From: Szabo, Aaron <Aaron_L_Szabo@omb.eop.gov> 

Sent: Thursday, July 30, 2015 9:58 AM 

To: Vasu, Amy; Culligan, Kevin; Harvey, Reid 

Cc: Frey, Nathan J.; Grossman, Andrea 

Subject: Summary of Interagency Comments Under EO 12866 and 13563 -- GHG Mitigation 

TSD BB1 

Attached please find a summary of interagency comments under EO 12866 and 13563 on the BB1 

chapter (Chapter 3) of the GHG Mitigation TSD. 

 

Thank you and please let know if you have any questions. 

Aaron L. Szabo 

Policy Analyst 

Office of Management and Budget 

202-395-3621 

Aaron_L_Szabo@omb.eop.gov 

<< SummaryOfInteragencyCommentsUnder_EO12866_EO13563_GHG Mitigation 

TSD_BB1.docx >> 

 

 
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Chapter 2: CO2 intensity reductions through heat rate improvements at 

existing coal fired electricity generating units 

This Technical Support Document (TSD) incorporates by reference the materials found 

in the Clarified Technical Support Document (TSD) for Carbon Pollution Guidelines for Existing 

Power Plants: Emission Guidelines for Greenhouse Gas Emissions from Existing Stationary 

Sources: Electric Utility Generating Units: GHG Abatement Measures as well as the Dataset 

related to Chapter 2 of the GHG Abatement Measures TSD, including inter alia the description 

of the data and methodology, analytical results, illustrative equipment upgrades, costs, and 

datasets.1

2.0 Overview 

The heat rate of coal-fired electricity generating units (EGUs) is the amount of energy 

required to generate each kilowatt-hour (kWh) of electricity. The more efficiently an EGU 

converts the energy embedded in coal into electricity, the lower the EGU’s heat rate and, 

correspondingly, the lower its CO2 intensity (CO2 lb/kWh). Because heat rate improvements 

reduce fuel consumption, improving coal-fired EGUs’ heat rates can be a cost-effective method 

of reducing the CO2 intensity of the power system as a whole.2

 In addition, it can provide 

additional economic benefits from reduced fuel costs. 

To assess the potential heat rate improvements of existing coal-fired EGUs, EPA 

analyzed historical gross heat rate data from 2002 to 2012 for 884 coal-fired EGUs that reported 

both heat input and gross electricity output to the agency in 2012. The agency grouped the EGUs 

by regional interconnections – Western, Texas, and Eastern – and analyzed potential heat rate 

improvements within each interconnection using three analytical approaches. The approaches 

compare each EGU’s “best” or “benchmark” historical gross heat rates against the EGU’s 2012 

gross heat rate. By founding the methodology on unitspecific comparisons between an EGU’s historical and 

baseline performances, the analyses control for 

variations in EGU design and largely obviate the need 

for subcategorization. By using the 2012 gross heat rate 

as the baseline, the analyses account for actions that 

individual EGUs have taken to improve gross heat rate. 

Accordingly, the results identify the overall heat rate 

improvements that will result if the coal-fired EGUs 

simply returned to their demonstrated and achievable 

past performance. 

 1

 See Clarified Technical Support Document (TSD) for Carbon Pollution Guidelines for Existing Power Plants: 

Emission Guidelines for Greenhouse Gas Emissions from Existing Stationary Sources: Electric Utility Generating 

Units; GHG Abatement Measures, Docket No. EPA-HQ-OAR-2013-0602-17180 (Sept. 16, 2014), available at

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0602-17180; Dataset related to Chapter 2 of 

the GHG Abatement Measures TSD, Docket No. EPA-HQ-OAR-2013-0602-0238 (June 8, 2014), available at

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0602-0238. 2

 Improving heat rate can result in a “rebound effect” that undermines the emissions reductions a coal-fired EGU 

would otherwise achieve. For a detailed discussion of the consequences of the rebound effect for building block 1 

and the best system of emission reductions, see sections V.A and V.C of the final rule preamble of the CPP. 

Abbreviations 

Btu British thermal unit 

CONUS contiguous U.S. 

EGU electricity generating unit 

kWh kilowatt hour 

MW megawatt 
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The first approach, “best historical average performance,” compared each EGU’s best 1- 

and 2-year average gross heat rates to the EGU’s 2012 gross heat rate. For the second and third 

approach, the agency controlled for select conditions beyond the EGU operator’s control – 

hourly capacity factor and hourly ambient air temperature. These two conditions account for 

approximately 26 percent of variation in gross heat rate for the 884 coal-fired EGUs between 

2002 and 2012. To control for these conditions, the agency grouped data by hours with similar 

hourly capacity factors (using 10 percent increments) and hourly ambient air temperature 

conditions (using 10° F ranges). In the second approach, “best historical average performance 

under similar conditions,” the agency compared each EGU’s best 1- and 2-year average gross 

heat rates in each capacity-temperature group against the EGU’s 2012 gross heat rate for the 

capacity-temperature group. For the third approach, “efficiency and consistency improvements 

under similar conditions,” the agency identified “benchmarks” for each EGU equal to the EGU’s 

lowest hourly gross heat rate (characterized as the 10th percentile value over 1- and 2-year 

periods) for each capacity-temperature group.3

 Then the agency determined the heat rate that 

could be achieved if the EGU implemented measures to operate more consistently nearer the 

“benchmark.” 

The results of these three approaches indicate that there is significant potential for heat 

rate improvement ranging from 4.0 to 6.6 percent nationally if coal-fired EGUs return to their 

best past performance between 2002 to 2012. The most conservative approach that is supported 

by the weight of evidence yields average potential heat rate improvements of 2.1 percent in the 

Western Interconnection, 2.6 percent in the Texas Interconnection, and 4.3 percent in the Eastern 

Interconnection. 

2.1 Introduction 

Heat rate, a measure of efficiency for fossil fuel-fired EGUs, is commonly expressed as 

the amount of heat input in British thermal units (Btu) required to generate one kWh of 

electricity (Btu/kWh). As a coal-fired EGU’s heat rate improves (i.e., efficiency improves), less 

coal or other fuel is required to produce the same amount of electricity. Because less fuel is 

combusted, the amount of CO2 and other emissions (e.g., mercury, NOX, PM, SO2) released to 

the environment also declines. In addition to the clear environmental benefits of heat rate 

improvements, there are important economic co-benefits attributable to reduced fuel costs and 

coal combustion residue management and disposal costs. 

Heat rates of existing coal-fired EGUs in the U.S. vary substantially. The variation in 

heat rates among EGUs with similar design characteristics (e.g., boiler type, fuel type, size, 

cooling system) as well as year-to-year variation in heat rate at individual EGUs indicate that 

there is potential for broad efficiency improvements that can yield significant CO2 emission 

reductions and fuel savings for the existing coal-fired EGU fleet as a whole. This chapter 

presents (1) the characteristics of existing coal-fired EGUs in the US, including heat rate 

performance over time, (2) the impact that design characteristics and other factors may have on 

 3

 The third approach uses hourly values to determine a heat rate benchmark for each EGU for periods with similar 

hourly capacity factor and hourly ambient temperature conditions. Therefore, the agency determined it was 

appropriate to select the 10th percentile value to (1) control for unusually low hourly values and (2) set a benchmark 

with sufficient hourly measurements at or below the benchmark. The first and second approaches use annual 

averages so the agency did not determine it necessary to remove unusually low or unusually high heat rate values as 

the low and high values will generally balance out. 
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EGU heat rates, (3) additional equipment upgrades and practices that can improve efficiency at 

existing coal-fired EGUs, (4) the potential heat rate improvements from existing coal-fired EGUs 

that, when realized, would reduce CO2 emission intensity, and (5) responses to key comments 

about building block 1 of the proposed rule. 

2.2 Coal-fired EGUs 

Several different coal combustion configurations and technologies are used at existing 

coal-fired EGUs in the U.S. Nevertheless, they all commonly follow the same process for 

converting the energy stored within coal into electricity. Figure 2-1 depicts a pulverized coalfired EGU, the most widely used configuration in the U.S.4

 In general, coal is ground into small 

pieces or a fine powder, and then fed into a furnace where it is burned. The heat from coal 

combustion boils preheated water creating high-pressure high-temperature steam that is 

transported to a steam turbine-generator where the steam passes through, forcing the blades of 

the steam turbine to rotate, which in turn drives a generator to generate electricity. The steam 

drops in pressure and expands in volume as its energy is transferred to the turbine. After the 

steam has expanded, the exhaust steam is cooled in a heat exchanger (i.e., condenser). The water 

is then returned to the boiler to repeat the cycle. Coal combustion waste gases (i.e., flue gas), 

including various air emissions (e.g., CO2, mercury, NOX, PM, SO2), are drawn downstream 

from the furnace by fans and pass through pollution control devices before they are released 

from the stack to the atmosphere. 

Figure 2-1 Coal-fired EGU schematic 

Note: Used by permission. Courtesy of the Babcock & Wilcox Company.

2.2.1 Design characteristics and site-specific factors that affect heat rate 

 4

 For information about coal combustion configurations at coal-fired EGUs, see supra note 1. 
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A variety of design characteristics, site-specific factors, and operating conditions can 

affect the heat rate of existing coal-fired EGUs. Some of these factors are influenced by or are 

under the direct control of the EGU operator, but other factors may be beyond the operator’s 

control, such as: 

Thermodynamic cycle. The thermodynamic steam cycle of a coal-fired EGU indicates the range 

of steam temperatures and pressures used in the boiler and steam turbine. There are two common 

steam cycles: subcritical and supercritical. In general, the higher the steam temperature and 

pressure, the higher the efficiency of the EGU and the lower the heat rate. Existing subcritical 

boilers that operate below the critical pressure of water (approximately 22.1 MPa or 3,206 psia) 

generally have higher heat rates with design thermal efficiencies of around 35 percent while 

supercritical and ultrasupercritical EGUs that operate above the critical pressure of water may 

have design thermal efficiencies of 40 to 45 percent. In any case, actual thermal efficiencies in 

daily operation are usually lower than design values. 

Boiler and steam turbine size. In general as the size of the boiler and the steam turbine increase, 

heat rate decreases. Larger coal-fired EGUs generally have lower heat rates for technical and 

economic reasons. Furthermore, relative to smaller EGUs, the larger EGUs typically have lower 

percentages of draft loss, heat loss, and seal leakage, and also tend to use more advanced 

technologies. They also have economies of scale for investment, operation, and maintenance, and 

have higher capacity factors because they are often dispatched before smaller, less-efficient 

units. 

Cooling system. The design of the cooling system for existing coal-fired EGUs – once-through, 

recirculating (i.e., evaporative), or dry – is largely dependent on an EGU’s proximity to water 

resources, ecological concerns, and regulatory requirements. The cooling system design directly 

affects the steam turbine’s ability to extract energy from the steam and affects overall efficiency. 

The amount of energy that the steam turbine can extract from the steam depends on the steam 

temperature and pressure, as stated above, as well as condenser pressure (affected by the cooling 

system design, condenser cleanliness, EGU load, and ambient cooling water or air temperature). 

At a lower condenser pressure (within design limits), more energy can be extracted by the steam 

turbine, with a resulting lower EGU heat rate. 

Auxiliary equipment. Auxiliary equipment, such as pumps, fans, pulverizers, and pollution 

control devices, require power to run, thereby consuming some of the electricity generation onsite and reducing the amount of electricity output available for use on the electricity grid. These 

systems vary in efficiency based on design, age, and usage. 

Geographic location. Ambient conditions at the plant location (e.g., seasonal ambient 

temperatures, cooling water temperatures) affect an EGU’s heat rate. Ambient air is mixed with 

the fuel prior to combustion, and a fraction of energy released during combustion heats the 

incoming air, increasing heat rate. On the other hand, cooler water temperatures improve the 

efficiency of the cooling system, thereby reducing heat rate. Colder cooling water (or ambient air 

for dry cooling systems) in the condenser reduces the back pressure in the condenser, allowing 

for more energy to be extracted by the steam turbine. 

Coal rank and quality. Higher rank coals (e.g., bituminous) tend to have higher energy contents 

(i.e., carbon content), burn more intensely, and have a lower moisture content than mid-rank 

(e.g., subbituminous) and low-rank (e.g., lignite) coals. In general, the lower the moisture content 

of coal, the less energy that is needed to evaporate the moisture and, therefore, the more energy 
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that is available for producing steam, thus lowering heat rate. The ash content of the coal can 

also affect heat rate. All coal fuels produce ash that accumulates on heat transfer surfaces (i.e., 

metallic tubes) and impedes energy transfer to the steam. While systems are designed to remove 

this “soot,” the quantity present between surface cleanings hinders energy transfer and results in 

higher heat rates. All EGU’s are designed to burn a specific, range of fuels, often within a single 

rank – deviating from the intended design can negatively affect heat rate. However, some coalfired EGUs efficiently burn blends of different coal types. 

2.2.2 Regional electricity interconnections 

As discussed in sections V.A and V.C of the preamble for the final CPP rule and the 

associated CO2 Emission Performance Rate and Goal Computation Technical Support 

Document, EPA assessed the potential CO2 reductions achievable through each of the building 

blocks that comprise the best system of emission reduction. The agency conducted assessment at 

the level of the three large regional electricity interconnections: Western, Texas, and Eastern (see 

Figure 2-2). The Western Interconnection is a major power grid that comprises one North 

American Electric Reliability Corporation (NERC) region – the Western Electricity Coordinating 

Council (WECC). The Western Interconnection encompasses all or portions of 14 western states. 

The Texas Interconnection includes the portion of Texas managed by the Electric Reliability 

Council of Texas (ERCOT). The Eastern Interconnection is the other major regional power grid, 

comprising six NERC regions – Florida Reliability Coordinating Council (FRCC), Midwest 

Reliability Organization (MRO), Northeast Power Coordinating Council (NPCC), Reliability 

First Corporation (RFC), SERC Reliability Corporation (SERC), and Southwest Power Pool 

(SPP) – covering all or portions of 39 eastern and midwestern states. 

Each interconnection is a highly-connected electricity grid in which, during normal 

conditions, power generated in one part of the interconnection can help balance power generation 

and load in all other parts of the system. Therefore, each interconnection must carefully manage 

electricity generation and load to ensure safe and reliable electricity service. 

For the proposal, EPA analyzed the potential heat rate improvements from coal-fired 

EGUs at the national level. Some commenters suggested that EPA should adjust the analysis and 

develop state-specific estimates of potential heat rate improvements from coal-fired EGUs. 

While the agency carefully evaluated these comments, the agency determined that due to the 

highly interconnected nature of the electricity system, and as further discussed in section V.C.3 

of the final rule preamble, it is more appropriate in this rule to assess potential for heat rate 

improvements from existing coal-fired EGUs at the regional interconnection level than at the 

national or state level. 

2.2.3 Coal-fired EGUs in operation in 2012 

In 2012, there were 884 coal-fired EGUs5 at 367 power plants in the contiguous U.S. 

(CONUS) that reported hourly heat input and gross electricity generation to EPA’s Clean Air 

 5

 Excludes cogeneration, integrated gasification and combined cycle (IGCC), retired, and non-operational EGUs. 

EGUs that reported steam co-generation to EPA or EIA are excluded because only a portion of heat input is used to 

generate electricity while the remainder is used to generate steam, making it difficult to meaningfully compare these 

EGUs’ heat rates. IGCC units are excluded because they are not conventional steam boilers and may regularly use 

pipeline natural gas in lieu of syngas from coal gasification. EGUs retired prior to 2012 or EGUs that did not operate 
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Markets Division. These EGUs are spread across the CONUS (see Figure 2-2) in each of the 

three regional electricity interconnects. Of the 884 coal-fired EGUs, 93 (10.5 percent) are located 

in the Western Interconnection, 32 (3.5 percent) are located in the Texas Interconnection, and 

759 (86 percent) are located in the Eastern Interconnection. 

Figure 2-2 Power plants with coal-fired EGUs reporting heat input and gross electricity 

generation in 2012 

The population of 884 coal-fired EGUs includes units with a variety of design 

configurations and operating characteristics that can affect an EGU’s heat rate, such as 

thermodynamic steam cycle, coal rank and coal quality, boiler type, boiler size (i.e., maximum 

hourly heat input), and generator power output capacity. 

At the end of 2012, the age of the 884 coal-fired EGUs varied widely, ranging from less 

than 1 year to 68 years. Nationally, the average age was 42 years, but this differed among the 

interconnections. The Texas Interconnection had the lowest average age of existing coal-fired 

EGUs at 27 years followed by the Western Interconnection at 34 years. The average age of the 

coal-fired EGUs in the Eastern Interconnection was 44 years (see Figure 2-3). 

Similarly, electricity generating capacity of the 884 coal-fired EGUs varied widely within 

and between the interconnections. In 2012, the capacity ranged from 25 MW to nearly 1,500 

MW with a national average capacity of 385 MW.6

 In the Western Interconnection the average 

generator capacity of coal-fired EGUs was 390 MW, in the Texas Interconnection the average 

was 689 MW, and in the Eastern Interconnection the average was 372 MW (see Figure 2-4). 

 

in 2012 are also excluded because they do not have 2012 operating data necessary to estimate potential heat rate 

improvement. 

6

 EGU operators report maximum hourly load data to EPA/CAMD. This value may differ from the EGU’s 

nameplate capacity and summer net capacity. 
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Figure 2-3 Age (years) distribution of coal-fired EGUs in 2012, by interconnection 

Figure 2-4 Generator capacity (MW) distribution of coal-fired EGUs in 2012, by 

interconnection 

2.2.3.1 Historical gross heat rate trends of coal-fired EGUs 

Between 2002 and 2012, the average gross heat rates of the 884 coal-fired EGUs have 

fluctuated from year to year. Nationally, the average gross heat rate7

 declined between 2002 and 

2008 to a low of 9,645 Btu/kWh in 2008 and 2009 (see Figure 2-5). However, after 2009, the 

 7

 EPA used hourly heat input (Btu) and hourly gross electricity generation (kWh) to calculate the hourly gross heat 

rate (Btu/kWh). As described later in this chapter, gross generation was the only complete and accurate hourly 

dataset available to EPA. Therefore, unless otherwise noted, references to heat rate in this chapter refer to gross heat 

rate. 
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average annual gross heat rate of the 884 coal-fired EGUs began to deteriorate, climbing to 9,753 

Btu/kWh in 2012. 

The variation for each of the interconnection regions was more pronounced. The average 

annual gross heat rate of the 93 coal-fired EGUs in the Western Interconnection declined from 

nearly 10,458 Btu/kWh in 2002 to 9,888 Btu/kWh in 2012, just slightly higher than the lowest 

gross heat rate in 2010. The larger and relatively younger 32 coal-fired EGUs in the Texas 

Interconnection saw less change than those in the Western Interconnection. The lowest average 

gross heat rate for the Texas Interconnection occurred in 2009 and was only slightly higher in 

2012 (9,760 Btu/kWh and 9,789 Btu/kWh in 2009 and 2012, respectively). In the Eastern 

Interconnection, where 86 percent of the coal-fired EGUs are located, gross heat rates have 

steadily increased since 2008, rising from 9,567 Btu/kWh to 9,700 Btu/kWh. 

