Technical Support Document (TSD) for 

New Source Performance Standards for Carbon Pollution from 

Electric Utility Generating Units (EGUs) 

Docket ID No. EPA-HQ-OAR-2013-0495 

Docket ID No. EPA-HQ-OAR-2013-0603 

Achievability of NSPS 

for Fired Combustion Turbines 

U.S. Environmental Protection Agency 

Office of Air and Radiation 

August, 2015 
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Summary

To establish an appropriate standard for combustion 

turbines, we reviewed the emissions rates of natural 

gas-fired (non-CHP) combined cycle units in the 

power sector that commenced operation on or after 

January 1, 2000. We only considered EGUs that 

reported both the electrical output from the 

combustion turbine-generator and the steam turbinegenerator. 

Introduction

The purpose of this study is to determine how existing 

natural gas-fired1 combined cycle (NGCC) units have 

performed in comparison to the final standards. The 

study is based on hourly emissions and operating data reported to the Environmental Protection Agency (EPA) 

and to the Energy Information Administration (EIA). Approximately 4,700 electricity generating units2

 are 

subject to the Acid Rain or Clean Air Interstate Rule programs. Of these, some 1,000 are NGCC units located 

in 41 states that encompass a diverse population in terms of capacity, years of service and configuration. This 

study also explores the extent that operational and geographic factors (such as cycling, ambient temperature, 

and elevation) affect CO2 emission rates and thermal efficiencies. Manufacturers of NGCC technologies are 

continuously improving the capabilities of these units to serve a broad range of system load profiles while 

improving thermal efficiencies3 to reduce marginal fuel costs. Since this study is retrospective (i.e., this study 

is evaluating the performance of older, less-efficient NGCC technologies), this study is inherently 

conservative because the performance of new sources with the latest technologies for optimizing efficiencies 

is expected to result in lower emissions given similar operating profiles. Additionally, this study has been 

updated since the proposed rule to include operating data through 2014 that reflects any changes in 

performance attributable to the increasing use of intermittent renewables, particularly in the western United 

States. 

The term ‘unit’ here refers to a natural gas-fired combustion turbine, heat recovery steam generator, and any 

duct burners associated with a particular set of electricity generators together in various configurations; these 

components taken together are commonly called combined cycle “power blocks.” These configurations 

generally fall into two groups: (1) single-shaft power blocks, where the combustion turbine, steam turbine, 

and electricity generator all share a common shaft; and (2) multiple-shaft power blocks, where each 

combustion turbine in the power block shares a shaft with a separate electricity generator and the steam 

turbine in the power block is on a completely separate shaft with an additional electricity generator. In this 

analysis when referring to various counts, we are referring to the number of combustion turbines. The 

analysis includes operating data from 345 combustion turbines within combined cycle power blocks. 

The analysis covers monthly emissions and operating data from 2007 to 2014. The study includes only 

those months where both CO2 emissions and gross MWh output were greater than zero. Not all units ran 

for all 96 months so the total number of ‘unit operating months’ used in this analysis is 22,913 out of 

                                                            

1 Natural gas refers to the primary fuel as reported to the EPA and includes both ‘Natural Gas’ and ‘Pipeline Natural Gas’. ‘Process

Gas’ and ‘Other Gas’ units, typically associated with industrial production, are excluded.

2 An electricity generating unit may be referred to as a ‘facility’ under NSPS 3 http://www.westgov.org/wieb/electric/Transmission%20Protocol/SSG‐WI/pnw_5pp_02.pdf See vintage heat rate improvement;

the annual average is assumed to improve ‐0.6% per year over 2002‐25.

Abbrev.

CHP 

CO2 

EGU 

EPA 

MMBtu 

MW 

MWh 

NGCC 

combined heat and power 

carbon dioxide 

electric generating unit 

U.S. Environmental Protection Agency 

million British thermal units (unit of energy) 

megawatt(s) – one million watts 

megawatt-hour(s) 

natural gas combined cycle 
Page | 3

33,120 potential unit operating months included in the study period. 

Emissions and operating data used in this analysis are publically available for download, including unit 

capacity, fuel type, monthly operating time, CO2 emissions and gross output in megawatt hours (MWh).4

The publically available data is essentially the same data that would be used for compliance 

determinations since there is no bias adjustment5 in Appendix G of Part 75 for units using fuel meters to 

determine CO2 emissions. 

