must install an SCR by 2015and operate it continuously to maintain a 30-DayRolling Average Unit Emission Rate for NOxof nogreater than 0.080 lb/MMBtu.Units 1 and 2’s ESPs must be rebuilt by 2014in order to meet a 0.030 lb/MMBtu PMEmissions RateJeffreyEnergyCenterKansasAll unitsFGDs must maintain a 30-Day RollingAverage Unit Removal Efficiency for SO2ofat least 97% or a 30-Day Rolling AverageUnit Emission Rate for SO2of no greaterthan 0.070 lb/MMBtu.By 2013 Westar shall elect to either (a) install asecond SCR on one of the other JEC Units by2017 or (b) meet a 0.100 lb/MMBtu Plant-Wide 12-Month Rolling Average Emission Rate for NOxby2015Duke EnergyUnits 1 &3Retire orrepower asnatural gas1/1/2012GallagherIndianaUnits 2 &4Install Drysorbent injectiontechnology80%1/1/2012Notes: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 description of all elements of the actualsettlement 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 generally modeled as individual constraints onemission rates in EPA Base Casev.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 theseNSR 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 EPABase Case v.4.104) If a settlement agreement requires installation of PM controls, then the controls are shown in this table and reflected inEPA Base Casev.4.10. If settlement requires optimization or upgrade of existing PM controls, those actions are not included inEPA Base Case v.4.10.5) 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, EPAmodeling assumes the most cost effective FGD (wet or dry) and a corresponding 98% removal efficiency for wet and 93% for dry.7) 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 afloor of .06 lb/MMBtu or used the emission limit if provided.8) The applicable low NOxburner 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 SO2allowances. 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 3-4.1Appendix 3-4 State Settlements in EPA Base Case v.4.10State Enforcement ActionsRetire/RepowerSO2controlNOxControlPM ControlMercury ControlCompany andPlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffective DateEquipmentRateEffectiveDateEquipmentRateEffectiveDateAESUnit 4Install FGD90%9/1/2007Install SCR0.159/1/2007GreenidgeNew YorkUnit 3Install BACT12/31/2009Install BACT12/31/2009Unit 890%12/31/2010Install SCR0.1512/31/2010WestoverNew YorkUnit 7Install BACT12/31/2009Install BACT12/31/2009HicklingNew YorkUnits 1 &2Install BACT5/1/2007Install BACT5/1/2007JennisonNew YorkUnits 1 &2Install BACT5/1/2007Install BACT5/1/2007Niagara Mohawk PowerNRG shall comply with the below annual tonnage limitations for its Huntley and Dunkirk Stations: 2005 is 59,537 tons of SO2and 10,777 tons of NOx, 2006 is 34,230 of SO2and 6,772 of NOx, 2007 is 30,859 of SO2and 6,211 of NOx, 2008 is22,733 tons of SO2HuntleyNew YorkUnits 63– 66RetireBefore2008Public Service Co. of NMUnit 110/31/200810/31/200812/31/200912/31/2009Unit 23/31/20093/31/200912/31/200912/31/2009Unit 34/30/20084/30/20084/30/20084/30/2008San JuanNew MexicoUnit 4State-of-the-arttechnology90%10/31/2007State-of-the-arttechnology0.310/31/2007OperateBaghouse anddemistertechnology0.0210/31/2007Designactivatedcarbon injectiontechnology (orcomparabletech)10/31/2007Public Service Co of ColoradoUnits 1 &2Install andoperate FGD0.1lb/MMBtucombinedaverage7/1/2009Install low-NOxemission controls0.15lb/MMBtucombinedaverage7/1/2009Install sorbentinjectiontechnology7/1/20090.1ComancheColoradoUnit 3Install andoperate FGDlb/MMBtuInstall andoperate SCR0.08Install andoperate afabric filterdust collectionsystem0.01Install sorbentinjectiontechnologyWithin 180days of startupAppendix 3-4.2State Enforcement ActionsRetire/RepowerSO2controlNOxControlPM ControlMercury ControlCompany andPlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffective DateEquipmentRateEffectiveDateEquipmentRateEffectiveDateTVABull RunTennesseeUnit 1Complete FGDinstallation0.15lb/MMBtu,4,431 TPYFGDalreadyactive as ofdate ofentry0.08lb/MMBtu,2,295 TPYUnit 10.15lb/MMBtu,1,023 TPY0.05lb/MMBtu,372 TPYUnit 20.15lb/MMBtu,1,028 TPY0.05lb/MMBtu,374 TPYUnit 30.15lb/MMBtu,1,081 TPY0.05lb/MMBtu,389 TPYJohn SevierTennesseeUnit 4Install FGD0.15lb/MMBtu,1,000 TPY27 monthsfrom dateof entryInstall SCR0.05lb/MMBtu,360 TPY21 monthsfrom date