### 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

<< SummaryOfInteragencyComment sUnder_EO12866_EO13563_GHG Mitigation TSD_BB1.docx >>

### Summary	of	Interagency	Working	Comments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

2-1 

### Chapter 2: CO 2 

### 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 CO 2 intensity (CO 2 lb/kWh). Because heat rate improvements reduce fuel consumption, improving coal-fired EGUs’ heat rates can be a cost-effective method of reducing the CO 2 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 2012gross 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

### Summary	of	Interagency	Working	Comments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

2-2 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 fossi l 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 ra te 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 CO 2 and other emissions (e.g., mercury, NO X , PM, SO 2 ) 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 charac teristics (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 CO 2 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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2-3 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 CO 2 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 forconverting 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., CO 2 , mercury, NO X , PM, SO 2 ), 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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2-4 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 pollutioncontrol 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, a nd 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

### Summary	of	Interagency	Working	Comments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

2-5 that is available for producing steam, thus loweri ng 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 singlerank – 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 CO 2 Emission Performance Rate and Goal Computation Technical Support

Document , EPA assessed the potential CO 2 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 EGUs 5 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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2-6 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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2-7 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 rate 7 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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2-8 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 lo w-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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2-9 EGU’s CO 2 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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2-10  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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2-11  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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2-12 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 bo iler, 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 whil e maintaining emission reduction levels.

2.3.3.2.1 Economizer

The economizer extracts energy from the combus tion 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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2-13 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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2-14 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 CO 2 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

CO 2 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 CO 2 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 sp eed 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 en gineers 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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2-15 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 90 th percentile EGU, 14 ranked by efficiency, within each of the 13 segments and calculated the potential efficiency improvements

if all EGUs below the 90 th percentile improved their average efficiency to the level of the 90 th
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 plan t 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 informatio n 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 90 th percentile in the NETL study is methodologically equivalent to the 10 th 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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2-16 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 10 th
percentile for their category, but lower than the median (i.e., 50 th 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 22O&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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2-17 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 95 th 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 95 th percentile gross heat rate, respectively.

The General Electric Company (GE) submitte d 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 CO 2 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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2-18 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 CO 2 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 ElectricPower 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 CO 2 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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2-19 Table 2-1 Net heat rate improvement ca se 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 existin g 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 CO 2 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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2-20 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” equipm ent 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 di scussed 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 SO 2 creates CO 2 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 CO 2 . Circulating fluidized bed (CFB) boilers also have higher CO 2 emissions from the chemical process of limestone injection to capture SO 2 , 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 CO 2 emissions from SO 2 pollution control devices.

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2-21 The agency does not agree that the EPA impr operly characterized or misused information from the S&L report. The S&L study 24 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 fo cus on methods that have been successfully implemented by the utility industry.”

 “This study identifies specific plant systems a nd 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 impr ovement concepts and the resulting heat rate reductions that can be implemented in various sy stems of a typical coal-fired power plant. All estimated capital and installation costs are referen ced from work in progress and vendor quotes as of the year 2008.”

 “S&L cautions that the costs presen ted herein are not indicative of those that may be expected for a specific facility due to variab les such as equipment, material, and labor market conditions and site specifications. However, these cost estimate s provide valuable information for comparative purposes when evaluating the ad vantages and disadvantages of the various concepts. The costs should not be used as a basis for proj ect 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 measures 25 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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2-22 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 pe rformance. 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 analys is compared each EGU’s best historicalgross 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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2-23 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 pr actices 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 po tential 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 CO 2 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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2-24 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 acc ounting 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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2-25 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 CO 2 emissions in 2012, 96 percent of the 1.67 billion tons of

CO 2 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 CO 2 contributing to attainment of the state goal, and (2) for states with CO 2 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

CO 2 , NO X , and SO 2 , and report those hourly emissions along with hourly heat input 29 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, accu rate, 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 CO 2 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 CO 2 or O 2 concentration and calculations detailed in 40 CFR Part 75 Appendix F. As a result, heat rate (Btu/gross kWh) is proportional to CO 2 rate (CO 2 /gross kWh).

30 The quality assurance requirements for monitoring systems are described in 40 CFR Part 75 Appendix B.

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2-26 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 si gnificantly 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 CO 2 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

accuracy 34 for both CO 2 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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2-27 Table 2-2 Generation-weighted relative accuracy of CO 2 and flow monitoring systems, by

interconnection

Western Texas Eastern

CO 2 Flow CO 2 Flow CO 2 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 CO 2 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 CO 2 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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2-28 nearest weather station 37 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 comprehensiv e 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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2-29 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 CO 2 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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2-30 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 b ecause it includes measurements from four “sister units”; the trend line is a power function in the form of y=c×x b ; 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 R 2 ) valueswere weighted using the EGU’s total annual gross electricity generation resulting in an EGU-specific generationweighted R 2 . This approach controlled for any differences in average gross heat rates between years. The weighted

R 2 values were averaged across all 884 coal-fired EGUs, resulting in an R 2 value of 0.179.

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2-31 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 af ter 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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2-32 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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2-33 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 airtemperature 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 R 2 ) valueswere weighted using the EGU’s total annual gross electricity generation resulting in an EGU-specific generationweighted R 2 . This approach controlled for any differences in average gross heat rates between years. The weighted

R 2 values were averaged across all 884 coal-fired EGUs, resulting in an R 2 value of 0.083.

51 For each EGU, the annual coefficient of determination (i.e., the square of the correlation coefficient, or R 2 ) valueswere weighted using each EGU’s total annual gross electricity generation resulting in an EGU-specific generationweighted R 2 . This approach controlled for any differences in average gross heat rates between years. The weighted

R 2 values were averaged across all 45 EGUs, resulting in an R 2 value of 0.072.