The unit population is filtered 

to include only those NGCC 

units that report natural gas or 

pipeline natural gas as the 

primary fuel, are in the 

electric utility or small power 

producer source categories 

and have commercial 

operation dates on or after 

January 1, 2000. In addition, 

the study is limited to those 

units that reported gross 

output data from both the 

primary combustion turbine 

and steam generator during 

the study period.6 The study 

also excludes all units at 

plants where combined heat 

and power (i.e., cogeneration) is reported.7

The resulting population of 345 NGCC units is heterogeneous in location, age, capacity and operating 

profile. They are located in 35 states and all 10 EPA regions, as shown in Table 1. Both large and 

small states are represented, including California with 43 units and Rhode Island with 3. 

Table 2 summarizes the study population by the year they entered service from 2000 through 2013. The 

average study unit has been in service for over 8 years. The study population includes 11 units that our 

research determined were retrofits or conversions of simple cycle turbines to NGCC or that operated in 

single cycle mode for a period of time during commencement of operations. In output capacity, the units 

range from 62 to 480 MW with an average capacity of 320 MW. The mean annual percent electric sales 

during the study period was 37 percent, but ranged from a low of 32 percent in 2008 to a high of 44 percent 

in 2012. Between 2007 and 2014, the annual CO2 rate, expressed in pounds of CO2 per megawatt hour of 

gross output (lb CO2/MWh), was consistently in the range of 780 to 980 lb CO2/MWh, while the count of 

operating units grew from 264 to 345. 

                                                            

4 Data is available at http://ampd.epa.gov/ampd/. 5 See part 75 in Volume 40 of the Code of Federal Regulations (CFR) originally published in January 1993. 6 Reporting output from the steam generator is optional. See 40 CFR part 75. 7 Excludes units at plants with any cogeneration or CHP noted in eGRID, Greenhouse Gas Reporting Program, CAMD, Ventyx (EIA), or

NEEDs databases.

State EPA 

Region

Units MW 

Capacity

State EPA 

Region

Units MW 

Capacity

State EPA 

Region

Units MW 

Capacity

AL 4 20 6,750 MA 1 2 858 OH 5 10 3,518

AR 6 20 4,854 ME 1 3 908 OK 6 19 6,349

AZ 9 22 7,274 MI 5 3 1,206 PA 3 12 3,682

CA 9 43 11,587 MN 5 6 1,993 RI 1 3 921

CO 8 5 1,101 MO 7 2 508 SD 5 1 310

CT 1 4 1,292 MS 4 16 5,114 TN 4 5 1,709

FL 4 27 10,690 NE 7 2 290 TX 6 35 10,676

GA 4 14 5,720 NV 9 6 1,944 UT 8 5 1,341

ID 10 1 314 NH 1 2 580 VA 3 7 2,322

IL 5 8 2,475 NM 6 4 1,250 WA 10 4 1,282

IN 5 2 690 NY 2 11 3,666 WI 5 8 2,799

LA 6 7 2,225 NC 4 6 2,258

Table 1. Study Units by EPA region and State
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Table 2. Study Units by Age and Capacity 

Year in Service Units Capacity (MW) 

2000 22 5,970 

2001 33 10,401 

2002 71 20,647 

2003 62 21,392 

2004 18 5,582 

2005 34 9,960 

2006 9 3,131 

2007 6 1,605 

2008 26 9,084 

2009 13 5,165 

2010 9 3,387 

2011 24 7,578 

2012 14 5,150 

2013 4 1,404 

Level of the Standard 

The final rule establishes three subcategories for base load, non-base load, and multi-fuel-fired combustion 

turbines. These subcategories reflect the degree of limitation that is achievable for specific classes of EGUs 

based on their percentage electric sales and percentage of natural gas use. The level of the standard for each 

of the subcategories is discussed in the following sections: 

Standard for the Base Load Natural Gas-fired Subcategory. The final standard for the base load natural 

gas-fired subcategory is 1,000 lbs CO2/MWh. This standard reflects the degree of emission limitation that 

has been demonstrated by combined cycle combustion turbines firing more than 90 percent natural gas (on a 

heat input basis) during periods when the percentage of electric sales is greater than 50 percent. The final 

standard is based on combined cycle performance that has been demonstrated across the full range of midto high-load conditions from combined cycle units. However applicability of the standard is not limited to 

combined cycle units. The standard applies to any combustion turbine during 12-operating month rolling 

periods when natural gas provides more than 90 percent of heat input, if the 12-month period occurs within a 