Figure 2-5 Gross heat rate trends of coal-fired EGUs, 2002-2012 by interconnection 

Notes: red dotted line represents the 11-year arithmetic average; 

axis does not start at zero to better illustrate trends in gross heat rate 

Commenters have offered a variety of opinions in an attempt to explain these gross heat 

rate trends over time, such as shifts from low-moisture bituminous coals to higher-moisture 

subbituminous coals from the Powder River Basin, installation of air pollution control devices in 

response to federal and state regulations, retirements of less-efficient coal-fired EGUs, 

fluctuations in precipitation and weather conditions, deterioration of plant equipment or deferral 

of equipment maintenance, or changes in dispatch patterns and capacity factors. EPA 

acknowledges that there are many factors that can affect the heat rate of coal-fired EGUs, some 

of which are within the EGU operator’s control and some that are not. In the analysis of potential 

heat rate improvements described below, the agency attempts to limit the influence of some of 

the factors outside the EGU operator’s control.

2.3 Heat rate improvement practices and equipment upgrades at coal-fired EGUs 

In the proposal TSD, EPA provided examples of best practices and equipment upgrades 

that may be available to existing coal-fired EGUs to improve heat rate and, as a result, reduce the 
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EGU’s CO2 emissions intensity.8

 Several commenters also provided extensive information about 

additional best practices and equipment upgrades that may be available for coal-fired EGUs to 

improve heat rate. Commenters also noted that many coal-fired EGUs have already implemented 

heat rate improvement measures for economic reasons and requiring EGUs to implement the 

measures again might not yield substantial benefits or might not be feasible. 

As explained in section 2.5 below and in preamble sections V.A and V.C, the agency has 

decided not to estimate a separate potential for heat rate improvements from equipment 

upgrades. As stated in the proposal TSD, the agency lacks reliable and complete information 

about the unit-level upgrades that coal-fired EGUs have already implemented and it is not 

practical for EPA to conduct engineering analyses at each coal-fired EGU for the purpose of 

answering the question about whether existing coal-fired EGUs are already taking advantage of 

all opportunities to improve heat rate. Nonetheless, the agency remains confident that there are 

additional opportunities for coal-fired EGUs to achieve heat rate improvements by implementing 

some combination of best practices and equipment upgrades, including the illustrative best 

practices and equipment upgrades shown below. The agency recognizes that the types and extent 

of capital improvements and operational and maintenance improvements available to individual 

coal-fired EGUs will vary. For this and other reasons stated below, the agency is therefore not 

basing the estimate of potential heat rate improvement on a specific proportion of best practices 

or equipment upgrades. 

The lists below are intended to provide examples of equipment upgrades and best 

practices to improve heat rates. While the agency believes these equipment upgrades and best 

practices are highly cost-effective, the agency recognizes that some EGUs (e.g., small EGUs) 

may not find each of the measures to be cost effective. In addition, the agency recognizes that 

not all measures are applicable to each and every EGU. Therefore, these lists are intended only to 

demonstrate the types of actions that EGUs might be able to implement or maintain to improve 

heat rate. 

2.3.1 Example equipment upgrades for heat rate improvement 

 Install intelligent sootblowing system 

 Replace feed water pump steam turbine seals 

 Overhaul high pressure feedwater pumps 

 Upgrade main steam turbine seals 

 Upgrade steam turbine internals 

 Install variable frequency drives for motors 

 Retube or expand the condenser 

 Install sorbent injection system to reduce flue gas sulfuric acid to allow lower 

temperature exhaust gas 

 Upgrade air heater baskets for lower temperature operation 

 Upgrade and repair flue gas desulfurization systems 

 Refurbish the economizer 

 Upgrade ESP components to lower auxiliary power consumption 

 8 See Clarified Technical Support Document, supra note 1 (discussing in greater detail some of the different types of 

equipment upgrades and best practices that coal-fired EGUs can employ to improve heat rate). 
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 Improve SCR and FGD system components to lower draft loss 

2.3.2 Example best practices for heat rate improvement 

 Adopt training for O&M staff on heat rate improvements 

 Perform on-site appraisals to identify areas for improved heat rate performance 

 Install neural network software for combustion/optimization with monitoring system 

for heat rate optimization 

 Repair steam and water leaks – replace leaking valves and steam traps 

 Replace / repair worn air heater seals 

 Manage feed water quality 

 Chemical clean boiler to remove scale build-up from water side 

 Install and operate condenser tube cleaning system 

 Repair boiler furnace and ductwork cracks to prevent boiler air in-leakage 

 Clean air preheater coils to restore performance 

 Adopt sliding pressure operation to reduce turbine throttling losses 

 Reduce activation of attemperator which compensates for over-firing the unit 

 Remove deposits on turbine blades 

2.3.3 Heat rate improvement measures identified by external studies 

There are a number of engineering studies that explore opportunities for improving the 

efficiency of existing coal-fired power plants, including studies by Sargent & Lundy and NETL 

that were referenced in the proposal TSD. Some of the practices and equipment upgrades have 

the potential to improve gross heat rate while others will not affect an EGU’s gross heat rate, but 

they will reduce the auxiliary load from on-site equipment, thereby improving the net heat rate 

(i.e., making more net electricity available for the same amount of fuel input). The following 

potential efficiency improvements in the boiler, turbine, flue gas system, air pollution control 

equipment, and the water treatment system are discussed below.9

2.3.3.1 Boiler systems 

2.3.3.1.1 Materials handling 

Materials handling includes the handling and transport of coal, the preparation of coal for 

combustion, and handling of combustion residues: 

 Coal-handling equipment requires about 0.07 percent (7 Btu/kWh) of an EGU’s gross 

electricity generation. Installation of energy-efficient motors and variable frequency 

drives can reduce auxiliary power requirements. 

 Coal pulverizers require about 0.6 percent (60 Btu/kWh) of an EGU’s gross 

electricity generation to prepare the coal for combustion. Upgrading the pulverizers to 

provide more consistent size and finer coal particles can improve the EGU’s 

combustion efficiency, produce less unburned coal, and consequently reduce fuel cost 

and gross heat rate. 

 9

 Chapter 2 of the proposal TSD provides a detailed description of numerous well-proven measures for improving 

heat rate at coal-fired EGUs. See supra note 1. 
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 Bottom ash handling equipment requires about 0.1 percent (10 Btu/kWh) of an 

EGU’s gross electricity generation. Switching from a water-sluicing bottom ash 

system to a dry system can reduce the auxiliary requirements and reduce the amount 

of wastewater to the water treatment plant. 

2.3.3.1.2 Boiler control system 

The boiler control system has a large impact on the gross heat rate of the unit. Commonly 

referred to as the DCS (Distributed Control System), this computer controls and displays many 

parameters affecting boiler operation. A neural network is an advanced control system utilizing 

artificial intelligence and installed in addition to the plant DCS. The neural network evaluates 

many parameters of the EGU’s operation and makes adaptive tuning based on statistical analysis 

to predict performance for increased efficiency. Many vendors offer neural network systems to 

improve the overall efficiency. These systems can offer gross heat rate improvements up to 150 

Btu/kWh. 

2.3.3.1.3 Steam turbine 

The steam turbine extracts energy from the steam and rotates a generator to produce 

electricity. Modern developments allow the steam turbine to extract more energy from the same 

amount of steam than was possible with equipment from decades ago. Replacing existing steam 

turbines with advanced designs or, where practical, upgrading turbines with improved internals 

can reduce gross heat rate by 100-300 Btu/kWh. As one commenter pointed out, Leyzerovich 

explains that upgrading and retrofitting a turbine at a 20-year old 500 to 700 MW coal-fired EGU 

can reduce heat rate by a total of about 4 percent.10

2.3.3.1.4 Feedwater heaters 

Boiler feedwater heaters pre-heat the water going to the boiler. The hotter the water 

entering the boiler, the less energy it takes to convert it to steam. Like any heat exchanger, EGUs 

can improve efficiency by removing built-up scale or increasing heat transfer surface area. 

Chemical cleaning removes scale and restores heat transfer efficiency. 

2.3.3.1.5 Condenser 

Condensers are subject to fouling and plugging, which directly impact the heat transfer 

efficiency and water quality. Closed cooling water systems can be used to provide better control 

over water quality and tube cleaning can be performed as needed. Condenser upgrades and 

maintenance typically improve gross heat rate by 30-70 Btu/kWh. 

2.3.3.1.6 Cooling tower 

The temperature of cooling water affects condenser performance. Supplying cold water 

allows the condenser to operate at lower pressures, which allows the steam turbine to extract 

more energy for power generation. As the cooling towers become fouled over time, the water 

returned to the condenser becomes warmer and negatively affects steam turbine performance and 

reduces gross electricity generated. Routine maintenance on the cooling towers might include 

 10 See AS Leyzerovich, 2007. Steam Turbines for Modern Fossil-Fuel Power Plants. CRC Press. ISBN 13: 978-

1420061024. 
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discarding accumulated debris, removing biologic growth, replacing defective fill material, 

ensuring uniform water distribution, correcting for uneven air distribution, verifying water flow 

rates, and replacing missing louvers 

2.3.3.1.7 Boiler feed water pumps 

Boiler feed pumps require a large amount of auxiliary power to pump large amounts of 

boiler feedwater through the heaters and the boiler. Due to their continuous operation, the pumps 

wear over time, lose efficiency, and require more energy to move the same volume of water. A 

pump overhaul restores efficiency, ensures reliability, and can reduce the net heat rate by 25-50 

Btu/kWh. 

2.3.3.1.8 Water Treatment System 

The quality of boiler water affects the rate of scale build-up on boiler tubes. Scale inhibits 

heat transfer and the EGU operator typically compensates by increasing the firing-rate to 

overcome this effect. Scale can reduce heat transfer up to 10 percent in severe cases. However, 

the higher the quality of water used in the boiler, the slower the scale build-up and thus the 

higher the efficiency of the EGU. Enhanced water treatment can reduce scale. In addition, scale 

can be removed through chemical cleaning to restore heat transfer and lower gross heat rate. 

The cooling water system can also suffer from poor water quality for the same reason – 

scale build-up fouls the heat transfer surfaces in the condenser, causing higher condenser 

temperatures and reducing the capability of the turbine to extract energy from the steam. 

Chemical cleaning and better water quality can mitigate the issue. 

2.3.3.1.9 Variable frequency drives 

Replacing fixed speed electric motors with variable frequency drives reduces auxiliary 

power requirements by reducing the drives’ speed (i.e., rpm) when maximum speed is not 

required. The net heat rate improvements can be 10-150 Btu/kWh. 

2.3.3.2 Flue gas and emission control technologies 

Equipment to move flue gases and control air pollution typically require large amounts of 

auxiliary power to properly operate equipment. Even small upgrades to the equipment can 

decrease auxiliary power requirements while maintaining emission reduction levels. 

2.3.3.2.1 Economizer 

The economizer extracts energy from the combustion gases as they exit the furnace. This 

energy is used to preheat the water returning to the boiler. This heat exchanger improves EGU 

efficiency by reducing the amount of fuel required to convert water into steam. The replacement 

or refurbishment of the economizer can lead to gross heat rate improvements of around 50-100 

Btu/kWh. 

2.3.3.2.2 Sootblowers 

Coal combustion produces ash that builds up on tubing surfaces, reducing heat transfer 

for steam generation and resulting in higher gross heat rates. Sootblowers remove built-up coal 

ash to restore performance of the heat transfer surfaces. Intelligent sootblowers monitor system 
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conditions and activate when boiler operation indicates the need to remove ash rather than 

activating at arbitrary time intervals set by operators. These systems use real-time furnace data to 

identify specific areas requiring ash removal. They can improve gross heat rates 30-150 

Btu/kWh. 

2.3.3.2.3 Air heaters 

Air heaters transfer heat between the incoming pre-combustion air and the exiting flue 

gas. By preheating the combustion air, less fuel is required to convert pre-heated water to steam. 

Due to their design, leakage can occur and, as a result, reduce the pre-combustion air 

temperature, requiring greater coal consumption. Leakage also increases auxiliary power 

requirements since equipment must now handle the increased volume of air from the in-leakage. 

Properly maintained air heaters limit leakage to below 6 percent. Reducing leakage can reduce 

the auxiliary power requirements and, therefore, the net heat rate by 10-40 Btu/kWh. 

Another method to improve heat rate is to extract more energy across the air heater to 

raise pre-combustion air temperature. Typically, the air heater outlet is maintained at 20-30°F 

above the sulfuric acid dew point to prevent corrosion. Depending on the air heater’s size, major 

modifications may be required to capture more energy, but the modifications might reduce gross 

heat rate by 50-120 Btu/kWh. 

2.3.3.2.4 Induced draft fans and forced draft fans 

Induced draft fans and forced draft fans typically operate at constant speed with dampers 

to control flue gas flow rate. Using dampers is the conventional choice to control flow while the 

fan motor runs at constant speed. However, newer methods are available to control flow for more 

efficient operation while reducing auxiliary load (e.g., variable frequency drives, variable pitch 

blades). These upgrades or replacements provide net heat rate improvements of 10-50 Btu/kWh. 

2.3.3.2.5 Flue gas desulfurization 

A variety of flue gas desulfurization systems are used at existing coal-fired EGUs. Some 

EGUs still employ outdated venturi-type designs that create large pressure drops and require 

greater auxiliary power to operate the induced draft fans. Upgraded designs, such as co-current 

spray tower quenchers, can replace the outdated designs and enhance net heat rate. 

A more common flue gas desulfurization technology installed throughout the fleet is a 

spray tower absorber, also known as a wet scrubber. Technology upgrades, including installing 

turning vanes to reduce pressure drop and improve gas flow, can reduces induced fan auxiliary 

power requirements and enhance net heat rate. 

2.3.3.2.6 Electrostatic precipitator 

Efficient electrostatic precipitator operation involves maintaining the maximum applied 

voltage, without arcing. Arcing represents lost energy unusable for particulate removal and 

requires the field be re-energized, consuming additional auxiliary power. Electrostatic 

precipitator upgrades improve performance by eliminating arcing and reducing auxiliary power 

consumption. 

2.3.3.2.7 Selective catalytic reduction 
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Innovations in selective catalytic reduction systems have reduced auxiliary energy 

requirements, such as the use of hot secondary air or auxiliary steam for heating system 

equipment (instead of electrically heating ambient air). Catalyst design can lower pressure drop 

across the reactor and reduce induced fan auxiliary power requirements. 

2.4 External studies of heat rate improvement potential at existing coal-fired EGUs 

There are a number of technical and statistical studies that explore opportunities to 

improve heat rate at existing coal-fired EGUs in the U.S. In the proposal TSD, EPA summarized 

five studies that found potential heat rate improvements of between 8.7 and 15 percent from 

existing coal-fired EGUs. Commenters provided information on additional studies, including 

government and independent research reports that assess potential heat rate improvements from a 

large study population of coal-fired EGUs. In general, the concepts for improving heat rate or 

reducing CO2 emissions presented in these studies focus on: reducing heat losses, extracting 

more energy from the cycle, replacing worn or degraded equipment, installing equipment 

upgrades, increasing data measurement and tracking to enhance operation and efficiency, 

conducting routine maintenance to sustain peak performance, hiring staff dedicated to heat rate 

improvement and management, and instituting a corporate culture that places emphasis on 

efficiency improvements. 

The studies use a variety of approaches to estimate potential heat rate improvement and 

CO2 emission reductions. For example, some studies used engineering assessments, some 

subcategorized EGUs by specific design characteristics or operating conditions and then 

compared EGUs in each subcategory against one another, and others compared each EGU’s heat 

rate performance or CO2 emission rate over time. Summaries of several of the studies referenced 

in the proposal TSD are presented below. 

NETL produced a number of reports and workshop summaries about improving 

efficiency at existing coal-fired EGUs. In a 2009 workshop to “explore opportunities to improve 

the thermal efficiency of existing and future coal-fired power plants,” NETL brought together 18 

leading industry experts representing EGU operators, equipment vendors, energy consultants, 

and industry associations to analyze the technical and non-technical issues affecting efficiency.11

The analysis identified a wide variation in efficiency levels across the EGU fleet, but found 

numerous opportunities to improve efficiency exist, such as: (1) decreasing excess oxygen to the 

boiler, (2) installing variable speed motors, (3) utilizing waste heat for coal drying, and (4) 

employing solar systems to heat feed water. The report identifies several barriers that limit the 

adoption of measures to improve heat rate, including: (1) lack of economic incentives to improve 

efficiency because of fuel adjustment clauses that enable electricity generating companies to 

“pass through” changes in fuel costs directly to customers, (2) lack of management commitment 

for efficiency programs, (3) focus on optimizing profitability and ensuring EGU availability over 

efficiency, and (4) lack of on-site performance engineers dedicated to heat rate improvement. In 

general, the report found that while heat rate improvements and efficiency are important, 

 11 See J Eisenhauer and R Scheer, 2009. Opportunities to Improve the Efficiency of Existing Coal-fired Power 

Plants. NETL Workshop Report. 2009 July 15-16 in Rosemont, IL. Available at 

http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/OpportImproveEfficExistCFP

P-ReportFinal.pdf. 
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potential fuel cost savings represent only a small portion of total costs and are “of secondary 

concern when compared to needs for maintaining system reliability.” 

A second NETL workshop was conducted with 53 leading industry experts to explore 

technical opportunities to improve thermal efficiency, identify barriers, and identify initiatives to 

enhance efficiency across the fleet.12 The workshop participants developed a list of more than 50 

distinct opportunities to improve thermal efficiency, many of which are broadly applicable 

“across most of the fleet of coal-fired [EGUs],” including better sensing, measurement, and 

control; better and more frequent maintenance; improved fuel handling; and capital upgrades and 

improvements. 

In 2010, NETL published a report that estimated existing coal-fired EGUs could enhance 

efficiency from a fleetwide generation-weighted efficiency of 32.5 percent in 2008 to 35.2 

percent, equivalent to a heat rate reduction of about 9 percent.13 To develop the estimate, NETL 

segmented coal-fired EGUs into 13 groups based on steam cycle, coal type, and capacity. Using 

data from 1998 to 2008, the researchers identified the 90th percentile EGU,14 ranked by 

efficiency, within each of the 13 segments and calculated the potential efficiency improvements 

if all EGUs below the 90th percentile improved their average efficiency to the level of the 90th

percentile EGU in the segment. Aside from the impact of steam cycle, coal type, and capacity, 

the NETL study found that other design characteristics, location, and emission air pollution 

controls did not account for variations in plant efficiency. NETL also conducted an alternate 

analysis that evaluated existing coal-fired EGUs’ past performance between 1998 and 2008 and 

found that if each EGU returned to its own best historical heat rate, overall fleetwide heat rate 

would improve more than 6 percent. 

Lehigh University’s Energy Research Center (ERC) developed techniques for improving 

heat rate, and a 2009 update stated improvements in net heat rate of up to 15 percent for existing 

coal-fired EGUs burning Powder River Basin subbituminous coal and lignite coal, and 10 

percent for bituminous coal were possible if improvements could be made “in all possible 

areas.”15 However, the authors note that it would not be possible to take full advantage of all 

opportunities at all EGUs, but the information demonstrates that there are substantial 

opportunities to improve heat rate. The research includes improvement opportunities from 

process optimization, more aggressive maintenance practice, and equipment design 

modifications. 

 12 See R Brindle, J Eisenhauer, A Greene, M Justiniano, L Kishter, M Munderville, R Scheer, 2010. Improving the 

Thermal Efficiency of Coal-Fired Power Plants in the United States. Workshop Report. 2010 February 24-25 in 

Baltimore, MD. Available at 

http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/ThermalEfficCoalFiredPower

Plants-TechWorkshopRpt.pdf. 13 See P DiPietro and K Krulla, 2010. Improving the Efficiency of Coal-Fired Power Plants for Near Term 

Greenhouse Gas Emissions Reductions. NETL Report DOE/NETL-2010/1411. Available at 

http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/DOE-NETL-2010-1411-

ImpEfficCFPPGHGRdctns-0410.pdf. 14 NETL ranked heat rate in the opposite order of many of the other studies discussed below. Therefore, the 90th

percentile in the NETL study is methodologically equivalent to the 10th percentile performer in the studies discussed 

below. 