52 For each EGU, the annual coefficient of determination (i.e., the square of the correlation coefficient, or R 2 ) valueswere weighted using each EGU’s total annual gross electricity generation resulting in an EGU-specific generationweighted R 2 . This approach controlled for any differences in average gross heat rates between years. The weighted

R 2 values were averaged across all 45 EGUs, resulting in an R 2 value of 0.057.

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2-34 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 R 2 value for rolling 24-hour water temperature and hourly gross heat rate was 0.071 and the R 2 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 R 2 ) valueswere weighted using the EGU’s total annual gross electricity generation resulting in an EGU-specific generationweighted R 2 . This approach controlled for any differences in average gross heat rates between years. The weighted

R 2 values were averaged across all 884 coal-fired EGUs, resulting in an R 2 value of 0.255.

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2-35 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 influenceof 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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2-36 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 reasonabl y 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 recognizesthat: (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. Ho wever, 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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2-37 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 sing le 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 wi thin each interconnection region.

60 See section 2.6.8 for more information about equipment degradation and maintaining heat rate performance.Summary	of	Interagency	Working	Comments	on	Draft	Language	underEO12866/13563	InteragencyReview.		Subject	to	Further	Policy	Review.2-382.5.3.2ExampleStep 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 EGU2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 20121-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 9,8642-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 10,244Step 2: The lowest 1-year gross heat rate occurred in 2008; the lowest moving 2-year gross heat rate occurred in 2009 (2008-2009data).Step 3: The potential heat rate improvements for the example EGU are:Based on best 1-year gross heat rate:1െቆଽଵହ଻ಳ೟ೠೖೈ೓ଽ଼଺ସಳ೟ೠೖೈ೓ቇ ൌ 7.2	݌݁ݎܿ݁݊ݐBased on best 2-year gross heat rate:1െቆଽଷଵଵಳ೟ೠೖೈ೓ଽ଼଺ସಳ೟ೠೖೈ೓ቇ ൌ 5.6	݌݁ݎܿ݁݊ݐ

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2-39 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 ba sed on best historical performance, by

interconnection

Performance period Western Texas Eastern Nationally 61

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 agencycalculated 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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2-40 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 Nationally 62

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 temperatureconditions, 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 hourlyheat 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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2-41 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 re sult 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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2-42 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 CO 2 emissions. For example, if an EGU were to operate more consistently at a higher heat rate (i.e., le ss 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 hourlygross 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 percentilehourly 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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2-43 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 th e 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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2-44 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 ଽଷହଷ ಳ೟ೠ

ೖೈ೓

ଽଽ଺଼ ಳ೟ೠ

೓ೖೈ ቇ ݐܿ݁݊ݎ݁݌	6.2 ൌ 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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2-45 Based on 2-year benchmark and consistency factor: 1 െ ቆ ଽସଽଶ ಳ೟ೠ

ೖೈ೓

ଽଽ଺଼ ಳ೟ೠ

೓ೖೈ ቇ ݐܿ݁݊ݎ݁݌	4.8 ൌ

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 ra te improvement based on efficiency and consistency under similar conditions, by interconnection

Performance period Western Texas Eastern Nationally 67

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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2-46 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 Nationally 70

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 CO 2 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

CO 2 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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2-47 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 CO 2 emissions from SO 2 pollution control devices

Commenters noted that the addition of wet flue gas desulfurization (WFGD or wet scrubber) technologies result in increased process CO 2 emissions because of the dissolution of limestone to capture SO 2

. 73 Because heat input, the numerator for calculating heat rate, is based

on an EGU’s measured CO 2 emissions, the additional process CO 2 emissions result in artificial increases in calculated gross heat rate. Commenters suggest that process CO 2 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 SO 2 +CaCO 3 +1⁄2H 2 O → CaSO 3 +1⁄2H 2 O+CO 2 (see RK Srivastava, 2000. Controlling SO 2 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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2-48 process CO 2 emissions, the agency estimated the incremental CO 2 from the WFGD chemical reaction. The results indicate that retrofit WFGD installed on existing coal-fired EGUs between

2002 and 2012 increased 2012 CO 2 emissions (and calculated heat input) by an average of no more than 0.7 percent for those EGUs in 2012.

To calculate the CO 2 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 CO 2 emissions that c ould 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 CO 2 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 CO 2 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 CO 2 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 CO 2 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 CO 2 emissions are based on 85 and 95 percent removal rate s, 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 CO 2 emissions

2.6.4 Impact of future retrofit air pollution controls to comply with EPA and state environmental requirements

This rule establishes CO 2 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 CO 2 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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2-49 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, CO 2 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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2-50 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 athttp://www.power-eng.com/articles/print/volume-118/issue-11/departments/clearing-the-air/bagging-two-birdswith-one-economizer.html

.

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2-51 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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2-52 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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2-53 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 meth ods 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 heatrate 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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2-54 Table 2-15 Potential heat rate improvement based on the 2-year efficiency and consistency under similar conditions analytical approach fo r 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 improvem ent 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 rateimprovements 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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2-55 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 E GUs, 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, no rmal 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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2-56 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 prop osal 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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2-57 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 CO 2 removal ($ per ton) is also discussed. EPA does not suggest in the proposal or in this final rule th at heat rate improvement measures should meet a particular economic criterion (e.g., pay for themselv es 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 CO 2 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 im provement, 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 2012 85

, 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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2-58 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 aver age 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 CO 2 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 CO 2 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 CO 2 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 CO 2 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 CO 2 reduction: $1.4/ton

2.7.3 Conclusion - heat rate improvement economics

This necessarily simplified analysis supports the following summary conclusions:

87 See supra note 85.

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2-59 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 CO 2 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 CO 2 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 CO 2 reduction for existing coal-fired EGUs.