ofentryUnit 10.15lb/MMBtu,794 TPY0.06lb/MMBtu,323 TPYUnit 20.15lb/MMBtu,785 TPY0.06lb/MMBtu,320 TPYUnit 30.15lb/MMBtu,822 TPY0.06lb/MMBtu,335 TPYUnit 40.15lb/MMBtu,800 TPY0.06lb/MMBtu,326 TPYUnit 50.15lb/MMBtu,1,021 TPY0.06lb/MMBtu,416 TPYUnit 60.15lb/MMBtu,1,095 TPY0.05lb/MMBtu,365 TPYUnit 70.15lb/MMBtu,1,040 TPY0.05lb/MMBtu,347 TPYUnit 80.15lb/MMBtu,1,048 TPY0.05lb/MMBtu,349 TPYKingstonTennesseeUnit 9Install FGD0.15lb/MMBtu,1,012 TPY27 monthsfrom dateof entryOperate existingSCR0.05lb/MMBtu,337 TPYAppendix 3-4.3State Enforcement ActionsRetire/RepowerSO2controlNOxControlPM ControlMercury ControlCompany andPlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffective DateEquipmentRateEffectiveDateEquipmentRateEffectiveDateUnit 10.15lb/MMBtu,569 TPY0.06lb/MMBtu,246 TPYUnit 20.15lb/MMBtu,608 TPY0.06lb/MMBtu,263 TPYUnit 30.15lb/MMBtu,663 TPY0.06lb/MMBtu,287 TPYUnit 40.15lb/MMBtu,602 TPY0.06lb/MMBtu,261 TPYUnit 50.15lb/MMBtu,640 TPY0.06lb/MMBtu,277 TPYUnit 6Install FGD0.15lb/MMBtu,626 TPY27 monthsfrom dateof entryInstall SCR0.06lb/MMBtu,271 TPY21 monthsfrom date ofentryUnit 70.56lb/MMBtu,8950 TPY0.06lb/MMBtu,892 TPYWidows CreekAlabamaUnit 80.30lb/MMBtu,4,508 TPY0.06lb/MMBtu,860 TPYRochester Gas & ElectricRussell PlantNew YorkUnits 1 –4RetireallunitsMirant New YorkUnit 1Retire5/7/2007Lovett PlantNew YorkUnit 2Retire4/30/2008Appendix 3-5.1Appendix 3-5 Citizen Settlements in EPA Base Case v.4.10Citizen Suits Provided by DOJRetire/RepowerSO2controlNOxControlPM ControlCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateSWEPCO (AEP)WelshTexasUnits 1-3Install andoperate CEMs12/31/2010Allegheny EnergyHatfield'sFerryPennsylvaniaUnits 1- 3Install andoperate wetFGD6/30/2010Install andoperate sulfurtrioxide injectionsystems, improveESPperformance0.1 lb/MMBtu in2006, then 0.075lbs per hour(filterable) and 0.1lb/MMBtu forparticles less thanten microns in 20102006 and6/30/2010Wisconsin Public Service CorpPulliamWisconsinUnits 3& 4Retire12/31/2007University of WisconsinCharterStreetHeatingPlantWisconsinRepower toburn 100%biomass12/31/2012Appendix 3-5.2Citizen Suits Provided by DOJRetire/RepowerSO2controlNOxControlPM ControlCompanyand PlantStateUnitActionEffectiveDateEquipmentPercentRemovalor RateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateTucson Electric PowerUnits 1& 20.27lb/MMBtu12/31/20060.22lb/MMBtu12/31/20060.03 lb/MMBtu1/1/2006Unit 3SpringervillePlantArizonaFutureUnit 4Dry FGD,85%reductionrequiredFour-unitcap of10,662tons peryear onceunits 3 and4 areoperationalSCR, LNBFour-unitcap of8,940 tonsper yearonce units3 and 4 areoperationalBaghouse

# 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 Li mits 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 CCSNew NuclearAppendix 3-8.1Appendix 3-8 Nuclear Capacity DeploymentConstraint in EPA Base Case v.4.10RunYearBase NewNuclearCapacityBase New NuclearCapacity DeploymentEquationPossibleAdditional New NuclearCapacity Deployment Equation1Maximum Annual Incremental New Nuclear CapacityDeployment Allowed Equation20207,5007,50007,500203014,7001.96 *2020_Base_Capacity+ 1.96 *2020_Incremental_Capacity= 1.96 * (2020_Base_Capacity + 2020_Incremental_Capacity)204028,8121.96 *2030_Base_Capacity+ 1.96 *2030_Incremental_Capacity= 1.96 * (2030_Base_Capacity + 2030_Incremental_Capacity)205056,4721.96 *2040_Base_Capacity+ 1.96 *2040_Incremental_Capacity= 1.96 * (2040_Base_Capacity + 2040_Incremental_Capacity)Maximum Possible New Nuclear Capacity Deployment AllowedDeployment Starts 2020Deployment Starts 2030Deployment Starts 2040Deployment Starts 2050RunYearIncrementalCumulativeIncrementalCumulativeIncrementalCumulativeIncrementalCumulative20207,5007,500000000203029,40036,90014,70014,7000000204086,436123,33657,62472,32428,81228,812002050225,886349,222169,415241,739112,943141,75556,47256,472Notes:No nuclear deployment is allowed before 20201Addtional new nuclearcapacity deployment isonlypossible if nuclear capacity has beenbuilt in the previous run year.Appendix 3-8.2Maximum Possible Cumulative New Nuclear Capacity Each Run Year0 50,000 100,000 150,000 200,000 250,000 300,000 350,0002020203020402050Run YearsCapacity (MW)Deployment Starts 2020Deployment Starts 2030Deployment Starts 2040Deployment 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