15 See Lehigh University Energy Research Center, 2009. “Reducing Heat Rates of Coal-fired Power Plants,” Lehigh 

Energy Update, 27(1). Available at http://www.lehigh.edu/~inenr/leu/leu_61.pdf. 
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The Congressional Research Service (CRS) published a report summarizing NETL and 

other analyses.16 The report notes that as coal-fired EGUs age, the EGUs lose efficiency due to 

mechanical wear; minimizing energy losses presents the greatest opportunity for regaining 

efficiency through equipment refurbishment, improved operations, and dedicated maintenance 

programs. For example, the top 10 percent of EGU’s operate on average 3.5 percentage points 

more efficiently than the remaining fleet. Consequently, there exists room for improvement. 

Lashof et al. of the Natural Resources Defense Council (NRDC) analyzed the potential 

heat rate improvements from coal-fired EGUs from a suite of heat rate improvement measures at 

EGUs with the highest heat rates for their thermodynamic steam cycle category.17 The study 

ranked coal-fired EGUs by their full-load gross heat rate. EGUs that ranked higher than the 10th

percentile for their category, but lower than the median (i.e., 50th percentile) were assumed to 

have potential heat rate improvements of 300 Btu/kWh and EGUs ranked greater than the 

median for their category were assumed to have potential heat rate improvements of 600 

Btu/kWh. The 600 Btu/kWh heat rate improvement is based on measures outlined in the NRDC 

report (e.g., combustion optimization software and controls, upgrading economizers, cleaning 

and tuning steam condensers). 

Linn et al. examined annual heat rate data from approximately 1,000 coal-fired EGUs 

between 1985 and 2009, grouping plants by boiler type, age, size, and other characteristics.18 The 

RFF study estimates that if coal-fired EGUs in each category improved heat rate to the level of 

the EGU with the 10th percentile heat rate in the category, overall gross heat rate would decline 

by 5.5 percent. 

Sargent & Lundy, LLC (S&L) developed for the EPA an engineering study of potentially 

applicable heat rate improvement methods for coal-steam EGUs. The S&L 2009 study report, 

cited in the proposal TSD, presents technical descriptions of numerous well proven, 

commercially available heat rate improvement techniques. The study also includes indicative 

ranges of potential heat rate improvement (Btu/net kWh) with associated indicative ranges of 

capital and O&M costs at three unit sizes (200, 500, and 900 MW). 

Several leading energy sector engineering consultants produced conference papers and 

presentations that summarize real-world projects and/or the consultants’ experience with heat 

rate improvement projects. In a conference paper, Storm indicated that there were at least 22 

O&M heat rate factors that are controllable by the EGU operator, including (1) reducing air inleakage into the boiler; (2) improving fineness of fuel by optimizing coal pulverizers; (3) 

reducing air heater leakage; (4) optimizing primary, overfire air, and secondary air flow 

measurement and control; and (5) balancing fuel and air distribution into the burner belt. The 

consultant estimates that the average large coal-fired EGU has about 300 to 500 Btu/kWh 

 16 See RJ Campbell, 2013. Increasing the Efficiency of Existing Coal-Fired Power Plants. CRS Report R43343. 

Available at http://fas.org/sgp/crs/misc/R43343.pdf. 17 See DA Lashof, S Yeh, D Doniger, S Carter, L Johnson, 2013. Closing the Power Plant Carbon Pollution 

Loophole: Smart Ways the Clean Air Act Can Clean Up America’s Biggest Climate Polluters. Available at: 

http://www.nrdc.org/air/pollution-standards/files/pollution-standards-report.pdf. 18 See J Linn, E Mastrangelo, and D Burtraw, 2014. “Regulating Greenhouse Gases from Coal Power Plants under 

the Clean Air Act,” Journal of the Association of Environmental and Resource Economists. 1(1/2): 97-134. (DOI: 

10.1086/676038). First published as 2013 working paper RFF-DP-13-05 available at 

http://www.rff.org/rff/Documents/RFF-DP-13-05.pdf. 
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potential heat rate improvement (i.e., about 3 to 5 percent for an EGU with a heat rate of 10,000 

Btu/kWh). The consultant goes on to say that “exacerbating the challenge [to improve heat rate] 

is the fact that often major plant overhauls have been changed from 6 months between boiler 

scheduled outages to sometimes more than 2 years.”19 

Commenters submitted independent studies to inform EPA’s analysis of potential heat 

rate improvement, including engineering analyses, statistical analyses, and case studies. The 

results of the commenters’ studies provide similar results to EPA’s potential heat rate 

improvement analyses described in the following section. The commenters’ studies are 

summarized below. 

Sierra Club and Earthjustice submitted an independent study comparing each coal-fired 

EGU’s best rolling 365-day gross heat rate between 2001 and 2012 against the EGU's own 

average gross heat rate.20 The study included 52 randomly selected coal-fired EGUs designed to 

represent the coal-fired EGU fleet as a whole (based on 2012 electricity generation). The study 

uses rolling 365-day averages of daily gross heat rates in order to minimize the influence of 

weather and electricity generation, and to represent long-term trends. For each EGU, the EGU’s 

lowest and 95th percentile rolling 365-day average gross heat rate were compared to the EGU’s 

12-year average gross heat rate (2001-2012). The results of the analysis indicate that, on average, 

the coal-fired EGUs in the study achieved and maintained gross heat rates over a 365-day period 

that were 7.6 or 6.1 percent lower at the lowest and 95th percentile gross heat rate, respectively. 

The General Electric Company (GE) submitted an assessment of technical, economic, 

and market potential for heat rate improvements at coal-fired EGUs.21 The assessment identified 

equipment upgrades and best practices that, individually, could improve heat rate between 0 and 

2.9 percent. The study estimated the average technical potential for gross heat rate improvements 

to be 5.8 for large coal-fired EGUs to 6.8 percent for smaller coal-fired EGUs. To calculate the 

economic potential, GE estimated the penetration rate for equipment upgrades and best practices 

by establishing a “best in class” full load net heat rate benchmark (9,400 Btu/kWh), irrespective 

of EGU design characteristics, and compared each EGU’s full-load net heat rate to the “best in 

class” benchmark to determine potential heat rate improvements. The study then constrained 

equipment upgrades and best practices to those with costs below the social cost of carbon, 

resulting in estimated heat rate improvement of 6.3 percent for large coal-fired EGUs to 5.3 

percent for small coal-fired EGUs. Finally, the study includes an assessment of market potential 

based on results from the North American Electricity & Environmental Model (NEEM). For the 

modeling study, each state was constrained to the CO2 emission rate from EPA’s proposal; coalfired EGUs for which the study assumed some heat rate improvement measures were 

implemented were only offered the option to use the most expensive heat rate improvements (on 

 19 See D Storm, 2009. Applying the Fundamentals for Best Heat Rate Performance of Pulverized Coal Fueled 

Boilers. EPRI 2009 Heat Rate Conference Paper. 2009 February 3-5 in Albuquerque, NM. Available at 

http://www.stormeng.com/pdf/EPRI2009HeatRateConference%20FINAL.pdf. 20 See Comments of Sierra Club and Earthjustice. Available at 

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0602-24029. Also, see B Buckheit and N 

Spiegel, 2014. Sierra Club 52-Unit Study: Data Files. Available at 

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0602-25475. 21 See Comments of The General Electric Company. Available at 

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0602-22971. 
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the assumption that the lower price options were already implemented at the EGU.) Using the 

least-cost electricity utility planning framework of NEEM, the modeling study estimates that 

only 1 percent heat rate improvement will be implemented and the remaining CO2 reductions 

will come from other actions within each state. 

In addition to the reports described above, POWER Magazine published an article on 

heat rate improvement opportunities at coal-fired EGUs.22 Korellis summarized an Electric 

Power Research Institute (EPRI) report of heat rate improvement case studies at five large coalfired EGUs with electricity generating capacities of 95 to 650 MW, combusting Powder River 

Basin subbituminous (3 EGUs) and bituminous (2 EGUs) coal, and utilizing different 

thermodynamic steam cycles (2 supercritical and 3 subcritical). Through a combination of best 

practices and equipment upgrades, four of the five EGUs were able to improve net heat rate by 3 

to 5 percent (see Table 2-1). Common issues at the EGUs prior to the heat rate improvement 

project included: (1) problems related to combustion and high air heater/stack gas temperatures, 

(2) shortage of heat rate data, (3) lack of training and understanding of controllable losses, (4) 

lack of performance testing, (5) problems with feedwater heater train performance, and (6) 

buildup of soot on heat transfer surfaces. The article provides a list of general and EGU-specific 

heat rate improvement recommendations with estimated reductions in heat input. The article also 

provides a summary of a utility’s “fleetwide” heat rate improvement assessment. The 

engineering study indicated that the 12 coal-fired EGUs in a member utility’s fleet could 

improve net heat rate by approximately 5.3 percent at a cost of approximately $40 per ton of CO2

reduced. The summary of the full report states, “[r]educing a power plant's heat rate can lower 

emissions, fuel consumption, and costs, thus contributing to the plant's bottom line. A significant 

improvement in heat rate can often be achieved with a re-commitment to best operating 

practices, which can minimize the need for capital expenditures on new technology. However, 

because the current fleet of coal-fired plants has endured age-related degradation; changed 

operational requirements such as fuel quality, low emissions, and flexible operations; and made 

physical modifications, achievable heat rates may be significantly different from initial design 

values. As a result, power plant owners and operators are unable to assess the range of possible 

heat rate improvements in many cases.” 

 22 See S Korellis, 2014. “Coal-Fired Power Plant Heat Rate Improvement Options, Part 2,” Power Magazine. 

Available at http://www.powermag.com/coal-fired-power-plant-heat-rate-improvement-options-part-2. For the full 

report, see EPRI, 2014. Range and Applicability of Heat Rate Improvements. Technical Update 3002003457. 

Available at http://www.epri.com/abstracts/Pages/ProductAbstract.aspx?ProductId=000000003002003457. 
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Table 2-1 Net heat rate improvement case study at five coal-fired EGUs 

EGU Project type Net heat rate 

improvement 

A Implementing multi-level heat rate teams, training, managing 

excess air 

279 Btu/kWh 

B Aligning cycles, reducing air inleakage, chemically cleaning 

turbine 

557 Btu/kWh 

C Maintaining steam path and replacing feedwater heater 400 Btu/kWh 

D Reducing air inleakage, replacing feedwater heater, cleaning 

condenser and feedwater tubes 

500 Btu/kWh 

E [Not available] Heat rate increased 

(350 Btu/kWh) 

These studies provide technical information about potential heat rate improvement at 

existing coal-fired EGUs, including available best practices and equipment upgrades. As several 

commenters noted, these studies demonstrate that heat rate improvements are both readily 

available and achievable. The studies and commenters’ suggestions informed EPA about the 

different approaches and analytical techniques that are available to assess potential heat rate 

improvements at existing coal-fired EGUs. The agency used the information to enhance the 

analytical approaches, but decided not to adopt any one of the studies described above. The 

agency believes its analyses, described in the next section, are more appropriate for the purpose 

of determining potential heat rate improvement for this final rule because the agency’s approach: 

(1) uses more recent data on nearly all existing coal-fired EGUs in the CONUS; (2) compares 

each EGU’s 2012 performance against the EGU’s own best performance, largely obviating the 

need for subcategorization or a “one-size-fits-all” heat rate or CO2 emission rate; and (3) controls 

for key ambient and operating conditions outside the EGU operators’ control. 

2.5 EPA study of heat rate improvement potential at existing coal-fired EGUs 

To assess potential heat rate improvements at coal-fired EGUs, EPA began by looking at 

each coal-fired EGU’s past gross heat rate performance. EPA used three analytical approaches to 

assess potential heat rate improvement for each coal-fired EGU by comparing the EGU’s best 

historical gross heat rate between 2002 and 2012 against the EGU’s own 2012 gross heat rate. 

The agency based this approach on the reasonable expectation that, in the general sense, if a 

coal-fired EGU was able to demonstrate and achieve specific heat rates in the past the EGU 

should be able to achieve that same heat rate again. The advantages of such an approach are (1) it 

compares each EGU against the EGU’s own past performance, thereby controlling for many of 

the design characteristics that vary among EGUs but are constant or nearly constant over time at 

individual EGUs (e.g., generator capacity, thermodynamic steam cycle, coal type, cooling 

system type); (2) it accounts for heat rate improvement measures employed during the study 
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period by using 2012 as the baseline, (3) it is not significantly affected by the addition of 

pollution control devices during the study period because the auxiliary power consumption from 

these devices has negligible impact on gross electricity generation;23 and (4) the historical unitlevel gross heat rate is by definition demonstrated and achievable by the respective coal-fired 

EGU. 

In the June 2014 proposal, EPA proposed a 6 percent potential heat rate improvement for 

the coal-fired EGU fleet for the purpose of establishing state emission goals. The potential heat 

rate improvement was based on two components: (1) a statistical analysis that determined 4 

percent improvement in the fleetwide coal-fired EGU heat rate is possible through best practices 

(e.g., improved operation and maintenance), and (2) an estimate that a 2 percent heat rate 

improvement is possible through additional equipment upgrades. 

Several commenters suggested these values were too conservative, suggesting the agency 

should require greater heat rate improvements from the fleet on average or from each and every 

coal-fired EGU. Some of these commenters provided studies and analyses showing larger heat 

rate improvements are feasible for coal-fired EGUs. EPA carefully reviewed the comments and 

supplemental materials before refining the potential heat rate improvement analysis. As 

explained below, the analysis for this final rule does not include a separate estimate of the 

potential from equipment upgrades. 

Conversely, several commenters suggested EPA’s proposed heat rate improvement was 

too optimistic, providing engineering studies, statistical evaluations, and data describing heat rate 

improvement measures that had already been implemented at specific coal-fired EGUs. 

Commenters also expressed concern that EPA improperly characterized the potential heat rate 

improvements from equipment upgrades because: (1) the Sargent & Lundy (S&L) report cited in 

the proposal TSD is based on “conceptual” equipment upgrades, (2) plant operators indicate they 

have already implemented many of the heat rate improvement measures identified in the S&L 

report, (3) heat rate improvements from the list of equipment upgrades and best practices in the 

S&L report may not be additive (i.e., cumulative), and (4) the costs of equipment upgrades are 

highly site specific. The EPA generally agrees with the four points noted above, and alluded to 

these considerations in the proposal TSD, section 2.6.1 Heat Rate Improvement Capital Cost 

Assumptions. The points are also discussed in more detail below. 

 23 In addition to the parasitic load from add-on pollution controls, another effect of some add-on controls is worth 

mentioning here. The installation of wet flue gas desulfurization (i.e., wet FGD or scrubber) technologies can affect 

heat rate because the chemical process of capturing SO2 creates CO2 that is measured in the continuous emission 

monitoring systems. This results in higher calculated heat input (see infra 29). However, the typical increase in heat 

rate is less than 1 percent and may be offset by heat rate improvements resulting from switching to lower-moisture, 

higher-sulfur bituminous coal. Furthermore, the impact on calculated heat input is only relevant to EGUs that added 

WFGD during the study period because the analytical approaches described below evaluate the step change in heat 

rates. Assuming consistent operation and fuel sulfur content, an EGU with a WFGD during the entire study period 

would not have a heat rate step change due to the WFGD CO2. Circulating fluidized bed (CFB) boilers also have 

higher CO2 emissions from the chemical process of limestone injection to capture SO2, thereby affecting the heat 

input calculations. However, because CFBs generally injected limestone at all times throughout the study period, the 

EGUs would not have heat rate step changes. See section 2.6.3 for more information about the impact of CO2

emissions from SO2 pollution control devices. 
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The agency does not agree that the EPA improperly characterized or misused information 

from the S&L report. The S&L study24 was prepared for the EPA, and senior engineering staff 

with previous experience in fossil power plant engineering, operations, and management were 

involved in the scoping and review of the study report. The agency recognized the limits of the 

study and considered the S&L caveats/limitations when using information from the study, 

including the following statements from the study: 

 “The primary intent of the study was to focus on methods that have been successfully 

implemented by the utility industry.” 

 “This study identifies specific plant systems and equipment where efficiency improvements can 

be realized either through new installations or modifications, and provides estimates of the 

resulting net plant heat rate reductions and the order-of-magnitude costs for implementation. To 

conduct the study presented in this report, S&L surveyed available literature, spoke with 

technology manufacturers, and used its engineering expertise as the basis.” 

 “This report discusses potential efficiency improvement concepts and the resulting heat rate 

reductions that can be implemented in various systems of a typical coal-fired power plant. All 

estimated capital and installation costs are referenced from work in progress and vendor quotes as 

of the year 2008.” 

 “S&L cautions that the costs presented herein are not indicative of those that may be expected for 

a specific facility due to variables such as equipment, material, and labor market conditions and 

site specifications. However, these cost estimates provide valuable information for comparative 

purposes when evaluating the advantages and disadvantages of the various concepts. The costs 

should not be used as a basis for project budgeting or financing purposes.” 

In consideration of these caveats/limitations, the agency used the average conceptual 

performance values from the S&L report to develop an estimated 4 percent potential heat rate 

improvement that the average coal-fired EGU could make from only a few of the higher-cost 

equipment upgrades. The agency then discounted that potential by 50 percent to obtain the 2 

percent potential heat rate improvement estimate attributable to equipment upgrades that was 

included in the proposal. The 50 percent discount was applied to account for site-specific factors 

that could limit the potential heat rate improvement, including the fact that the cumulative effect 

of installing multiple measures can be less than the sum of their individual effects. The agency 

similarly used averages of S&L order-of-magnitude costs for thirteen of the fifteen S&L heat rate 

improvement measures25 to develop an indicative conceptual cost estimate ($100/kW) for an 

overall 6 percent heat rate improvement. That estimate was conservative because 4 percent was 

projected to come from relatively inexpensive best practices while only 2 percent was projected 

to come from a small number of more expensive “new installations or modifications” described 

by the S&L report. The average $100/kW cost, derived from S&L estimates for unit sizes 

ranging from 200 to 900 MW inherently reflects the inverse relationship of $/kW cost to MW 

unit size, and was thus appropriately applied in the agency’s estimate of the fleet wide average 

cost of heat rate improvement. The agency was also mindful of the 2008 time frame of the S&L 

cost estimates. EPA considered the 2008 cost values to be applicable as 2011 values because, 

 24 Coal-fired Power Plant Heat Rate Reductions, Sargent & Lundy LLC, January 2009. Available at 

http://www.epa.gov/airmarkets/documents/ipm/coalfired.pdf 

25 Three mutually exclusive fan and fan drive modifications were discussed by S&L. Accordingly, EPA selected the 

fan-related measure that included both a fan upgrade and variable frequency drive for use in the cost estimate 

because the selected measure had the highest estimated capital cost. 
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through a coincidence of timing, the 2008 study reflected the highest cost levels experienced by 

the power sector up to that point in time. The economic recession that commenced in late 2008 

caused costs to decrease sharply before beginning a slow recovery. The agency therefore 

considered the S&L cost values to quite reasonably represent the costs in 2011.26

In addition to the S&L report, EPA referred to several other studies in the proposal TSD 

that present similar information on equipment upgrades to the S&L report. As demonstrated by 

the materials provided by commenters expressing a preference for larger heat rate improvements, 

there are further analyses that show a greater than 6 percent heat rate improvement is 

demonstrated and achievable. One commenter also noted that many existing smaller coal-fired 

EGUs have recently retired or will be retiring over the next decade (see section 2.6.5 below for 

more information about retirements), leaving more of the larger, well-controlled coal-fired EGUs 

that are similar to the example EGUs used in the S&L report. Furthermore, the equipment 

upgrades and best practices identified in the proposal TSD and supporting reports are intended to 

serve as illustrative lists of measures that coal-fired EGUs might employ to improve heat rate. 