3-year rolling period8 when the EGU supplies more than its design efficiency9 times its potential electric 

                                                            

8 The base load electric sales criteria includes both a 12‐operating month and 3 year electric sales threshold. Throughout this

document we are simple using the shorthand of 3 year electric sales threshold. 9 The unit‐specific percent electric sales applicability threshold is based on the design efficiency of the combined cycle power block,

but the threshold threshold cannot exceed 50 percent. For example, a new combined cycle power block with a design efficiency at

baseload conditions of 57 percent would be subcategorized as a base load unit during a year when the actual percent electric sales

was 52 percent, but this same unit would be subcategorized as a non‐baseload unit during a year when the actual percent electric
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output as net-electric sales. Based on analysis of this data we have determined that a standard of 1,000 lb 

CO2/MWh-g is achievable for natural gas-fired base load combustion turbines regardless of size. Therefore, 

the final rule does not include subcategories for small and large combustion turbines. In addition, based on 

comparing the cost of electricity from simple cycle and combined cycle units, it is cost effective to use a 

combined cycle unit when operating as a base load unit. Therefore, this final rule has minimal compliance 

costs since it is cost effective based on fuel savings alone. The costing analysis compared the generation 

costs of advanced combine units to advanced simple cycle units. The EPA notes that the distinction between 

“advanced” and “conventional” is based on incremental design improvements. Table 3 presents the EIA 

definitions for these two classes of combined cycle technologies. 

  Table 3: EIA Definitions of Combined Cycle Design Classes

Conventional Natural Gas Combined Cycle (NGCC) 

The Conventional NGCC produces 620 MW of net electricity. The facility utilizes 2 natural gas-fueled F5-class 

CTs and associated electric generators, 2 supplemental-fired heat recovery steam generators (“HRSG”), and 1 

condensing ST and associated electric generator operating in combined-cycle mode. Each CT is designed to 

produce nominally 205 MW and includes a dry-low NOX combustion system and a hydrogen-cooled electric 

generator. The 2 triple-pressure HRSGs include integrated deaerators, SCRs, oxidation catalyst for control of 

carbon monoxide and supplemental duct firing with combustion management. The ST is a single-reheat condensing 

ST designed for variable pressure operation, designed to produce an additional 210 MW. The ST exhaust is cooled 

in a closed-loop condenser system with a mechanical draft cooling tower. The CTs are equipped with inlet 

evaporative coolers to reduce the temperature of the turbine inlet air to increase summer output. The Conventional 

NGCC plant also includes a raw water treatment system consisting of clarifiers and filters and a turbine hall, in 

which the CTs, ST, and HRSGs are enclosed to avoid freezing during periods of cold ambient temperatures. 

Advanced Generation Natural Gas Combined Cycle (AG-NGCC) 

The Advanced Generation (“AG”)-NGCC design is the same as the Conventional NGCC, except an H-class CT is 

utilized in lieu of F-class, and there is only one CT/HRSG supporting the ST included. Since the H-class CT design 

employs steam cooling of both stationary and rotational hot parts, the HRSG systems and the ST are both 

considered “advanced” designs, as compared to the Conventional NGCC. The AG-NGCC has advantages 

compared to the Conventional NGCC. The advantages of the AG-NGCC are for the same size of equipment – more 

megawatt output due to higher firing temperature. The higher firing temperature is due to more technically 

advanced metallurgy, coatings, and blade cooling systems. The AG-NGCC may or may not have a better ramping 

rate depending on the geographical location of the facility. The net output of the AG-NGCC is 400 MW. 

Compliance Calculations

Compliance with the standard in the final rule is determined by calculating the 12-operating month rolling 

average. To calculate compliance for a given unit, the unit’s total CO2 emissions over the twelve previous 

operating months is divided by either the unit’s total energy output (in MWh) or the total energy input (in 

MMBtu) over that period. The generalized formula is: 

A = C / M

A is the 12-operating month rolling average (lb CO2/MWh or lb CO2/MMBtu). 

C is total CO2 emissions for the 12 month periods in pounds. 

For base load units, M is total energy output for the 12 month period in MWh. 

For non-base load, M is the total heat input from all fuels fired. 

                                                            

sales was 48 percent.  
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Since the study period is 96 months long the maximum number of rolling average results is 85. An 

‘exceedance,’ as used here, means that a unit exceeded the applicable subcategory standard of performance for 

one 12-month rolling average. Since the calculation only includes operating months, the actual time span 

covered may be more than a calendar year. For example, if a unit started operation in January 2007, but did not 

operate in March of that year, the first rolling average would not be available until the end of January 2008. 

Unless stated otherwise, the term ‘CO2 rate’ as used here means the 12-month rolling average CO2 emission 

rate. 

There are a number of advantages to using this approach. A 12-month rolling average balances seasonal 

variations in thermal performance because EGUs may perform differently in winter than in summer and use of 

a 12-month average reflects the overall performance of the unit across all meteorological conditions. 

Additionally, the standard applies at all times including periods of startup, shutdown, and malfunctions. Use of 

a 12-month period allows sufficient time for a unit to off-set the unavoidable efficiency penalty that occurs 

during unit start up. 

Fleet Averages

The EPA calculated the 12-month rolling averages for this study using hourly unit emissions data aggregated 

to the monthly level. The key parameters examined are monthly CO2 mass (lbs), gross output (MWh), and 

operating time (hours). The calculation is based on operating months (i.e., months in which both CO2 mass 

emissions and gross output are greater than zero). The fleet average monthly CO2 rate9 for all study units is 

857 lb CO2/MWh with a distribution, s h o w n i n Figure 1, which is slightly right-tailed due to four units 

with higher rates that exceeded three standard deviations from the mean. 

Figure 1: Study Unit 12-Month Average CO2 Rate Distribution 2007-2014

The average unit percentage electric sales for all units was 37 percent. This average was comprised of a 

wide range of percentage electric with the 2nd percentile value equal to 3 percent and the 98th percentile 

value equal to 70 percent.10 Similarly, the 12-month average emission rates was comprised of a wide range 

                                                            

10 Eight‐year percentage electric sales include only years with MW generation reported. Normal Distribution

0

0.001

0.002

0.003

0.004

0.005

0.006

600 800 1,000 1,200 1,400 1,600

All 12‐Month Averages of Study Units

lb CO2/MWh
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of values with the 2nd percentile equal to 754 lbs CO2 per MWh and the 98th percentile value equal to 

1065 lbs CO2/MWh. 

Exceedances

Out of 345 units, 320 had no exceedances during the eight year study period even without filtering out 

periods of operation as non-base load units. However, without filtering out periods of operation as nonbase load units this overestimates the number of actual exceedances. The base load standard is only 

applicable during 12-month averages where the percentage electric sales are above the threshold. 

Twenty four of the units appeared to be operating as non-base load units when the exceeding an 

emission rate of 1,000 lb CO2/MWh-g. Therefore, essentially all the NGCC units in this analysis have 

demonstrated that the base load natural gas-fired combustion turbine standard included in this final rule is 

achievable. 

Site Specific Factors 

Many commenters stated that the EPA needs to account for site specific factors such as ambient conditions 

(e.g., temperature and elevation), operating parameters (e.g., number of starts), cooling type, degredation, and 

the use of backup fuel. No comments were submitted that changed our analysis at proposal for the first two 

factors (ambient conditions and operating parameters). As described in the preamble to this final rule, units 

with dry cooling towers had an average 12-operating month maximum emission rate of 875 lb CO2/MWh-g. 

This is lower than the fleet average 12-operating month maximum emission rate of 897 lb CO2/MWh-g. 

Therefore, the final base load standard has been demonstrated as achievable by units electing to use dry 

cooling systems. To evaluate degredation, the EPA determined the change in the average annual emission 

rate. Overall, the median annual emission rates of individual units is decreasing at 0.10 percent. Therefore, 

the average emission rate for individual NGCC units is essentially constant with limited degredation evident 

in the data. Due to two factors, the use of backup fuel would in theory increase the emission rate of a base 

load unit by approximately 4 percent. First, according to Gas Turbine World, the heat rate will increase 

between 1 to 2 percent when firing distillate oil relative to the heat rate when firing natural gas. The 

efficiency impact would be negligible for base load units since it is limited to units burned greater than 90 

percent natural gas. The primary factor increasing the emission rate is the relative carbon content of the fuels. 