In the refined heat rate analyses described below for this final rule, the results are not 

based on heat rate improvements that would be achieved by implementation of specific 

measures. Instead, the heat rate analyses are based on each coal-fired EGU’s best historical heat 

rate performance relative to its 2012 heat rate performance. It reflects the heat rate improvements 

that would occur if each EGU performed at levels that the EGU has already demonstrated are 

achievable. As one commenter phrased it, EPA is simply basing building block 1 on a 

continuation of the types of good maintenance and operating practices that are necessary for 

EGUs overall to maintain the better heat rates they have previously achieved. 

Some commenters also noted that if a coal-fired EGU implemented equipment upgrades 

during the study period (2002–2012), improvements to gross heat rate would show up in the 

historical gross heat rate data and could result in double counting because the heat rate 

improvements would affect the statistical results and would still be expected from the equipment 

upgrade component. Similarly, many commenters provided lists of equipment upgrades 

undertaken at specific coal-fired EGUs, arguing that the equipment upgrade component of the 

agency’s potential heat rate improvements does not account for upgrades that coal-fired EGUs 

have already implemented. EPA acknowledges that there could be overlap between the two 

components of the potential heat rate results, but notes that the agency was not requiring 

individual coal-fired EGUs to achieve specific heat rate improvements. However, for this 

analysis the agency no longer uses the two components to identify potential heat rate 

improvements. Instead, the agency conducts the statistical analyses described below to compare 

each EGU’s best historical performance to its 2012 performance. The results reflect the overall 

heat rate improvement for coal-fired EGUs in each regional interconnection if those EGUs had 

returned to their demonstrated best historical gross heat rates from the baseline year of 2012. 

This backward-looking approach is inherently conservative because it does not reflect 

opportunities for heat rate improvements from additional best practices and equipment upgrades 

that could have been (and still can be) cost-effectively implemented at coal-fired EGUs. 

In the proposal TSD, EPA’s statistical analysis compared each EGU’s best historical 

gross heat rate to the EGU’s 11-year average gross heat rate. Commenters stated that some coalfired EGUs made significant investments to improve heat rate during the 11-year study period 

 26 Cost estimates for implementation of the final rule are based on 2011 dollars. 
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and the use of an 11-year baseline fails to recognize those investments. These commenters 

suggested the agency could adjust the potential heat rate improvements to reflect any upgrades 

already implemented at coal-fired EGUs. In the revised analyses described below, in order to 

account for actions undertaken to improve gross heat rates at coal-fired EGUs, the agency 

refined the methodology to compare each EGU’s best heat rate performance to its 2012 gross 

heat rate. Therefore, any actions an EGU implemented to improve gross heat rate during or 

before 2012 (and maintained in 2012) would be accounted for in the analysis. In addition, the 

selection of 2012 as a baseline is conservative because many commenters noted that coal-fired 

EGUs experienced greater cycling and lower capacity factors in the later years of the study 

period (2002-2012). 

Several commenters suggested that EPA should replace the statistical analysis with unitspecific engineering studies to establish unit-level heat rate improvement goals. These 

commenters contended that such studies are the only method for accurately identifying what 

types of equipment upgrades and best practices (and therefore, potential heat rate improvements) 

are feasible and cost effective at each coal-fired EGU. As discussed in sections V.A and V.C of 

the preamble and the response to comments, conducting engineering studies to determine the 

potential for improving heat rate through best practices and equipment upgrades at every coalfired EGU would be unnecessarily lengthy and expensive, and would not be consistent with the 

broader goal-setting purpose of this rulemaking. However, the agency does believe that EGU 

owners and operators that conduct such studies will discover additional cost-effective 

opportunities to improve heat rate at their EGUs. Commenters also suggested that as an 

alternative to unit-level engineering studies, EPA could identify unit-level heat rate improvement 

goals. EPA’s methodology does assess the potential heat rate improvement for each 

interconnection by comparing an individual EGU’s best demonstrated and achievable historical 

gross heat rate relative to the EGU’s own 2012 gross heat rate. However, as several commenters 

note, and the agency explained in the proposal, this rule does not establish mandatory federal 

heat rate performance requirements for coal-fired EGUs or mandate heat rate improvement as a 

compliance strategy. The agency uses the results of the heat rate improvement analysis for each 

regional interconnection (i.e., the electricity system) along with emission reductions from the 

other building blocks of the best system of emission reductions to establish state-level goals. 

Each state has the flexibility to identify measures in its state plan to achieve the state goals and, 

if the state chooses, it may develop unit-specific heat rate improvement targets – or entirely 

ignore potential heat rate improvement. Commenters also stated that the proposal expressly 

anticipates fleetwide averaging of CO2 emission intensity improvements, thereby offering greater 

opportunities to achieve the state goals at lower cost relative to controlling emissions or heat rate 

at the plant or unit level. Therefore, the agency believes it is appropriate in this rulemaking to 

assess potential heat rate improvement at a scope broader than the unit-level. 

Commenters also recommended that EPA subcategorize coal-fired EGUs and develop 

specific heat rate improvement goals for each subcategory to account for the influence of 

different design characteristics and fuel choices on an EGU’s heat rate. However, as discussed 

above and noted in the proposal TSD, the agency is not establishing mandatory heat rate 

improvements that must be achieved at each and every coal-fired EGU. Instead, the agency is 

attempting to determine a reasonable heat rate improvement that, on average, the coal-fired 

electricity generating fleet can achieve, and to use the average potential heat rate to calculate 

state goals. In addition, the agency does not believe there is a need to control for the design 
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characteristics and fuel choices because the agency compared each EGU’s performance to the 

EGU’s own past performance. Because EPA compared each EGU to itself, the full analyses 

inherently account for design characteristics that do not change from year to year. 

Commenters also highlighted the role of age and coal rank on an EGU’s heat rate. The 

average age of coal-fired EGUs in the study population was approximately 42 years in 2012. To 

assess the impact of age, EPA grouped the 884 coal-fired EGUs by 10-year age increments (as of 

December 2012). While there is a difference in median and average annual gross heat rates 

between coal-fired EGUs less than 10 years of age and those greater than 10 years, there was no 

statistical difference between gross heat rates of coal-fired EGUs older than 10 years of age (i.e., 

range of performance of an EGU 10-19 years of age is approximately the same as one 30-39 

years of age). In addition, it is likely that the gross heat rate differences for younger units is due 

to other factors (e.g., advanced technology, larger boiler and/or steam turbine size) that do not 

change as the EGU ages. Therefore, the influence of age is unlikely to play an important role for 

an individual coal-fired EGU. An EGU’s primary coal rank may change, but changing coal ranks 

at a coal-fired EGU requires significant effort. Generally, coal-fired EGUs – especially 

pulverized coal boilers and their corresponding fuel handling equipment, combustion systems, 

and pollution control devices – are designed for the characteristics of a specific type of coal. 

Significant deviations from those coal characteristics can affect the EGU’s performance and 

reliability. Changes to coal type might require plant modifications to maintain maximum output 

and efficiency (e.g., pulverizer capacity, fan capacity, heating surface). Commenters noted that 

changing coal rank is likely not practical at many EGUs because coal rank is determined by the 

design of the EGU and environmental control systems. Although it might be a significant 

engineering endeavor, some coal-fired EGUs have switched coal types or blended different coal 

types. Furthermore, some EGUs might have the option of changing coals in the future, 

potentially improving their heat rate. Commenters also discussed the impact that coal quality 

(e.g., higher heating value, moisture content, ash content) can have on an EGU’s heat rate. While 

EPA recognizes the impact that coal rank and quality can have on an EGU’s heat rate, the agency 

also recognizes that EGU operators and coal suppliers typically set requirements for coal quality 

in purchase contracts, providing coal-fired EGUs with some level of control over the quality of 

fuel they purchase. Therefore, EPA did not control for coal rank or coal quality in the analysis. 

In summary, the agency feels the analytical approaches described below, which are 

founded on comparisons between each coal-fired EGU’s historical performance and its 2012 

performance, account for nearly all design characteristics because these characteristics do not 

vary for a particular EGU between years or are accounted for by the use of 2012 as the baseline. 

Other factors, (i.e., ambient temperature and hourly capacity factor) that are beyond the EGU 

operator’s control are explicitly accounted for in some of the agency’s analyses presented below. 

Finally, for all of these analyses, by using long-term averages of heat rate (i.e., at least a year) or 

grouping large numbers of hourly values and accounting for outliers, EPA implicitly accounts for 

some variation that might be beyond the EGU operator’s control. 

EPA used three approaches to calculate the potential heat rate improvement: (1) best 

historical performance, (2) best historical performance under similar conditions, and (3) 

efficiency and consistency improvements under similar conditions. Each of these approaches is 

described in more detail below. 

2.5.1 Heat rate, capacity factor, and temperature data 
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Under 40 CFR Part 75, most fossil fuel-fired EGUs report hourly emission and operation 

data to EPA’s Clean Air Markets Division (EPA/CAMD). In 2012, 884 coal-fired EGUs 

reported heat input and gross electricity generation data to EPA.27 These 884 EGUs account for 

approximately 1.61 billion tons of CO2 emissions in 2012, 96 percent of the 1.67 billion tons of 

CO2 emitted by the national coal-fired EGU fleet in 2012.28 Therefore, EPA considers these 884 

coal-fired EGUs representative of the coal-fired EGU fleet as a whole. 

Some commenters suggested that the agency’s inclusion of coal-fired EGUs near 

retirement inflates the results of the heat rate improvement analysis because the soon-to-retire 

EGUs may have more variability in gross heat rate and higher gross heat rates due to frequent 

cycling, deferred or canceled maintenance, and termination of good heat rate practices. EPA’s 

analysis included the 884 coal-fired EGUs that reported heat input and gross electricity 

generation in 2012, including those EGUs that are expected to retire. While the agency 

recognizes the commenter’s concern that soon-to-retire EGU that operate with poor maintenance 

and operating practices can increase the potential heat rate improvements identified by the heat 

rate improvement analysis, the agency does not believe this artificially inflates the potential heat 

rate improvements. Any coal-fired EGU that stops implementing good maintenance and 

operations practices to maintain heat rates will have a similar type of impact on the results 

regardless of whether it is scheduled to retire to not. Also, the agency believes that the inclusion 

of coal-fired EGUs that are near retirement is conservative for two reasons: (1) for states with 

mass-equivalent goals based on 2012 baseline levels, after soon-to-retire EGUs cease operation 

they cease emitting CO2 contributing to attainment of the state goal, and (2) for states with CO2

intensity goals based on 2012 baseline levels, the retirement of coal-fired EGUs with high heat 

rates in 2012 will contribute to achievement of the state goals. 

40 CFR Part 75 requires that most coal-fired EGUs continuously measure emissions of 

CO2, NOX, and SO2, and report those hourly emissions along with hourly heat input29 and gross 

electricity generation to EPA/CAMD at the end of each calendar quarter. The monitoring 

regulation requires regular quality assurance/quality control (QA/QC) of the monitoring systems, 

including daily calibrations and semi-annual or annual relative accuracy tests.30 When EGU 

operators submit the hourly emission and operation data to EPA/CAMD, a responsible company 

official must certify that the data are true, accurate, and complete. In addition, the data undergo 

thousands of automated quality assurance tests as well as statistical analyses and EPA staff 

audits. Therefore, the agency believes these high-quality data are the best available information 

for assessing coal-fired EGUs’ performance over time. 

The monitoring regulation includes provisions to accommodate time periods when 

emission data are not available due to monitoring system malfunctions or maintenance, technical 

challenges, or missed QA/QC tests. When data are not available or deemed invalid (e.g., when a 

 27 This population does not include coal-fired EGUs that did not operate in 2012, some of which retired before 2012 

and others which may have resumed operation after 2012. See supra note 5 for a discussion about treatment of 

cogeneration EGUs. 

28 CO2 emissions for the national coal-fired EGU fleet are taken from Table 12.6 Carbon dioxide emissions from 

energy consumption: electric power sector. EIA, 2015. Monthly Energy Review. Dated 2015 May 22 available at 

http://www.eia.gov/totalenergy/data/monthly/#environment. 

29 Heat input is derived using CO2 or O2 concentration and calculations detailed in 40 CFR Part 75 Appendix F. As a 

result, heat rate (Btu/gross kWh) is proportional to CO2 rate (CO2/gross kWh). 30 The quality assurance requirements for monitoring systems are described in 40 CFR Part 75 Appendix B. 
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QA/QC test was not performed as required), the EGU is required to use specified data 

substitution methods that are designed to be conservative (i.e., overestimate emissions). This 

conservative bias is intended to create an incentive for better emission measurement – the 

overestimate incurs an economic penalty because at the end of the compliance period an EGU 

must surrender allowances equal to total reported emissions. Because of this conservative bias 

and the impact it would have on the results of this study, the agency excluded substitute data 

reported by EGUs from the dataset. These substitute data represent approximately two percent of 

all reported operating hours for the 884 coal-fired EGUs during the study period. In addition, the 

agency excluded partial hours of operation that occur during the first hour of startup and the last 

hour of shutdown, and hourly gross heat rate values that were greater than or less than 2.6 

standard deviations from an EGU’s annual average gross heat rate.31 Both of these conditions 

tend to occur during very low gross electricity generation. The hourly values ±2.6 standard 

deviations from the EGU’s annual average gross heat rate may be due to unusual operating 

conditions or misreported gross electricity generation.32 These outliers account for approximately 

1.9 percent of hourly data records. 

The monitoring provisions of 40 CFR Part 75 require regular QA/QC testing of the 

monitoring systems to ensure they are reading accurately. Commenters hypothesized that 

discrepancies between the monitoring system and the reference tests could explain much of the 

variation in heat rates. EPA assessed the monitoring systems’ relative accuracy and the findings 

indicate that the relative accuracy does not significantly affect the results of the agency’s 

analyses. In general, coal-fired EGU operators are required to perform relative accuracy test 

audits (RATA) once per year if the difference between the monitoring system and RATA results 

is less than or equal to 7.5 percent, and twice per year if the difference is greater than 7.5 percent 

but less than 10 percent.33 If the flow monitoring system readings are statistically-significantly 

lower than the RATA results, the EGU operator must apply a bias adjustment factor (BAF) to all 

subsequent flow measurements to reduce potential underreporting of flow. There is no BAF 

applied for CO2 measurements. To assess the relative accuracy of the monitoring systems during 

the study period, EPA reviewed the EGU-level RATA results for the study period and then 

conservatively calculated the average annual generation-weighted relative accuracy within each 

of the interconnection regions. As shown in Table 2-2, the average (i.e., mean) relative 

accuracy34 for both CO2 and flow monitoring systems are reasonable – the difference between 

the reference tests and measured values is approximately 1.5 to 3.0 percent – and varies little 

from year to year within each interconnection. 

 31 Assuming a normal distribution, 99 percent of all values will be within 2.6 standard deviations. 

32 40 CFR Part 75 requires operators to apportion heat input to all EGUs sharing a common stack. For this reason, 

EGUs that are not generating electricity during startup or shutdown periods may report a small amount of gross 

electricity generation (e.g., 1 MW) to avoid errors in the apportionment calculations. However, this can result in 

unusually large gross heat rates. 

33 More information about the quality assurance provisions, including RATAs, can be found in 40 CFR Part 75 

Appendix B. 

34 Relative accuracy is expressed as the absolute value of the difference between the reference method measurements 

and the EGU’s pollutant concentration or flow measurements. However, the averages at the interconnection level are 

overstated because the relative accuracy is expressed as an absolute value. As a simple example, if the difference 

between the measurements at one unit is -2 percent and at another unit the difference is 2 percent, the arithmetic 

average is 0 [(-2+2)/2] while the average of the absolute values is 2 [(|-2| + |2|)/2]. EPA’s calculation is based on the 

absolute value. 
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Table 2-2 Generation-weighted relative accuracy of CO2 and flow monitoring systems, by 

interconnection 

 Western Texas Eastern 

CO2 Flow CO2 Flow CO2 Flow 

2003 2.57 2.70 2.27 2.30 2.52 2.22 

2004 3.17 2.51 2.63 1.64 2.51 2.11 

2005 3.21 2.95 2.82 2.25 2.69 2.10 

2006 3.06 2.81 2.85 1.33 2.56 1.99 

2007 3.15 2.59 2.25 1.50 2.61 2.06 

2008 3.41 2.86 3.68 1.59 2.75 2.12 

2009 2.95 2.97 2.47 1.76 2.55 1.97 

2010 2.65 3.07 2.86 2.00 2.45 2.05 

2011 2.40 2.59 2.56 1.69 2.63 2.02 

2012 2.33 2.56 2.46 1.53 2.41 2.13 

Notes: All values are generation weighted; 

Due to data management and archive policies, 2002 data were not available at the time of this analysis 

While the average relative accuracy at the EGU-level varies from 1 to 3 percent, the 

uncertainty becomes significantly less when these differences are aggregated over many EGUs – 

the relevant scope of analysis for building block 1 as a whole. EPA evaluated the combined 

effect of CO2 and flow measurement differences between the RATA and measurement systems 

at 685 coal-fired EGUs between 2009 and 2012. The results show that the combined differences 

across the 685 EGUs amount to a fleetwide standard “error” of 0.07 percent.35 Therefore the 

agency believes the impact of monitoring system relative accuracy does not significantly 

influence the results of the potential heat rate improvement analyses. 

EPA also used data from NOAA’s Integrated Surface Data (ISD) and the USGS’s 

WaterQualityWatch (WQW). The NOAA dataset provides hourly ambient air temperature for 

over 20,000 weather stations worldwide.36 Since coal-fired EGU heat rates can be sensitive to 

ambient air temperature and barometric pressure, the agency collected meteorological data from 

stations that are reasonably close to each coal-fired EGU's location and elevation to account for 

the impact of ambient conditions. For each of the 884 coal-fired EGUs, the agency identified the 

 35 The average combined difference between the RATA and monitoring system for flow and CO2 measurements, 

using the directional difference (e.g., positive and negative values), is 0.5 percent and the standard deviation is 3.4 

percent. To calculate the standard error, EPA used the following equation: ௌ௧௔௡ௗ௔௥ௗ	ௗ௘௩௜௔௧௜௢௡

√௡ 36 NOAA’s Integrated Surface Data are available at http://www.ncdc.noaa.gov/data-access/land-based-stationdata/land-based-datasets/integrated-surface-database-isd. 
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nearest weather station37 that reported a minimum of 8,400 hourly observations in the calendar 

year (i.e., greater than 95 percent of the hours in a year). Because of the constraint that a station 

must report at least 8,400 measurements in a calendar year, most of the 884 EGUs were 

associated with meteorological data from the two closest stations over the study period (2002-

2012). The average distance between the EGUs and the weather stations was 22 miles and the 

average difference in elevation was only 366 feet.38 For at least one year of the study period 

(2002-2012), nine power plants did not have weather stations that met the three constraints 

described above. For these plants, the agency used its judgement and assigned nearby weather 

stations with as few as 7,000 hourly observations, but within 100 miles and 1,000 feet elevation. 

In response to commenters’ concerns that EPA’s analysis did not account for cooling water 

temperature, the agency added data from the USGS WQW.39 

After excluding coal-fired EGUs that did not report heat input and gross electricity 

generation in 2012 and coal-fired cogeneration EGUs that reported steam generation in one or 

more years during the study period, and excluding the data described above in subsection 2.5.1, 

EPA developed a dataset of hourly heat input, gross electricity generation, gross heat rate,40

capacity factor,41 and ambient air temperature for the years 2002 through 2012 for all 884 coalfired EGUs. This dataset, which was included in the proposal,42 contained more than 61,848,500 

hourly records. 

Commenters also suggested that EPA should use fewer years of data in its analysis, 

noting that the power sector is very different today than it was in 2002. EPA recognizes that the 

power sector went through many changes between 2002 and 2012, and is likely to go through 

many more changes between 2012 and 2022 – the first year of the interim implementation 

period. Nevertheless, the agency believes it is appropriate and beneficial to use the full 11 years 

of data. First, this time period includes a variety of national and regional economic conditions, 

fuel prices, electricity resource mixes, weather conditions (e.g., precipitation), and demand 

levels. As a result, it is more likely that future economic and weather conditions will be 

represented by data periods between 2002 and 2012. Second, commenters specifically expressed 

concern that many coal-fired retired during the study period and might bias the results. However, 

EGUs that retired prior to 2012 are not included in the dataset. Only coal-fired EGUs that 

reported both heat input and gross electricity generation are included in the dataset. Third, the 

foundation of EPA’s methodology involves comparisons of each coal-fired EGU’s best gross 

heat rate performance between 2002 and 2012 against the EGU’s own 2012 gross heat rate. 

Therefore, if a coal-fired EGU employed better practices for maintenance and operation in the 

past than it did in 2012, as characterized by a lower gross heat rate, the agency believes it is 

 37 EPA established two constraints on distance between the weather station and the EGU: (1) less than 100 miles, 

and (2) less than 1,000 feet in elevation. 

38 The NOAA data set is the most complete and comprehensive ambient air temperature data available to EPA. The 

hourly ambient air temperature of the nearest weather station is used only for the purpose of grouping hourly heat 

rate into temperature bins by 10° F increments. Therefore, the agency believes conditions at the nearest weather 

station provide a reasonable approximation of temperature conditions at the coal-fired EGU. 

39 The USGS WaterQualityWatch dataset provides hourly surface water temperature from approximately 2,000 sites 

around the U.S. The data are available at http://waterwatch.usgs.gov/wqwatch. 40 EPA calculated gross heat rate as heat input (Btu) / gross electricity output (kWh). 

41 EPA calculated capacity factor as gross electricity output (kWh) / generator capacity (kWh). 

42 See supra note 1. 
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reasonable to base the potential heat rate improvement for the population of EGUs in the 

interconnection region on their collectively more efficient operations – whether for individual 

EGUs those operations were in 2012 or as early as 2002.43 This longer time period better reflects 

various operating practices and investment priorities for the sector. As one power-sector trade 

magazine stated, “[R]elatively cheap coal and a focus on plant emissions controls has, 

unfortunately, taken the focus away from maintaining and improving plant heat rate.”44 EPA’s 

analysis seeks to identify the potential for EGUs to re-achieve their better heat rates. 

Commenters also noted that the state goals are based on CO2 intensity using net 

electricity generation, but EPA based its potential heat rate improvement analysis on gross heat 

rate.45 The commenters suggested that EPA should change the analysis to use net heat rate. 

While EPA acknowledges the discrepancy between the unit of measure for the state goals and 

the gross heat rate improvement analysis, the agency uses hourly gross heat rate for the analysis 

because it is the only comprehensive, quality assured dataset available to the agency. The agency 

also believes the use of gross heat rate is inherently conservative for two reasons: (1) it does not 

reflect additional opportunities that coal-fired EGUs may have to reduce auxiliary energy use 

(i.e., parasitic load),46 and (2) gross electricity generation is not affected by auxiliary energy use 

required to power the significant capacity of air pollution control devices that were installed 

between 2002 and 2012. If net heat rate data were available and the agency used these data for 

the analytical approaches described below, the auxiliary energy use of air pollution control 

devices installed during the study period could possibly inflate the potential heat rate 

improvement. 

2.5.2 Influence of ambient conditions and capacity factor on gross heat rate 

Ambient conditions can affect a coal-fired EGU’s gross heat rate. EPA evaluated three 

ambient conditions – hourly capacity factor, hourly air temperature, and hourly surface water 

temperature – to assess the influence these conditions can have on coal-fired EGU’s gross heat 

rate. The assessment results indicate that each of the ambient conditions has significant influence 

on the variation in hourly gross heat rate of the 884 coal-fired EGUs during the study period 

(2002–2012). The agency chose to control only for the influence of hourly capacity factor and 

hourly ambient air temperature in two of the three analyses described below because: (1) 

comprehensive water temperature data from monitoring locations nearby and upstream of each 

of the 884 coal-fired EGUs were not available, and (2) water temperature data are highly 

 43 Beginning in reporting year 2002, the agency introduced numerous quality assurance checks on hourly emission 

data, enhancing the data quality. Therefore, for the purpose of the potential heat rate improvement analyses, the 

agency chose not to include data prior to 2002. 

44 See U Nowling, 2015. “Understanding coal power plant heat rate and efficiency,” Power. Available at 

http://www.powermag.com/understanding-coal-power-plant-heat-rate-and-efficiency 45 For an explanation of why EPA used gross heat rate in this heat rate improvement analysis, section V.C.3 of the 

final rule preamble of the CPP. 

46 See EPRI, 2011. Opportunities to Enhance Electric Energy Efficiency in the Production and Delivery of 

Electricity. Technical Report 1024651. Available at 

http://www.pserc.wisc.edu/documents/publications/special_interest_publications/EPRI_Electricity_Use_Report_Fin

al_1024651.pdf. The report explores the auxiliary electricity consumption at EGUs and finds that auxiliary energy 

use (and transmission and distribution losses) can be reduced by 15 percent through available technology options, 

including variable speed drives. 
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correlated with ambient air temperature data so, as described below, the additional influence of 

water temperature on heat rates is implicitly included. 

2.5.2.1 Capacity factor 

Coal-fired EGUs are designed to operate most efficiently near full capacity. In general, as 

an EGU’s hourly capacity factor declines, the EGU’s hourly gross heat rate increases. Across the 

full range of capacity factors, this trend is not linear. This relationship between hourly gross heat 

rate and capacity factor is illustrated in Figure 2-6. Each dot represents the average hourly gross 

heat rate for all measurements at a specific hourly capacity factor for four “sister units”47 in 

2012. The bottom chart shows the number of hourly measurements at each hourly capacity 

factor. The figure illustrates three effects that are broadly applicable to the 884 coal-fired EGUs: 

(1) average hourly gross heat rate is higher and shows more variation, or “scatter,” from the 

average at lower hourly capacity factors, (2) the gross heat rate trend flattens at around 60 – 70 

percent hourly capacity factor, and (3) the majority of operating hours are at higher hourly 

capacity factors. 

Figure 2- 6 Average hourly gross heat rates at partial load levels 

Notes: 2012 data are from four 650 MW coal-fired “sister units” at JM Stuart in Ohio; 

cumulative number of measurements exceeds 8,784 hours because it includes measurements from four “sister units”; 

the trend line is a power function in the form of y=c×xb

; 

average hourly gross heat rate axis does not start at zero to better illustrate changes in gross heat rate 

For each EGU, EPA used a least-squares linear regression to assess the relationship 

between hourly gross heat rates and hourly capacity factor.48 The hourly capacity factor 

explained about 18 percent of the variation in gross heat rate for the 884 coal-fired EGUs 

between 2002 and 2012. These results, however, conceal considerable variability. At some coal-

 47 Four 650 MW cell burner coal-fired EGUs at J M Stuart Station in Ohio. 

48 For each EGU, the annual coefficient of determination (i.e., the square of the correlation coefficient, or R2

) values 

were weighted using the EGU’s total annual gross electricity generation resulting in an EGU-specific generationweighted R2

. This approach controlled for any differences in average gross heat rates between years. The weighted 

R2

 values were averaged across all 884 coal-fired EGUs, resulting in an R2 value of 0.179. 
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fired EGUs hourly capacity factor has a greater influence on hourly gross heat rate. For example, 

hourly capacity factor can explain nearly 50 percent of variation in gross heat rate at some loadfollowing EGUs. The analysis indicates that as EGUs move from base load to load following 

(i.e., from high to lower hourly capacity factors), hourly capacity factor tends to have a larger 

influence on gross heat rate. 

Several commenters noted that the power sector saw dramatic changes during the 11-year 

study period, including significant declines in annual capacity factors at coal-fired EGUs. As 

discussed in the proposal TSD, it can be difficult to interpret the relationship between annual 

capacity factors and hourly capacity factors as used in the agency’s analyses. EGUs with high 

annual capacity factors (e.g., greater than 90 percent) must operate at high levels for most hours 

in a year. However, it is not possible to make such a generalization at lower annual capacity 

factors. For example, if a hypothetical coal-fired EGU operated at 90 percent capacity for six 

months and was offline for the remaining six months of the year, the EGU’s annual capacity 

factor would be only 45 percent – equivalent to an EGU that might have operated below 50 

percent capacity factor for the entire year. However, to assess the commenters’ concerns, the 

agency calculated two annual capacity factors for the 884 coal-fired EGUs – annual capacity 

factor and annual capacity factor during hours of operation. The latter represents the average 

annual capacity factor for the 884 coal-fired EGUs excluding hours in which the EGU did not 

operate, such as downtime for maintenance or due to low electricity demand. This latter capacity 

factor reflects the average capacity levels when EGUs are operating.

As shown in Table 2-3 and Figure 2-7, the annual average capacity factor of the 884 coalfired EGUs declined by approximately 10 percent in 2009 and, after a small increase in 2010, 

continued to decline through 2012. However, the annual capacity factor during operating hours 

(i.e., excluding non-operating hours) declined after 2010, but by a much smaller amount. This 

illustrates that during the 11-year study period, coal-fired EGUs operated fewer hours in later 

years, but during the hours they operated, they maintained high hourly capacity factors on 

average. 

Table 2-3 Annual capacity factors for 884 coal-fired EGUs 

Year Annual capacity 

factor 

Operating hours 

capacity factor 

2002 68 77 

2003 69 79 

2004 70 79 

2005 71 80 

2006 70 80 

2007 71 81 

2008 70 80 

2009 62 77 
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Year Annual capacity 

factor 

Operating hours 

capacity factor 

2010 65 78 

2011 61 76 

2012 53 72 

Figure 2-7 Change in annual capacity factors for 884 coal-fired EGUs relative to 2002 

Note: capacity factors are relative to 2002 capacity factor, the first year of the study period 

2.5.2.2 Ambient air temperature 

Ambient air temperature can affect gross heat rate in three ways: (1) ambient air (primary 

air) is mixed with fuel prior to combustion and a fraction of energy released during combustion 

heats the incoming air, (2) in many regions of the country temperature affects electricity demand 

and, as a result, some EGUs’ hourly capacity factors may increase when ambient temperatures 

are high, and (3) ambient air temperature influences cooling water temperatures, affecting an 

EGU’s efficiency. The relationship between hourly ambient air temperature and hourly capacity 

factor is complex. Generally, peak electricity demand in most parts of the U.S. occurs on the 

hottest days of the year. However, each EGU responds differently depending on design, duty 

cycle, meteorological conditions, electricity demand, and other factors. For example, a baseload 

plant may operate at high hourly capacity factors regardless of temperature. EPA assessed the 

correlation between hourly ambient air temperature and hourly capacity factor during the study 

period (2002–2012) and found the correlation to be very low.49

 49 The Pearson correlation coefficient for hourly ambient air temperature and hourly capacity factor from 2002–2012 

is -0.048. 
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For each EGU, EPA used a least-squares linear regression to assess the relationship 

between hourly gross heat rates and hourly ambient air temperature.50 The hourly ambient air 

temperature explained about 8 percent of the variation in gross heat rate. At approximately onefourth of the 884 coal-fired EGUs ambient air temperature had a greater influence on hourly 

gross heat rate than the influence of hourly capacity factor. At some individual EGUs, ambient 

air temperature may explain up to 30 percent of the variation in hourly gross heat rate. These are 

typically, but not exclusively, units with freshwater once-through cooling systems. Identifying 

temperature-responsive coal-fired EGUs allows us to understand why heat rate may increase 

during periods of peak demand. These are the EGUs where the ambient temperature ‘signal’ is 

an important variable. Gross hourly heat rates at a temperature-responsive EGU may increase as 

much 10 percent during high temperature days in summer months. 

2.5.2.3 Cooling water temperature 

As discussed earlier in this chapter and noted by commenters, cooling water temperature 

can have a significant influence on a coal-fired EGU’s heat rate. The availability of a cold heat 

sink in the condenser is important to maximize the EGU’s efficiency. The design of the heat 

exchanger, type of cooling system, availability of water, and temperature of water all have an 

impact on performance. Higher water temperatures typically reduce the effectiveness of the 

cooling system and, therefore, overall plant efficiency. 

Commenters suggested EPA should account for the influence of cooling water 

temperature in addition to ambient air temperature. The agency did not have comprehensive 

cooling water temperature data to assess the influence on gross heat rate at the time of the 

proposal. However, in response to commenters’ suggestions, the agency compiled hourly surface 

water temperature data for 45 coal-fired EGUs at 19 power plants in the Eastern Interconnection. 

For each EGU and each year with available data, EPA used a least-squares linear regression to 

assess the relationship between hourly gross heat rates and hourly water temperatures.51 The 

variation in hourly water temperature explained about 7 percent of the variation in gross heat 

rate. 

When EPA applied the same approach for the 45 coal-fired EGUs over the same time 

period using hourly ambient air temperature instead of hourly water temperature, the air 

temperatures explained approximately 6 percent of the variation in gross heat rate.52 The agency 

also examined relationships between hourly gross heat rate and several time-averaged 

temperatures (air and water temperatures) and found comparable results to the hourly ambient 

 50 For each EGU, the annual coefficient of determination (i.e., the square of the correlation coefficient, or R2

) values 

were weighted using the EGU’s total annual gross electricity generation resulting in an EGU-specific generationweighted R2

. This approach controlled for any differences in average gross heat rates between years. The weighted 

R2

 values were averaged across all 884 coal-fired EGUs, resulting in an R2 value of 0.083. 51 For each EGU, the annual coefficient of determination (i.e., the square of the correlation coefficient, or R2

) values 

were weighted using each EGU’s total annual gross electricity generation resulting in an EGU-specific generationweighted R2

. This approach controlled for any differences in average gross heat rates between years. The weighted 

R2

 values were averaged across all 45 EGUs, resulting in an R2 value of 0.072. 52 For each EGU, the annual coefficient of determination (i.e., the square of the correlation coefficient, or R2

) values 

were weighted using each EGU’s total annual gross electricity generation resulting in an EGU-specific generationweighted R2

. This approach controlled for any differences in average gross heat rates between years. The weighted 

R2

 values were averaged across all 45 EGUs, resulting in an R2 value of 0.057. 
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temperature values. For example, the rolling 24-hour water temperatures and rolling 24-hour 

ambient air temperatures explained 7 percent of the variation in hourly gross heat rate.53 Not 

surprisingly, the air temperature and water temperature are strongly related.54

Although the surface water data in this analysis were from the Eastern Interconnection, 

where 86 percent of the 884 coal-fired EGUs are located, the agency has no reason to believe, 

nor have commenters suggested, that this correlation would not hold elsewhere in the country. 

Studies suggest that ambient air temperature is similarly correlated with water temperature 

elsewhere in the country. See, for example, a report by the New Mexico Environment 

Department notes that “based on data for approximately 300 New Mexico streams, air 

temperature is highly correlated with stream water temperature...”55; Kaushal et al. found 

“[l]ong-term increases in stream water temperatures were typically correlated with increases in 

air temperatures”;56 and Webb et al. found there is usually a strong correlation between ambient 

air temperatures above 0° C and stream water temperatures (although the relationship may be 

non-linear at higher temperatures).57

Based on these results, the agency believes that hourly ambient air temperature is the 

appropriate variable to use in the potential heat rate improvement analyses because: (1) available 

hourly water temperature data are limited to a portion of the fleet, (2) air and water temperatures 

are highly correlated (i.e., simultaneously controlling for air temperature and water temperature 

appears highly redundant), and (3) the results from all of the agency’s analyses described above 

demonstrate that ambient air temperature and water temperature explained similar amounts of the 

variability in hourly gross heat rate. 

2.5.2.4 Capacity factor and ambient air temperature 

In addition to the regression analyses discussed above, EPA conducted a least-squares 

linear regression analysis to assess the relationship between hourly gross heat rate and the 

combination of hourly capacity factor and hourly ambient air temperature.58 For the 884 coalfired EGUs, the combination of hourly capacity factor and hourly ambient air temperature 

explained about 26 percent of variation in gross heat rate between 2002 and 2012. 

2.5.2.5 Accounting for the influence of factors outside coal-fired EGU operators’ control 

The objective of EPA’s analysis is to identify the potential heat rate improvements at 

coal-fired EGUs for the purpose of calculating state goals. Therefore, the agency attempted to 

 53 The R2

 value for rolling 24-hour water temperature and hourly gross heat rate was 0.071 and the R2 for rolling 24-

hour ambient temperature and hourly gross heat rate was 0.072. 

54 The Pearson correlation coefficient for hourly water temperature and 24-hour ambient air temperature is 0.74. 

55 See New Mexico Environment Department, 2011. Air-Water Temperature Correlation. Available at 

https://www.env.nm.gov/swqb/documents/swqbdocs/MAS/Protocols/Air-Water/Air-Water08-01-2011.pdf. 56 See SS Kaushal, GE Likens, NA Jaworski, ML Pace, AM Sides, D Seekell, KT Belt, DH Secor, and RL Wingate, 

2010. “Rising stream and river temperatures in the United States,” Frontiers in Ecology and the Environment. 8:461-

466. (DOI: 10.1890/090037). 57 See BW Webb, DM Hanna, RD Moore, LE Brown and F Nobilis, 2008. “Recent advances in stream and river 

temperature research,” Hydrological Processes. 22: 902-918 (DOI: 10.1002/hyp.6994). 

58 For each EGU, the annual coefficient of determination (i.e., the square of the correlation coefficient, or R2

) values 

were weighted using the EGU’s total annual gross electricity generation resulting in an EGU-specific generationweighted R2

. This approach controlled for any differences in average gross heat rates between years. The weighted 

R2

 values were averaged across all 884 coal-fired EGUs, resulting in an R2 value of 0.255. 
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control for many of the factors that influence gross heat rate but are beyond the control of the 

coal-fired EGU operator. For example, as stated above, EPA’s analysis controls for EGU design 

characteristics such as boiler type and size, age, generator size, coal type, and cooling system 

type because it compares each coal-fired EGU’s historical performance against the EGU’s own 

2012 performance. Because these design characteristics are typically constant over time, they do 

not influence the results of the EGU-level analyses. As mentioned earlier, age does not have a 

significant effect on gross heat rate. EPA controlled for the installation of air pollution control 

devices by analyzing gross heat rate. Because the impact of air pollution control devices’ 

auxiliary energy consumption does not affect gross electricity generation, the addition of controls 

does not influence the results of the gross heat rate analyses. 

In two of the three analytical approaches discussed below, EPA also controlled for hourly 

capacity factor and hourly ambient air temperature because these two environmental and 

operating factors are considered to be beyond the EGU operators’ control. To limit the influence 

of these two factors, the agency grouped each EGU’s hourly gross heat rate values into unitspecific “capacity-temperature bins” based on hourly capacity factor and hourly ambient air 

temperature. This enabled the agency to compare gross heat rate values for each coal-fired EGU 

during hours with similar capacity factor and ambient air temperature conditions, effectively 

controlling for a large influence on the variation in an EGU’s hourly gross heat rates. 