Co-firing 10 percent distillate oil increases the emission rate on a lb/MMBtu basis by slightly less than 4 

percent relative to burning 100 percent natural gas. However, the vast majority of units operating at base load 

conditions (i.e., percentage of electric sales of greater than 50 percent) have a maximum 12-operating month 

average of less than 960 lb CO2/MWh-g. Therefore, the final standard in this rule includes sufficient 

compliance margin for the use of backup fuels. 

Temperature

Combustion turbines generally are less efficient when ambient temperatures are highest, however, a 

comparison of winter monthly (December, January and February) to summer monthly (June, July, August) 

rolling average CO2 rates in this study found no difference overall in the NGCC CO2 emission rate. Both 

time periods had nearly identical fleet average CO2 rates of 863 lb CO2/MWh. Less than half of the units 

operating in both time periods, had lower rolling average rates in the summer months. 

Using the actual monthly summer-winter monthly data (rather than the 12-month rolling average CO2 rate) finds 

that about 60% of the units with both summer and winter data sets had lower rates in the winter months. This 

finding is consistent with manufacturer performance specifications for winter and summer operating conditions. 

Looking at individual cases, two of the four units with the highest percentage difference in actual CO2 rate, i.e., 

2-4 % higher in summer months, had exceedances. However, those units are the exception. Over 93 percent of 

the units with higher actual monthly CO2 rates in summer still met the standard with no exceedances. For the 

majority of post-2000 NGCC units, the 12-month rolling average CO2 rate avoids exceedances by smoothing 
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out any increases in CO2 rate that may occur due to ambient temperature. 

Pollution Controls

All the units in this study are assumed to be equipped with low NOX burners. Nearly 90 percent are also 

equipped with selective catalytic reduction (SCR) NOX controls. No correlation between the presence of an 

SCR and higher average CO2 emission rates was evident. In fact, five of the units with exceedances did not 

have an SCR during the study period. 

Cycling

NGCC units can cycle frequently. An examination of starts, defined here as the initiation of fuel consumption, 

found that the average unit started 106 times per calendar year over the study period. Several units in this 

study cycled over 300 times per calendar year, (i.e., the equivalent of starting up every weekday). The data 

indicates that NGCC units can cycle very efficiently. There is no correlation between the number of starts 

and exceedances. Figure 3 plots the count of starts 2007-2011 (on the X axis) against the average CO2 rate 

for each unit (on the Y axis). The CO2 rates are evenly distributed around the mean and show limited 

correlation to the starts. Of the top 50 units with the most starts, only three had exceedances. The average CO2 

rate of the top ten cycling units, measured by start count over the study period, was 882 lb CO2/MWh, which 

is well below the performance standard. 
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FIGURE 2: Unit Start Ups and Average CO2 Rate 2007-2011

Elevation

The elevation of the units in this study ranges from 1 to 5,276 feet above sea level. There is no correlation 

between the elevation of a study unit and either the number of exceedances or the average CO2 rate. None of 

the units with exceedances is located above 1,500 feet. Fifteen units operated at elevations above 4,200 feet 

and had no exceedances during the study period. The average CO2 rate for the fifteen units at altitudes over 

4,000 feet is 862 lbs CO2/MWh, which would indicate that new units situated at higher elevations can 

maintain a high standard of efficiency. 

Figure 3: Unit Elevation and Average CO2 Rate 2007-2011

   

 
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Standard for the Non-base Load Natural Gas-fired Subcategory. 

The final standard for the non-base load natural gas-fired subcategory is 120 lbs CO2 per MMBtu of heat 

input. This standard reflects the degree of emission limitation demonstrated by combustion turbines firing 

more than 90 percent natural gas (on a heat input basis) during periods when these units have percentage 

electric sales less than or equal to their design efficiency times their potential electric output. The final 

standard is based on use of natural gas (with a small allowance for use of a backup fuel) and encompasses 

the levels of performance demonstrated by both combined cycle and simple cycle natural gas-fired turbines 

during periods when they operate at as non-base lod units. This standard applies to any combustion turbine 

during 12-operating month rolling periods when natural gas provides more than 90 percent of heat input, if 

the 12-month period occurs within a 3-year rolling period when the EGU supplies less than its design 

efficiency times its potential electric output as net-electric sales. As described in the preamble to this final 

rule, this standard is readily achievable. 