To create the capacity-temperature bins, the agency divided the range of hourly capacity 

factors into 12 groups, each separated by 10 percent of an EGU’s capacity (i.e., 0-9, 10-19, 20-

29, ... , 90-99, 100-109, greater than or equal to 110 percent), and the ambient air temperatures 

into 14 groups, each separated by 10° F (i.e., below -

10°, -10--1°, 0-9°, ... , 90-99°, 100-109°, 

greater than or equal to 110° F). The result is 168 capacity-temperature bins (12 X 14) for each 

of the 884 coal-fired EGUs. However, some capacity-temperature bins for an EGU might not 

have any data. 

At least one commenter expressed concern that the hourly capacity factor ranges were too 

large. They pointed to information that showed heat rate can vary significantly at low hourly 

capacity factors, resulting in differences of as much as 4 percent from a 30 percent hourly 

capacity factor to a 40 percent hourly capacity factor. Figure 2-6 illustrates this concept. At 

higher hourly capacity factors the hourly gross heat rate declines. However, the trend is more 

pronounced at low capacity factors, as noted by the commenter, and less prominent at higher 

capacity factors. EPA chose to maintain the size of the hourly capacity factor ranges for three 

reasons: (1) approximately 70 percent of the hourly values are greater than 70 percent capacity 

factor in each of the three interconnection regions and nationally (see Figure 2-8), (2) the data 

are skewed toward the higher end of each range (e.g., more hourly data points range from 75-79 

percent range than from 70-74 percent), and (3) reducing the range of the hourly capacity factor 

groups would double the number of capacity-temperature bins, resulting in fewer measurements 

in each bin and more data excluded from the analysis.59 EPA’s analyses do not indicate that 

using a smaller range for capacity factor would have a significant impact on the results. 

 59 As described below, in the efficiency and consistency analysis EPA excluded any capacity-temperature bins that 

had fewer than 15 hourly measurements for a single coal-fired EGU. 

Commented [A1]: Could this 12 x 14 table be included in 

an appendix for reference? 
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Figure 2- 8 Distribution of hourly capacity factors by interconnection 

Several commenters noted that EPA’s analysis does not account for all the factors that 

affect a coal-fired EGU’s heat rate. Specifically, these commenters mention the influence of 

geographic differences (e.g., seasonality, altitude), coal rank and quality, equipment degradation, 

and operating conditions. As stated above, the agency made every effort to control for design 

characteristics and ambient conditions that the agency believes to be outside the EGU operator’s 

control. The agency also controlled for capacity factor, which some commenters argued is 

partially under the operator’s control. However, the agency lacks sufficient information to 

determine the portion of capacity factor that is under the direct control of influence of the 

operator. Therefore, the agency chose to reasonably and conservatively control for the full effect 

of hourly capacity factor based on the results of the analysis described above. Regarding 

commenters’ assertion about the role of a coal-fired EGU’s location (i.e., geography) on heat 

rate, the agency believes that the approaches described below do control for these conditions 

because coal-fired EGUs are not considered mobile sources so by comparing each EGU’s 

performance from 2002 to 2012 against the EGU’s own performance in 2012 the agency 

controlled for both seasonal differences and location characteristics (e.g., altitude). Commenters 

also noted that coal-fired EGUs that changed coal rank during the study period might have 

significantly different heat rates depending on the rank of coal burned. The agency recognizes 

that: (1) different coal ranks have different heating values and moisture content, and (2) coalfired EGUs are generally designed for a specific coal rank and coal quality and deviations from 

that coal rank can adversely affect heat rate. However, the agency believes that for most coalfired EGUs coal rank and coal quality are controlled by the EGU operator through purchase 

contracts with fuel suppliers. Therefore, the agency chose not to control for coal rank or coal 

quality. Commenters also stated that equipment degrades over time, increasing heat rate. As 

discussed further in section 2.6.8 below, EPA recognizes that all equipment will degrade over 

time. However, some of the best practices that can be employed to improve heat rate involve 

properly operating and maintaining equipment to minimize the degradation and, when necessary, 

replacing equipment to maintain efficient operation of the plant. Therefore, the agency did not 

control for the effect of equipment degradation in the analyses described below because EGU 
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operators can limit equipment degradation through best practices for operation and 

maintenance.60 Similarly, the agency believes operating conditions at each coal-fired EGU are 

largely under the control of the EGU operator so it is appropriate for the agency to include 

variability due to operating conditions (with the exception of capacity factor.) 

2.5.3 Heat rate improvement approach “best historical performance” 

In the proposal TSD, EPA included an assessment of potential heat rate improvement 

based on the difference between each coal-fired EGU’s best rolling annual gross heat rate and its 

11-year (2002–2012) gross heat rate. Based on commenters’ suggestions and heat rate 

improvement analyses provided by commenters, the agency refined the approach and calculated 

1- and moving 2-year gross heat rates for each of the 884 coal-fired EGUs in the study for the 

years 2002–2012. The agency removed the 3-year averaging period discussed in the proposal 

TSD because, as noted by commenters, the differences in temperature profiles and loads from 

one year to the next are relatively small and not large enough to justify a 3-year rolling average. 

Commenters suggested that 1 year is sufficient because the agency already controls for capacity 

factor and temperature in some of the analytical approaches. However, the agency chose to 

conservatively include a 2-year rolling average to account for atypical annual operations due to 

factors such as extended outages, equipment failures, cooling water availability, or unusual 

demand patterns. The advantage of using the moving 2-year average is that it can smooth out the 

peaks and troughs and reduce the influence of a single unusual year (e.g., low utilization, unusual 

weather or climate conditions), while not diluting the results so much that it would obscure 

significant changes to annual gross heat rate. 

For each EGU, the agency compared the EGU’s best (i.e., lowest) 1- and moving 2-year 

gross heat rates to the EGU’s own 2012 average heat rate. As described above, this approach 

controls for design characteristics that remain constant and is not affected by the installation and 

operation of air pollution control devices. It does not, however, control for the variation in hourly 

gross heat rate attributable to hourly capacity factor and hourly ambient air temperature. 

2.5.3.1 Methodology 

The procedures for calculating the potential heat rate improvement are: 

1. For each coal-fired EGU, calculate the 1- and moving 2-year average gross heat rate. 

2. Identify each EGU’s best 1- and moving 2-year gross heat rate. 

3. Calculate each EGU-specific potential heat rate improvement – the difference between 

the best 1- and moving 2-year gross heat rate and the 2012 gross heat rate. 

4. Calculate the generation-weighted potential heat rate improvement based on 1- and 

moving 2-year gross heat rate within each interconnection region. 

 60 See section 2.6.8 for more information about equipment degradation and maintaining heat rate performance. 
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2.5.3.2 Example Step 1: The annual data for an example coal-fired EGU are shown in Table 2-4. 

Table 2-4 1- and moving 2-year heat rates for an example coal-fired EGU 

 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 1-year gross heat rate (Btu/kWh) 9,615 10,146 10,078 10,076 10,186 9,994 9,157 9,502 10,341 10,549 9,864 2-year gross heat rate (Btu/kWh) N/A 9,883 10,108 10,077 10,134 10,101 9,528 9,311 9,962 10,441 10,244 

Step 2: The lowest 1-year gross heat rate occurred in 2008; the lowest moving 2-year gross heat rate occurred in 2009 (2008-2009 

data). Step 3: The potential heat rate improvements for the example EGU are: 

Based on best 1-year gross heat rate: 1െቆଽଵହ଻ ಳ೟ೠ ೖೈ೓ ଽ଼଺ସ ಳ೟ೠ ೖೈ೓ቇ ൌ 7.2	݌݁ݎܿ݁݊ݐ

Based on best 2-year gross heat rate: 1െቆଽଷଵଵ ಳ೟ೠ ೖೈ೓ ଽ଼଺ସ ಳ೟ೠ ೖೈ೓ቇ ൌ 5.6	݌݁ݎܿ݁݊ݐ
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2.5.3.3 Results 

This approach calculates the potential heat rate improvement by determining what would 

have been possible if each of the 884 coal-fired EGUs had reproduced its demonstrated and 

achievable best performance from 2002 to 2012 in the year 2012. These results are conservative 

because they only account for a return to each EGU’s historical best annual performance and do 

not account for the full extent of heat rate improvement available through additional equipment 

upgrades and best practices. After calculating the difference between each EGU’s best 1- and 

moving 2-year gross heat and its 2012 gross heat rate, the agency calculated the average potential 

heat rate improvement for each interconnection region by weighting the EGU-specific potential 

improvements by each EGU’s 2012 gross electricity generation. The results of the analytical 

approach are presented in Table 2-5. 

Table 2-5 Potential heat rate improvement based on best historical performance, by 

interconnection 

Performance period Western Texas Eastern Nationally61

Best 1-year gross heat rate (%) 4.1 4.2 6.3 5.9 

Best moving 2-year gross heat rate (%) 2.6 3.1 4.9 4.6 

2.5.4 Heat rate improvement approach “best historical performance under similar 

conditions” 

The second analytical approach – best historical performance under similar conditions – 

is an outgrowth of the first and third analytical approaches based on comments and analyses 

provided by commenters. The second approach is similar to the first approach described above, 

but in this approach EPA controlled for each EGU’s hourly capacity factor and hourly ambient 

air temperature as described above. Within each capacity-temperature bin for each coal-fired 

EGU, EPA calculated the bin-specific 1-year and moving 2-year gross heat rates and compared 

the EGU’s best gross heat rate within that capacity-temperature bin to its 2012 gross heat rate 

within the same bin. In other words, the agency compared only the operating hours when 

capacity factor and ambient air temperature were similar for an EGU. The difference between an 

EGU’s best gross heat rate and the 2012 gross heat rate, expressed as a percentage, represents the 

potential heat rate improvement for that EGU in that capacity-temperature bin. EPA weighted the 

results on 2012 electricity generation to calculate the potential heat rate improvement for the 

coal-fired EGU fleet in each interconnection. One advantage of this approach is that it controls 

for factors that explain a significant portion of differences in an EGU’s gross heat rate and is 

based on each EGU’s historical mid-term (i.e., 1- or moving 2-year) performance. 

2.5.4.1 Methodology 

The procedures for calculating the potential heat rate improvement using this approach 

are the same as those shown above with one exception: in the first approach, the agency 

calculated a single potential heat rate improvement for each EGU then calculated a generationweighted average potential heat rate improvement within each interconnection region. In this 

 61 EPA has provided nationwide results for purposes of comparison; they are not part of the methodology. 
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second approach, the agency calculated a potential heat rate improvement for each of the 168 

capacity-temperature bins for each coal-fired EGU, and then calculated a generation-weighted 

average potential heat rate improvement within each interconnection region. 

2.5.4.2 Results 

The results of this second analysis are shown in Table 2-6. 

Table 2-6 Potential heat rate improvement based on best historical performance under 

similar conditions, by interconnection 

Performance period Western Texas Eastern Nationally62

Best 1-year gross heat rate (%) 4.7 4.9 6.9 6.6 

Best moving 2-year gross heat rate (%) 3.1 3.5 5.3 5.0 

One reason this approach, which controls for the influence of hourly capacity factor and 

hourly ambient air temperature, yields interconnection-level results that are higher than the first 

approach is that it relies on the lowest 1- and moving 2-year gross heat rates within each 

capacity-temperature bin. Therefore, unlike the first approach where the “best” performance for 

each coal-fired EGU is from one or two years across all capacity factor and temperature 

conditions, this second approach may have different “best” years for the different capacitytemperature bins. 

This analytical approach determines the potential heat rate improvement if each EGU 

reproduced its best demonstrated and achievable 1- and moving 2-year heat rates while 

controlling for the influence of hourly capacity factor and hourly ambient temperatures. These 

results are conservative because they account only for potential heat rate improvements if each 

coal-fired EGU returned to its best performance; it does not account for the full extent of heat 

rate improvements available through additional equipment upgrades and best practices. 

2.5.5 Heat rate improvement approach “efficiency and consistency under similar 

conditions” 

The two approaches described above are based on the general principle that coal-fired 

EGUs are capable of returning to historically demonstrated and achievable best annual average 

heat rates (over a 1- or moving 2-year period). The third approach, which was described 

extensively in the proposal TSD, uses a different methodology to determine the potential heat 

rate improvement. This third approach is based on the principle that coal-fired EGUs are capable 

of operating more consistently with their historically demonstrated and achievable best hourly 

heat rates. For this approach, the agency grouped each coal-fired EGU’s data by capacitytemperature bin and determined a 1- and moving 2-year gross heat rate “benchmark.”63 This 

benchmark was based on each coal-fired EGU’s 10th percentile hourly gross heat rate during 

each 1- and moving 2-year period for each capacity-temperature bin. The 10th percentile value 

means 10 percent of all hourly values for the 1- or 2-year period were below the selected value 

(i.e., the benchmark is demonstrated by 10 percent of all measurements in each capacity-

 62 EPA has provided nationwide results for purposes of comparison; they are not part of the methodology. 

63 EPA excluded capacity-temperature bins that had fewer than 15 hourly measurements for a single coal-fired EGU. 
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temperature bin). The agency chose the 10th percentile because it represents a demonstrably 

achievable gross heat rate indicating efficient operation of the EGU, but ignores unusually low 

outlier values.64 Furthermore, the 10th percentile is a commonly used statistical level for 

determining if particular values are unusually low relative to the average value.65 

EPA did not assume a coal-fired EGU could regularly achieve the benchmark gross heat 

rate under similar hourly capacity factor and hourly ambient air temperature conditions. Instead, 

the agency calculated the potential heat rate improvements from greater consistency (i.e., less 

variability of heat rate) such that each EGU’s hourly gross heat rates that were greater than the 

benchmark for the capacity-temperature bin were adjusted downward by a specific percentage 

(consistency factor) to represent more consistently efficient operation of the EGU. Using this 

conservative approach, the hourly gross heat rate values adjusted most in absolute terms were the 

highest values (i.e., less-efficient hours of operation) that indicate a relative failure to fully 

employ heat rate improvement measures. The net result is that the post-adjustment distribution of 

hourly heat rate values has a smaller variability in heat rate, with the average value nearer the 

benchmark value, while the lowest heat rate values remain unchanged (see Figure 2-9 and 

example below). This is based on the principle that a coal-fired EGU following best practices 

should be able to consistently operate closer to the demonstrated and achievable benchmark heat 

rate. 

In the proposal TSD, EPA assessed several different consistency factors ranging from 10 

to 50 percent and proposed 30 percent because the results were similar to results achieved 

through other analytical approaches (e.g., 3-year rolling averages relative to the 11-year 

average), accorded with EPA experts’ engineering judgment, and because 30 percent was in the 

middle of the reasonable range evaluated by the agency. Several commenters suggested that this 

choice of values was arbitrary and could have easily been higher or lower had EPA selected the 

middle of a different range of values. To identify a consistency factor with more precision for 

this analytical approach, EPA analyzed the EGUs’ historically demonstrated level of consistency 

(i.e., variability) for hourly gross heat rate over 1-year and moving 2-year periods between 2002 

and 2012 for each capacity-temperature bin. The agency calculated the mean-centered standard 

deviation of hourly gross heat rate values for each 1- and 2-year period for the 884 coal-fired 

EGUs for all capacity-temperature bins.66 The lowest standard deviation – a measure of 

dispersion – for the 1- and moving 2-year periods were then compared to the mean-centered 

standard deviation of 11-year gross heat rate data. The ratio of the 1- and moving 2-year standard 

deviations to the 11-year standard deviation represent the potential consistency improvement at 

 64 During the development of the dataset the agency excluded extreme outliers – hourly gross heat rate values that 

were greater than ±2.6 standard deviations from the EGU’s mean gross heat rate. 

65 Common statistical levels include the 10th and 90th percentiles, the 5th and 95th percentiles, and the 1st and 99th 

percentiles. EPA considered these other levels but selected the 10th percentile because it is a common statistical 

level, is conservative, and is substantially less likely to have been an outlying value than the 5th or 1st percentile. If 

EPA had selected the 5th percentile as the benchmark, the facility would have half as many hours of historical 

operation at or below that level and the overall resulting potential heat rate improvement would have been 

substantially larger. 

66 The mean-centered standard deviation shows the extent of variation relative to the mean and allows for 

meaningful comparison of variability from coal-fired EGUs that can have widely different average gross heat rates. 

The mean-centered standard deviation, also called the coefficient of variation, is calculated by dividing each coalfired EGU’s standard deviation for the capacity-temperature bin by the EGU’s capacity-temperature bin’s average 

gross heat rate. It is reasonable to use the standard deviation when evaluating the potential to reduce variability 

because standard deviation is the most common measure of the spread, or variation, of values within a dataset. 
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each interconnection. In other words, this approach compares the EGU’s most consistent 

performance (i.e., least variability) for each capacity-temperature bin over a 1- or moving 2-year 

period to the EGU’s consistency (i.e., variability) over the study period (2002-2012). 

As described above at the beginning of section 2.5, EPA replaced the 11-year baseline 

used in the proposal TSD with a 2012 baseline in this analysis. The refined approach – 

comparing each EGU’s best performance against its 2012 baseline performance – recognizes 

actions that improve gross heat rate performance because better practices that result in lower 

gross heat rates in 2012 reduce the estimated potential heat rate improvement. 

Several commenters noted that reduced variability does not necessarily equate to 

improved heat rates. EPA agrees with commenters that reducing variability alone does not result 

in lower heat rates and, therefore, lower CO2 emissions. For example, if an EGU were to operate 

more consistently at a higher heat rate (i.e., less efficient), the variability would decrease, but the 

heat rate would increase. However, the agency is not simply asking for less variability in 

operation at existing coal-fired EGUs. Instead, the agency is assessing the average heat rate 

improvement that would result if coal-fired EGUs had operated more consistently nearer their 

gross heat rate benchmarks. Both the benchmark gross heat rates and consistency factors were 

demonstrated and achieved by the EGUs from 2002–2012 during hours with similar hourly 

capacity factors and hourly ambient air temperatures. 

2.5.5.1 Methodology 

The procedures for calculating the consistency factor are: 

1. For each coal-fired EGU, calculate the 1-year average gross heat rate for each capacitytemperature bin. 

2. For each coal-fired EGU, calculate the difference, as a percentage, between every hourly 

gross heat rate value and the relevant 1-year average gross heat rate within each capacitytemperature bin. 

3. Within each interconnection, calculate the mean-centered standard deviation of the 

differences calculated in step 2 for all coal-fired EGUs and capacity-temperature bins for 

each 1-, moving 2-, and 11-year period. 

4. Within each interconnection, calculate the consistency factor by comparing the lowest 1- 

and 2-year standard deviation and the 11-year standard deviation from step 3. 

The procedures for calculating the potential heat rate improvement are: 

1. For each coal-fired EGU, determine the gross heat rate benchmarks – the 10th percentile 

hourly gross heat rate – for each 1- and moving 2-year period within each capacitytemperature bin. 

2. Identify each EGU’s best 1- and moving 2-year gross heat rate benchmark within each 

capacity-temperature bin. 

Commented [A2]: Can you please elaborate on these two 

steps. 
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3. For each coal-fired EGU, calculate the adjusted gross heat rate for each capacitytemperature bin: 

a. For each hourly gross heat rate value greater than the 1- or moving 2-year benchmark 

calculate the difference between the hourly value and the relevant benchmark; 

b. Multiply the difference by the relevant 1- or moving 2-year interconnection-specific 

consistency factor; and 

c. Subtract the result from the hourly gross heat rate value. 

4. Within each interconnection, calculate the 11-year generation-weighted adjusted heat rate 

average for the 1- and moving 2-year benchmark using the adjusted gross heat rate values 

from step 3. 

5. Calculate the generation-weighted potential heat rate improvement by comparing the 11-

year adjusted heat rate average for the 1- and moving 2-year benchmarks from step 4 

against the 2012 generation-weighted gross heat rate. 

One commenter noted that EPA’s analysis in the proposal TSD used heat input instead of 

gross heat rate to assess potential heat rate improvements. The commenter noted that EPA’s 

assumption of an equivalent level of gross electricity generation across the full range of the 

capacity factor bin skewed the results. EPA agrees with the commenter that using the gross heat 

rate for the analysis provides more accurate results. Therefore, the agency changed the approach 

to use hourly gross heat rate, calculated as heat input divided by gross electricity generation. 

2.5.5.2 Example 

Step 1: The 1- and moving 2-year gross heat rate benchmarks (i.e., 10th percentile values) for the 

90–99 percent hourly capacity factor/70–79° F temperature bin for an example coal-fired EGU 

are shown in Table 2-7. 

Table 2- 7 1- and moving 2-year 10th percentile benchmark gross heat rate for an example 

coal-fired EGU in capacity factor range 90-99 percent and temperature range 70-79° F 

(Btu/kWh) 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 

1-year benchmark 9166 9978 9659 9745 9839 9497 8625 9005 9544 9729 9780 

2-year benchmark N/A 9253 9774 9696 9786 9554 8743 8728 9142 9661 9769 

Step 2: The lowest 1-year gross heat rate benchmark is from 2008; the lowest moving 2-year 

gross heat rate benchmark occurred in 2009 (2008–2009 data). There are 284 hours of operation 

in the capacity-temperature bin with a gross heat rate lower than the 1-year benchmark of 8,625 

Btu/kWh. For the moving 2-year benchmark, 434 hours of operation in the capacity-temperature 

bin had a gross heat rate lower than 8,728 Btu/kWh. 
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Step 3: The EGU’s adjusted gross heat rates for the capacity-temperature bin calculated with the 

1-year benchmark and the Eastern interconnection’s 1-year consistency factor (.455), and 

moving 2-year benchmark and the Eastern interconnection’s 2-year consistency factor (.381), are 

shown in Figure 2-9. 

Figure 2-9 Frequency of hourly gross heat rates measured and adjusted, 2002–2012 for an example 

coal-fired EGU in capacity factor range 90–99 percent and temperature range 70–79° F

Step 4: The 11-year measured and adjusted gross heat rate using the 1- and moving 2-year 

benchmarks and consistency factors for the example EGU in the capacity-temperature bin are 

listed in Table 2-8. 

Table 2-8 Measured and adjusted heat rate based on efficiency and consistency under 

similar conditions for one capacity-temperature bin for an example coal-fired EGU 

Measured/adjusted 2002–2012 

gross heat rate

(Btu/kWh) 

Measured gross heat rate 9,968 

Adjusted gross heat rate – 1-year benchmark and consistency factor 9,353 

Adjusted gross heat rate – 2-year benchmark and consistency factor 9,492 

Step 5: The potential heat rate improvement for the example EGU in the capacity-temperature 

bin based is: 

Based on 1-year benchmark and consistency factor: 1 െ ቆ

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Commented [A3]: Should this be presented as a percent? 

Commented [A4]: It would be helpful is EPA lays out 

step-by-step the process for calculating the interconnection 

consistency factors presented here. 
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Based on 2-year benchmark and consistency factor: 1 െ ቆ

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2.5.5.3 Results 

This approach calculates the potential heat rate improvement by determining what would 

be possible if each of the 884 coal-fired EGUs had operated more efficiently and consistently 

nearer their historically demonstrated and achievable “best” gross heat rate from 2002 to 2012. 

First, EPA calculated the ratio of the least variability in the period 2002 to 2012, defined by 

standard deviation, to the average variability to establish interconnection-specific consistency 

factors (see Table 2-9). Next, the agency determined the average potential heat rate improvement 

for each interconnection by calculating an adjusted heat rate for each EGU based on the EGU’s 

benchmark and the relevant interconnection consistency factor, and weighting the EGU-specific 

potential improvements by the EGU’s 2012 gross electricity generation. The results of the 

analytical approach are presented in Table 2-10. 

Table 2-9 Consistency factors based on best historical performance under similar 

conditions, by interconnection 

Performance period Western Texas Eastern Nationally

Best 1-year consistency 46.9 46.6 45.5 45.8 

Best 2-year consistency 38.4 37.1 38.1 38.2 

 

Table 2-10 Potential heat rate improvement based on efficiency and consistency under 

similar conditions, by interconnection 

Performance period Western Texas Eastern Nationally67

Best 1-year benchmark and consistency (%) 3.5 3.7 5.6 5.3 

Best 2-year benchmark and consistency (%) 2.1 2.3 4.3 4.0 

2.5.6 Results 

Each of the three analytical approaches described above is based on unit-specific 

comparisons between individual EGUs’ more efficient and baseline performances. In part for 

this reason, each approach constitutes a reasonable means of assessing the potential for heat rate 

improvements by affected coal-fired EGUs within the regional interconnections. Because the 

analyses are based on actual historical gross heat rate data for each of the 884 coal-fired EGUs in 

the study population, the EPA is confident that the potential heat rate improvements identified on 

the regional basis through these approaches are feasible. 

Although each of these three analytical approaches is independently reasonable, EPA’s 

overall methodology adopts as “building block 1” the most conservative value identified by any 

 67 EPA has provided nationwide results for purposes of comparison; they are not part of the methodology. 

Commented [A5]: Aren’t these values %s? 
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approach. For each analytical approach, EPA calculated potential heat rate improvements based 

on the best 1-year and moving 2-year performance for each EGU. The results from the moving 

2-year analyses will always be more conservative than the 1-year analyses.68 Therefore, to be 

conservative and ensure that the potential heat rate improvements are supported by the weight of 

evidence, EPA compared the results of the moving 2-year analyses shown in Table 2-11.69

Table 2-11 Potential heat rate improvement for best moving 2-year period, by 

interconnection 

Analytical approach Western Texas Eastern Nationally70

Best historical performance 2.6 3.1 4.9 4.6 

Best historical performance under similar 

conditions 

3.1 3.5 5.3 5.0 

Efficiency and consistency under similar 

conditions 

2.1 2.3 4.3 4.0 

For the final rule, the “efficiency and consistency under similar conditions” approach 

provides the most conservative result for all three regions. Accordingly, the tripartite 

methodology adopts those results for purposes of calculating the relevant CO2 emission 

performance rates and accompanying state goals.71 Specifically, a well-supported and 

conservative estimate of the potential heat rate improvements (and accompanying reductions in 

CO2 emission rates) that affected coal-fired EGUs in the Western interconnection is 2.1 percent, 

in the Texas interconnection is 2.3 percent, and in the Eastern interconnection is 4.3 percent. The 

agency believes these values are conservative and that EGUs have demonstrated these gross heat 

rates were achieved during the study period. 

It is important to note that these potential heat rate improvements are based on the 

difference between coal-fired EGUs’ past performance and their 2012 performance; they do not 

reflect additional opportunities for heat rate improvements from best practices and equipment 

upgrades that could have been (and still can be) cost-effectively implemented at coal-fired 

EGUs. The agency decided not to pursue a separate heat rate improvement target for specific 

equipment upgrades due to (1) insufficient information about the current deployment of the 

technologies specified in the proposal TSD, (2) the availability of data necessary to conduct the 

statistical analyses to identify potential heat rate improvement, and (3) potential impact of past 

 68 The “best” gross heat rate over a moving 2-year period will always be higher than the best gross heat rate over a 

1-year period because the moving 2-year period includes at least one non-best year (i.e., a year with higher average 

gross heat rate values). 

69 The results of EPA’s inherently less conservative 1-year analyses can be found in section V.C of the final rule 

preamble of the CPP. 

70 EPA has provided nationwide results for purposes of comparison, they are not part of the methodology. 

71 The “best historical performance” and “best historical performance under similar conditions” approaches identify 

greater potential heat rate improvement in each region. Accordingly, they inherently support the feasibility of the 

more conservative values identified by the “efficiency and consistency under similar conditions” approach. 
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deployments of heat rate improvement technology at some EGUs that might already be reflected 

in the results of the analyses described above. 

2.6 Assessment of key comments 

EPA received more than 1,500 comments on building block 1, including the methodology 

and assumptions for calculating potential heat rate improvements. Several of the comments are 

addressed above and below, and in the preamble with the remaining comments addressed in the 

response to comments (RTC). EPA appreciates the information and insights that commenters 

shared about the proposal. The information assists the agency in developing a stronger, more 

effective rule. Below are several key comments related to potential heat rate improvement and 

the additional analyses conducted by EPA to respond to those comments. 

2.6.1 Effect of heat rate improvement implemented during study period 

Several commenters expressed concern that measures implemented at specific EGUs to 

improve heat rate between 2002 and 2012 would result in greater variability of heat rate and, 

therefore, inflate the potential heat rate improvements. EPA acknowledges variability from heat 

rate improvements would affect the results of the approach used for the proposal. However, by 

changing the methodology to use a 2012 baseline for the analytical approaches described in this 

chapter, any heat rate improvements made during the study period and maintained through 2012 

are accounted for and do not result in additional potential heat rate improvement. 

2.6.2 Impact of air pollution controls installed during study period 

Commenters described many of the air pollution control devices that were installed at 

coal-fired EGUs between 2002 and 2012, noting that these devices can have significant auxiliary 

energy requirements (i.e., parasitic load) that reduce the amount of electricity available for 

distribution on the regional interconnection. As a result of lower net electricity generation, the 

EGU’s net heat rate increases. Many commenters recommended that EPA consider the auxiliary 

energy requirements of these controls when assessing the potential heat rate improvement. EPA 

recognizes that air pollution control devices have auxiliary power requirements and a significant 

amount of coal-fired EGUs were retrofitted with air pollution controls during the study period. 

However, EPA rejects the recommendation to credit the auxiliary power requirements in the 

analysis because the agency’s analysis is based on gross heat rate and, therefore, is not affected 

by auxiliary power requirements of air pollution controls.72

2.6.3 Impact of CO2 emissions from SO2 pollution control devices 

Commenters noted that the addition of wet flue gas desulfurization (WFGD or wet 

scrubber) technologies result in increased process CO2 emissions because of the dissolution of 

limestone to capture SO2.

73 Because heat input, the numerator for calculating heat rate, is based 

on an EGU’s measured CO2 emissions, the additional process CO2 emissions result in artificial 

increases in calculated gross heat rate. Commenters suggest that process CO2 emissions can be 

“several percentage points.” To assess the range of potential impacts on EPA’s analysis from 

 72 See supra note 45. 73 The reaction in the WFGD absorber is summarized by SO2+CaCO3+1⁄2H2O → CaSO3+1⁄2H2O+CO2 (see RK 

Srivastava, 2000. Controlling SO2 emissions: a review of technologies. EPA report EPA/600/R-00/093. Available at 

http://nepis.epa.gov/Adobe/PDF/P1007IQM.pdf. 
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process CO2 emissions, the agency estimated the incremental CO2 from the WFGD chemical 

reaction. The results indicate that retrofit WFGD installed on existing coal-fired EGUs between 

2002 and 2012 increased 2012 CO2 emissions (and calculated heat input) by an average of no 

more than 0.7 percent for those EGUs in 2012. 

To calculate the CO2 emissions, the agency first identified the 121 existing coal-fired 

EGUs that installed retrofit limestone WFGD between 2002 and 2012. Collectively these EGUs 

have approximately 59 GW of electricity generating capacity. Next, EPA reviewed monthly fuel 

transactions and calculated the weighted average sulfur content of fuel deliveries to the relevant 

power plants.74 Finally, the agency calculated the process CO2 emissions that could result at 85 

and 95 percent removal efficiencies (see Table 2-11). Due to data limitations – EGU-level fuel 

consumption data are not available – the agency assumed that: (1) fuel delivered to the power 

plant in 2012 was representative of coal burned in the WFGD-equipped coal-fired EGU, and (2) 

EGUs operated the WFGD to remove 85 to 95 percent of the sulfur. The resulting process CO2

emission increase at coal-fired EGUs that installed retrofit limestone WFGD ranges from 0.2 

percent (Texas) to 1.0 percent (Eastern). It should be noted, however, that this is a very 

conservative estimate for the following reasons: (1) some of the sulfur is bound in pyrites and 

well-maintained coal pulverizers/grinders should remove much of the pyritic-bound sulfur, (2) a 

small amount of the combustion CO2 might be absorbed in the WFGD slurry, and (3) in 2012 

many EGUs did not operate their WFGD at full capacity. 

Table 2-11 Increase in 2012 CO2 measurements due to retrofit limestone wet flue gas 

desulfurization 

 Western Texas Eastern Nationally

Number of retrofit limestone WFGD 6 6 109 121 

Average sulfur content (%) of 2012 coal deliveries 0.55 0.43 1.82 1.63 

Total quantity (1,000 tons) of 2012 coal deliveries 12,375 11,637 148,631 172,644 

Potential process CO2 increase (%) from WFGD 0.3 0.2 0.9-1.0 0.8-0.9 

Note: Interconnection-level totals may not add up to national-level totals due to rounding; 

Potential process CO2 emissions are based on 85 and 95 percent removal rates, Western and Texas values round to the same 

quantity for 85 and 95 percent removal rates; 

Retrofits are for limestone WFGD only and do not account for other WFGD that do not produce process CO2 emissions 

2.6.4 Impact of future retrofit air pollution controls to comply with EPA and state 

environmental requirements 

This rule establishes CO2 intensity goals based on net electricity generation for each state 

using the state’s 2012 net electricity generation baseline. Many commenters noted that air 

pollution controls installed after 2012, many of which are required to comply with other federal 

and state environmental regulations, will require auxiliary power and therefore will increase 

EGUs’ net heat rate and CO2 intensity. These commenters suggested that EPA should account 

for the addition of new air pollution controls when calculating the state goals. EPA evaluated the 

potential impact of the additional pollution controls that are expected to be installed between 

 74 Monthly fuel transactions are reported at the plant level on form EIA-923. 
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2013 and 2025 to comply with rules such as the Mercury and Air Toxics Standards (MATS), 

Clean Air Interstate Rule (CAIR), Cross-State Air Pollution Rule (CSAPR), Regional Haze Rule, 

as well as consent decrees and state policies. The agency’s analysis, described below, indicates 

that the potential impact on net heat rate and, therefore, CO2 intensity is small – approximately 

0.3 percent – in 2025. 

To assess the anticipated impact of new retrofit air pollution controls on net heat rate, 

EPA used data and information from EPA’s Power Sector Modeling Platform v.5.15.75 The Base 

Case is a projection of power sector activity, taking into account existing federal and state air 

emission laws and regulations. The Base Case includes projected installations of air pollution 

controls and EGU-level net electricity generation in the years 2017, 2018, and 2025. The agency 

compared the Base Case 2025 installations of air pollution controls to the 2012 installations 

listed in the National Electric Energy Data System (NEEDS) v.5.15. Specifically, the agency 

identified predicted additions of WFGD, dry flue gas desulfurization (DFGD), selective catalytic 

reduction (SCR), and selective non-catalytic reduction (SNCR) (see Table 2-12). 

 

Table 2-12 Predicted additional capacity (MW) with air pollution controls installed by 

2025, by interconnection 

Air pollution control Western Texas Eastern

WFGD: wet flue gas desulfurization (MW) 283 0 18,214 

DFGD: dry flue gas desulfurization (MW) 505 584 15,388 

SCR: selective catalytic reduction (MW) 11,194 0 13,618 

SNCR: selective non-catalytic reduction (MW) 0 391 4,014 

To estimate the impact on heat rates, the agency used the heat rate penalties (i.e., 

auxiliary power requirements) from EPA’s Power Sector Modeling Platform v.5.13 (see Table 2-

13).76 Each EGU’s 2012 net heat rate was adjusted for the assumed heat rate penalties and 

multiplied by the EGU’s projected 2025 net electricity generation to estimate the incremental 

heat input required to operate the retrofit air pollution controls. The incremental heat input at 

EGUs with additional air pollution controls was aggregated to the interconnection region and 

then divided by the region’s pre-control heat input.77 The anticipated impacts of the retrofit air 

pollution controls on net heat rate in 2025 are 0.31 percent in the Western Interconnection, 0.06 

percent in the Texas Interconnection, and 0.31 percent in the Eastern Interconnection. 

Table 2-13 Assumed heat rate penalty for air pollution controls 

 75 More information about the Power Sector Modeling Platform, including data, assumptions, and documentation is 

available at http://www.epa.gov/airmarkets/programs/ipm/psmodel515.html. 76 Information on air pollution controls is taken from Chapter 5 available at 

http://www.epa.gov/airmarkets/documents/ipm/Chapter_5.pdf. 77 The pre-control heat input is calculated as 2012 net heat rate (before additional air pollution controls) multiplied 

by 2025 net electricity generation. 
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Air pollution control Heat rate penalty (%)

WFGD: wet flue gas desulfurization 1.70 

DFGD: dry flue gas desulfurization 1.33 

SCR: selective catalytic reduction 0.56 

SNCR: selective non-catalytic reduction 0.78 

This estimate is conservative for at least two reasons: (1) EPA’s cost performance 

assumptions tend to overestimate the auxiliary energy requirements from individual retrofit 

controls, and (2) at some EGUs these newer pollution control devices will replace existing 

pollution control devices. Accordingly, for these EGUs, the increase in net heat rate due to power 

required to operate new controls will be at least partially offset by the decrease in net heat rate 

caused by removal of the control devices currently in place. The retrofit of air pollution control 

devices also present opportunities to improve net heat rate by replacing some equipment (e.g., 

fans, pumps, air heaters, economizers) with more efficient equipment.78 In addition, future 

technological innovations or advances in emission control practices may reduce the need for 

retrofit emission controls. 

Therefore, for the reasons described above, the agency has determined that when 

calculating overarching state goals, it is not necessary to account for the net heat rate impact of 

predicted installations of controls. However, EPA recognizes that states may choose to account 

for the installation of pollution controls at coal-fired EGUs after 2012 when developing their 

state plans. 

2.6.5 Impact of cycling operations and lower capacity factors on heat rate 

Several commenters expressed concern that the application of the other building blocks 

that make up the best system of emissions reductions will result in coal-fired EGUs operating at 

lower capacity factors and cycling more frequently during the interim and full compliance 

periods. Commenters noted that at lower hourly capacity factors efficiency decreases and heat 

rate increases (for example, see Figure 2-6) making improving heat rate even more challenging. 

EPA disagrees that the application of the other building blocks from the best system of emission 

reductions necessarily results in more cycling at existing coal-fired EGUs for the following 

reasons: (1) many coal-fired EGUs are expected to retire between 2012 and 2020, reducing the 

remaining capacity of coal-fired EGUs during the interim and full compliance periods; (2) EPA 

modeling of electricity generation in 2030 indicate that the remaining coal-fired EGUs will have 

higher annual capacity factors than the 884 coal-fired EGUs in 2012 – the baseline for the 

agency’s heat rate improvement analyses; and (3) states have flexibility when developing their 

state plans and may choose policies that do not require heat rate improvements at specific EGUs. 