Standard for the Multi-fuel-fired Subcategory. 

The final standard for the multi-fuel-fired subcategory ranges from 120 to 160 lbs CO2 per MMBtu of heat 

input. The specific standard that applies during a particular compliance period is proportional to the fraction 

of total heat input derived from natural gas. This standard reflects the degree of emission limitation 

demonstrated by combustion turbines firing less than or equal to 90 percent natural gas (heat input basis). The 

final standard is based on the use of clean fuels with average carbon contents within the range encompassed 

by natural gas on the lower end and distillate fuel oil on the upper end. This range encompasses the levels of 

performance demonstrated by both combined cycle and simple cycle turbines during periods when firing 

backup fuels or industrial by-product gases. This standard applies to any combustion turbine that is connected 

to a natural gas pipeline during 12-operating month periods when natural gas provides less than 90 percent of 

heat input. 

Combustion turbines in this subcategory are required to perform periodic fuel sampling when firing residual 

fuel oils and non-uniform fuels such as refinery fuel gas. Operators firing gases that already contain CO2

(prior to combustion) may elect to utilize periodic sampling to determine the quantity of CO2 in the stream 

prior to combustion and may exclude this portion from the compliance calculation. 

According to the final data published by both CAMD and the EIA for 2013, natural gas was used to generate 

more than 98 percent of all the electricity delivered to the grid by combustion turbines with nameplate 

capacities greater than 25 MW. Table 4 presents 2013 data from EIA summarizing the generation from 

combustion turbines firing non-natural gas fuels. These data show that the primary, non-natural gas fuels used 

by combustion turbines for the production of electricity are fuel gas, residual fuel oil, distillate fuel oil, 

kerosene, and jet fuel. It is noteworthy that the EIA data indicate that the majority of the combustion turbines 

using these non-natural gas fuels are associate with combined heat and power operations. The final rule 

includes an option for such CHP operators to take a permit limit on electric sales to avoid applicability of the 

NSPS. As shown in Table 4 the carbon contents of these non-natural gas fuels range from 118 to 180 lbs 

CO2/MMBtu HHV. The BSER is based on a weighted average emission limit for periods when natural gas is 

fired with other fuels in order to limit the usage of high carbon fuels such as high-carbon residual fuel oils. 

However, the BSER allows continued use of distillate oils 1 and 2, jet fuel, fuel gas, propane, and liquefied 

petroleum gas. 

 
Page | 11

Table 4. Non‐natural Gas Fuel Use for Electricity Generation11 

Fuel Average Carbon Content12 Fraction of National 

Net Generation 

Other Gas13 (fuel gas, propane, 

liquefied petroleum gas)14

115 to 139 lbs CO2/MMBtu 0.49 percent 

Coal-derived synthesis gas Not applicable; units are subject 

to IGCC standard. 

0.19 percent 

Residual Fuel Oil (Nos. 5 and 6 and 

bunker C) 

161 to 177 lbs CO2/MMBtu 0.14 percent 

Pet. Coke-derived synthesis gas Not applicable; units are subject 

to IGCC standard. 

0.14 percent 

Distillate fuel oils (Nos. 1, 2, and 4) 161 to 166 lbs CO2/MMBtu 0.09 percent 

Kerosene and jet fuel 159 to 166 lbs CO2/MMBtu 0.05 percent 

Other biomass gases and liquids 115 to 180 lbs CO2/MMBtu 0.01 percent 

                                                            

11 Usage is based on EIA 923 data for RY2013. 12 Average carbon contents taken from Table C‐1 of 40 CFR Part 98 and

http://www.wiley.com/legacy/wileychi/morvayindustrial/supp/toolbox5.pdf

13 The petroleum refining and chemicals sectors reported 0.28 of the 0.49 % shown; the balance was reported by the utilities sector. 14   EIA does not publish specific fuels within the "Other Gas" fuel code, however EIA does publish the NAICS codes for facilities

reporting this fuel code. The specific fuels listed are the gaseous fuels reported to 40 CFR Part 98 from the NAICS codes that also

reported electricity generation to EIA associated with the "Other Gas" fuel code.