A significant amount of coal-fired EGU capacity has retired since 2012 and even more is 

expected to retire by 2020. For the 884 coal-fired EGUs in the agency’s analyses, more than 

53,000 MW of generator capacity is expected to retire. This represents approximately 16 percent 

 78 For example, see D Osowski, 2014. “Bagging Two Birds with One Economizer,” Power Engineering. Available at 

http://www.power-eng.com/articles/print/volume-118/issue-11/departments/clearing-the-air/bagging-two-birdswith-one-economizer.html. 
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of the capacity from the 884 coal-fired EGUs across the nation. In the Western Interconnection, 

coal-fired EGU owners and operators have officially announced 6,000 MW of capacity, 16 

percent of total capacity, will retire in 2020 or earlier (see Figure 2-10). The agency does not 

have information about any official planned retirements in the Texas Interconnection. In the 

Eastern Interconnection, EGU owners and operators have officially announced more than 47,000 

MW of capacity, 17 percent of total capacity, will retire in 2020 or earlier (see Figure 2-11). 

Because less coal-fired electricity generating capacity will be available for dispatch, the 

remaining coal-fired EGUs are expected to operate at higher annual capacity factors. 

Figure 2- 10 Official completed and planned retirements of coal-fired EGUs in Western 

Interconnection, 2012–2020

Note: Generator capacity scale is 1/10 of scale in Eastern Interconnection (Figure 2-11) 
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Figure 2- 11 Official completed and planned retirements of coal-fired EGUs in Eastern 

Interconnection, 2012–2020

EPA's power sector modeling for this rule predicts that annual capacity factors for coalfired EGUs in 2030, with the rule in full effect, will be higher than the EGUs’ capacity factors in 

2012. As noted above, the increased utilization of existing coal-fired EGUs that remain in 

operation is due in large part to significant retirements of coal-fired EGUs that have already 

occurred or are expected to occur as well as growth in electricity demand. Nationally, net annual 

capacity factors – net electricity generation divided by net summertime capacity – at coal-fired 

EGUs is predicted to be approximately 70 percent under a rate-based goal and 75 percent under a 

mass-based goal while the 2012 net annual capacity factor averaged 55 percent.79 The values for 

the interconnections are shown in Table 2-14. While these values represent annual capacity 

factors and not hourly capacity factors, the substantial increase in annual capacity factors at 

existing coal-fired EGUs in all interconnections except Texas leads to a reasonable conclusion 

that the remaining coal-fired EGUs as a whole will operate at higher levels in 2030 than they did 

in 2012, the baseline for this heat rate improvement study. For the Texas interconnection, the 

capacity factors are anticipated to be approximately the same under a mass-based policy 

approach and lower under a rate-based approach. The state of Texas has the flexibility to 

consider this projected change in annual capacity factors when designing the state plan. 

Table 2-14 Annual net capacity factors (percent) in 2012 and 2030, by interconnection 

Interconnection 2012 2030 mass 

goal 

2030 rate 

goal 

Western 69.5 80.5 79.5 

 79 The 2012 net annual capacity factors were calculated from the 2012 baseline data using the eGRID methodology. 

For the 947 coal steam EGUs in the CONUS, the capacity factor was calculated as net electricity generation 

(MWh)/[8784 hours X net summertime capacity (MW)]. 
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Texas 66.5 66.5 55.8 

Eastern 52.8 74.9 69.5 

CONUS 55.3 74.7 69.5 

2.6.6 Influence of flow monitoring method on historical heat rate data 

To calculate heat input at a coal-fired EGU, the operator must measure the flow rate of 

flue gases as they pass through the stack (or duct). Initially, all coal-fired fired EGUs used EPA 

Reference Method 2 to measure stack gas flow.80 However, in 1999 EPA introduced new 

reference methods to address angular flow (Methods 2F and 2G) and the effect of the stack walls 

on gas flow (Method 2H). In general, these alternative measurement methods reduce or eliminate 

the over estimation of stack gas flow that results from the use of method 2 when the specific flow 

conditions (e.g., angular flow) are present in the stack. Generally, the alternative methods lead to 

lower flow rates and as a result, lower heat input. After the introduction of these new methods, 

many coal-fired EGUs adopted the alternative methods to measure flow and calculate mass 

emissions.81 However, coal-fired EGUs are not required to use the alternative measurement 

methods and they may change methods when conducting a RATA. Commenters have 

hypothesized that much of the variability in gross heat great is caused by coal-fired EGUs 

changing from one flow measurement method to another. EPA carefully considered commenters 

concerns and conducted additional analyses to explore the potential impact of flow method on 

heat rate variability. 

Evaluation of flow measurement methods is complex because coal-fired EGUs may have 

one or more stacks, including common stacks that are shared with other EGUs at the power 

plant, and might use different methods for up to three different load levels in each stack. To 

assess the potential influence of flow measurement methods on heat rate variability, EPA 

reviewed the reported flow measurement methods for the 884 coal-fired EGUs between 2002 

and 2012. Of the 884 EGUs, 531 EGUs modified one or more flow measurement method for at 

least one load level during the 11-year study period (2002–2012). If, as commenters suggested, 

changes to flow measurement methods were responsible for much of the variability in EPA’s 

data, the analytical results should show that EGUs with a change of flow measurement method 

have higher indicated potential heat rate improvements. However, as shown in Table 2-15, the 

EGUs that changed flow method during the study period (2002-2012) have lower potential heat 

rate improvements in the Western and Texas interconnections than for the full group of coalfired EGUs in the interconnections. In the Eastern interconnection, the results between the two 

groups – EGUs that changed flow measurement method(s) and EGUs that have not changed flow 

measurement methods – are nearly identical. 

 80 For more information about Method 2, see 40 CFR Part 60 Appendix A. 

81 Coal-fired EGUs use continuous emission monitoring systems to measure pollutant concentrations and stack gas 

flow. The two measured values are used to calculate mass emissions. 
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Table 2-15 Potential heat rate improvement based on the 2-year efficiency and consistency 

under similar conditions analytical approach for all coal-fired EGUs and coal-fired EGUs 

that changed flow measurement method, by interconnection 

Interconnection 884 coal-fired 

EGUs 

Coal-fired EGUs 

with flow 

measurement 

method changes 

Western 2.1 2.0 

Texas 2.3 0.0 

Eastern 4.3 4.3 

CONUS 4.0 3.8 

Note: The Texas interconnection has a small number of EGUs, so small changes to the population can result in large changes in 

potential heat rate improvement 

Because the potential heat rate improvement for the 884 coal-fired EGUs and the 531 

coal-fired EGUs that changed one or more flow measurement methods are approximately the 

same, EPA disagrees with commenters’ statement that changes to flow measurement methods 

were responsible for much of the variation in gross heat rates. 

2.6.7 Inability of individual coal-fired EGUs to achieve the heat rate improvement 

targets 

Several commenters stated that specific coal-fired EGUs are not able to achieve the heat 

rate improvements identified in the proposal TSD. They provide a variety of reasons, including: 

(1) fuel type (e.g., lignite has low energy value and high moisture content, making it difficult to 

improve heat rate), (2) specific EGUs have already implemented efficiency measures and are not 

capable of improving heat rates beyond their current levels, (3) soon-to-retire EGUs would be 

forced to make additional efficiency upgrades to improve heat rate, resulting in stranded assets, 

and (4) small coal-fired EGUs do not have the same economies of scale as larger EGUs. The 

commenters argue that requiring every coal-fired EGU to meet a mandatory heat rate 

improvement target or standard would force EGU retirements and, as a result, strand assets and 

affect electricity consumers. First, EPA disagrees with commenters that this rule establishes a 

mandatory “one-size-fits-all” heat rate improvement standard. Rather, the heat rate improvement 

is one part of the best system of emission reduction and must be viewed in the context of the full 

best system of emission reductions. As noted earlier, states have the flexibility to establish 

policies in the state plan that are reasonable and appropriate for that state; these policies may or 

may not include heat rate improvement goals. Second, EPA disagrees with the commenters’ 

presumption that each coal-fired EGU must independently achieve the potential heat rate 

improvements identified in this analysis. The results of the analyses described above provide an 

estimate of potential heat rate improvements that, on average, are possible for each 

interconnection region based on each coal-fired EGU’s best historical heat rate between 2002 

and 2012 and the EGU’s own 2012 heat rate. Because the results represent the average potential 

heat rate improvement for an interconnection, some coal-fired EGUs can make greater heat rate 

improvements while other EGUs might make less. Third, the agency’s analysis is based on coalfired EGUs' historical heat rates relative to 2012 and is therefore demonstrated and achievable. 
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Commenters also noted that the interim and full compliance periods do not begin for several 

years and new technologies and practices for improving heat rate may be available in the future. 

With regard to soon-to-retire EGUs, it is not clear why EGUs retiring before the beginning of the 

interim compliance period in 2022 would make additional investments in heat rate 

improvements. However, if a soon-to-retire EGU did make such investments, those investments 

might serve to extend the useful life of the EGU. 

2.6.8 Impact of equipment degradation 

Several commenters stated that EPA’s assessment of potential heat rate improvement 

from equipment upgrades was unrealistic because it did not account for degradation of the 

equipment over time. First, it is important to note that: (1) EPA is no longer basing potential heat 

rate improvements on specific upgrades and (2) the rule does not establish a federal requirement 

for coal-fired EGUs to meet specific heat rate improvement targets (see section 2.6.7). Second, 

the agency disagrees with commenters; the agency believes EGU operators can control the rate 

of degradation through proper maintenance and, when necessary, replacement or refurbishment 

of equipment. This is supported by information provided by a commenter referring to National 

Petroleum Council (NPC) and International Energy Agency (IEA) reports that discuss 

deterioration and enhanced maintenance practices at coal-fired EGUs. The NPC report stated: 

Deterioration naturally occurs, and if left unchecked it can become substantial. 

Therefore, some amount of deterioration, normal deterioration, will always be present 

and non-controllable. Most of the normal deterioration can be recovered with regularly 

scheduled maintenance intervals... There is a gradual increase in the unrecoverable 

portion as the unit ages which would require a replacement rather than a refurbishment 

to eliminate. Poor maintenance practices regarding the timing of the intervals and the 

amount of refurbishment may result in excessive deterioration and is controllable [by the 

EGU operator].82 

The IEA report stated: 

[I]mprovements can not only restore ageing plants to their original performance, but 

also can often improve them further by avoiding the limitations of the prevailing 

technology at the time of original plant design...Not all of these areas have been 

considered worthy of attention previously, and a conclusion from that is that there may 

be other unrecognized areas of losses in efficiency which could be worth identifying.83

2.6.9 Limited adoption of low- and zero-cost heat rate improvements 

Commenters suggested that if there were low- or no-cost options to improve heat rate 

and, therefore, reduce fuel cost, coal-fired EGUs would have already implemented those 

measures because they have economic incentives to do so. However, research from NETL, RFF, 

and others show that there are a number of reasons that existing coal-fired EGUs might not 

implement low- and no-cost heat rate improvement practices, including: (1) concerns or 

 82 See National Petroleum Council (NPC), 2007. Electricity Generation Efficiency. NPC Working Document; Topic 

Paper #4. Available at http://www.npc.org/Study_Topic_Papers/4-DTG-ElectricEfficiency.pdf. 83 See C Henderson, 2013. Upgrading and efficiency improvement in coal-fired power plants. International Energy 

Agency (IEA) Clean Coal Centre Report. CCC/221. ISBN 978-92-9029-541-9. Available at http://bookshop.ieacoal.org/reports/ccc-221/83186. 
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uncertainties about New Source Review impacts; (2) lack of economic incentives to improve 

efficiency because of fuel adjustment clauses that enable electricity generating companies to 

“pass through” changes in fuel costs directly to customers; (3) lack of management commitment 

for efficiency programs; (4) focus on optimizing profitability and ensuring availability; (5) lack 

of on-site performance engineers dedicated to heat rate improvement; (6) potential fuel cost 

savings represent only a small portion of total costs and are “of secondary concern when 

compared to needs for maintaining system reliability”; and (7) lack of regulatory certainty about 

future environmental regulations that lead to operators deferring significant upgrades on older 

coal-fired EGUs.84 

2.7 Costs 

2.7.1 Breakeven costs 

In the proposal TSD the EPA used an estimated average cost of $100/kW for a potential 

national average 6 percent heat rate improvement by coal-fired EGUs. Four percentage points of 

that potential improvement was projected to come from relatively inexpensive low- or no-cost 

best practices. Thus, most of the estimated $100/kW average cost actually represented the cost of 

relatively more expensive equipment and system upgrades that EPA expected would provide the 

remaining 2 percent improvement. 

For this final rule, as explained above, EPA has refined the estimate of potential national 

average net heat rate improvement by coal-fired EGUs to between 2.1 to 4.3 percent for each 

interconnection, or about 4 percent nationally, with potentially all of that improvement coming 

from best practices. The agency no longer relies on an additional and distinct 2 percent 

improvement contribution from equipment upgrades. The agency expects, however, that some 

EGUs will in fact choose to make equipment upgrades for heat rate improvement, and that at 

least some small fraction of the overall heat rate improvement will come from equipment 

upgrades, and for at least a few EGUs most of the improvement may come from equipment 

upgrades. Overall, the agency expects the cost of heat rate improvement to be significantly less 

than $100/kW at the new level of heat rate improvement. However, because of the uncertainty 

associated with what fractions of a potential national average 4 percent heat rate improvement 

may come from no- or low-cost versus higher cost measures at individual EGUs, and considering 

commenter concerns that EPA’s previous estimated cost was too optimistic, the agency assessed 

the economic effects of a heat rate improvement cost that might range from $50 to $100/kW. 

The agency acknowledges here, as in the proposal TSD, that the technical applicability 

and efficacy of heat rate improvement measures, the cost of implementing them, and delivered 

coal cost, all depend upon site specific factors and can vary widely from site to site. Nonetheless, 

the agency finds it reasonable to expect that a fleet wide average cost for a national fleetwide 

average improvement of 4 percent, based primarily on low- and no-cost best practices, would be 

significantly less than $100/kW. However, as a conservative measure, and because the cost of 

heat rate improvement is one of the least costly and least impactful measures considered in the 

best system of emission reductions for this rule, the agency has decided to continue to use the 

 84 See supra notes 11 and 18. Also see Comments of Natural Resources Defense Council (NDRC). Available at 

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0602-26818. 
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previously estimated $100/kW cost value for IPM modeling and the RIA estimates of the total 

cost of this final rule. 

The brief assessment presented here is intended only to illustrate the approximate effects 

of coal cost and heat rate improvement capital cost on the economic breakeven point between 

coal cost savings and the capital cost of implementing heat rate improvement. The resulting 

order-of-magnitude cost range for CO2 removal ($ per ton) is also discussed. EPA does not 

suggest in the proposal or in this final rule that heat rate improvement measures should meet a 

particular economic criterion (e.g., pay for themselves through reduced fuel costs) in order to be 

applied in state plans for compliance with this rule. 

Figure 2-12 presents a simplified economic breakeven analysis for a 4 percent nationwide 

average heat rate improvement, assuming there is no CO2 emission allowance cost involved. 

Additional assumptions used in the breakeven calculation include: capital charge rate of 14.3 

percent, as used in the IPM base case modeling for this final rule; 2030 annual capacity factor of 

78 percent, derived from the IPM modeling; coal fleet generation weighted average 2030 net 

heat rate of 10,250 Btu/kWh before heat rate improvement, also derived from the IPM modeling. 

Figure 2-12 Breakeven economics of a 4 percent heat rate improvement 

Figure 2-12 shows that at a capital cost of $50/kW, the average fleetwide 2030 savings in 

coal cost would become greater than the annualized capital cost of an average 4 percent 

reduction in net heat rate when the average fleetwide coal cost exceeds about $2.50/mmBtu. For 

comparison, the average U.S. power sector delivered cost of coal was $2.38/mmBtu in 201285, 

and is projected to be about $2.70/mmBtu in 2030.86 For different assumptions, the heat rate 

improvement economic breakeven point would change directionally as follows: 

 85 EIA, Electricity DataTable 7.4, Average Weighted Cost of Fossil Fuels for the Electric Power Industry 2002–

2012. Available at http://www.eia.gov/electricity/annual/html/epa_07_04.html. 86 2030 projected fuel costs are derived from IPM Base Case. 
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If the heat rate improvement capital cost were on average less than $50/kW, 4 percent 

heat rate improvement would then “become economic” (i.e., pay for itself) at lower coal costs. 

For example, if the average capital cost were actually $25/kW, a fleetwide 4 percent heat rate 

improvement would become economic at an average coal cost of about $1.25/mmBtu, which is 

comparable to the U.S. power sector average costs of $2.38/mmBtu for all coal ranks and 

$2.89/mmBtu for bituminous coals in 2012.87 This sensitivity indicates that fuel cost savings 

alone would make it economic for some of those EGUs currently using the higher cost 

bituminous coals to make heat rate improvement investments. 

At an EGU net heat rate that is higher than the IPM projected 2030 average value of 

10,250 Btu/kWh, 4 percent heat rate improvement could be economic at coal costs lower than 

the values mentioned above. 

If there were additional heat rate improvement savings due to avoided future CO2

emission costs, heat rate improvement could become economic at lower coal costs, or at higher 

capital costs, or at lower heat rate reduction percentages. 

2.7.2 Estimated fleetwide CO2 reduction from and cost for heat rate improvements 

EPA derived the following illustrative order-of-magnitude estimate of the fleetwide costeffectiveness of a 4 percent heat rate improvement from the IPM base case modeling: 

2.7.2.1 Fleetwide 2030 assumptions derived from IPM Base Case for this final rule 

 Coal fleet capacity applying combined heat rate improvement methods: 213,000 

MW 

 Average net heat rate: 10,250 Btu/kWh net, before 4 percent heat rate 

improvement 

 Average capacity factor: 78 percent 

 Heat rate improvement Btu and CO2 reduction: 4 percent 

 Heat rate improvement capital cost: $50/kW (assumed) 

 Annual capital charge rate: 14.3 percent 

 Average coal cost: $2.70/mmBtu 

2.7.2.2 Estimated fleetwide results 

 Fleetwide CO2 reduction via heat rate improvement: 62 million ton/yr 

 Total heat rate improvement capital cost: $10.7 billion 

 Annualized heat rate improvement capital cost: $1.5 billion 

 Annual coal cost savings: $1.6 billion 

 Annual net savings: $0.09 billion 

 Annual net savings for CO2 reduction: $1.4/ton 

2.7.3 Conclusion - heat rate improvement economics 

This necessarily simplified analysis supports the following summary conclusions: 

 87See supra note 85. 
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1. Some degree of heat rate improvement is very likely already economic (paying for itself) for 

high heat rate – high coal cost EGUs, and will remain so in 2030 

2. If a fleetwide average 4 percent heat rate improvement were implemented, it would also pay 

for itself on the basis of fuel savings alone, before consideration of the value of the 

associated CO2 emission reductions, on a fleetwide basis at projected 2030 coal prices if the 

associated average capital cost is about $50/kW or less. 

3. If a fleetwide average 4 percent heat rate improvement were implemented, and the associated 

average capital cost is as much as $100/kW, 4 percent heat rate improvement would not 

likely pay for itself based on fuel cost savings alone. 

4. Even at a capital cost of $100/kW and an IPM projected 2030 coal price of $2.70/MMBtu, 

the average fleetwide cost of CO2 reduction via 4 percent heat rate improvement would be a 

still relatively low $23/ton. 

Thus, although there is currently some uncertainty associated with the costs of achieving 

a particular fleetwide amount of heat rate improvement, it is clear that heat rate improvement is 

an available low-cost approach to CO2 reduction for existing coal-fired EGUs.