From: Higgins, Cortney [mailto:Cortney_Higgins@omb.eop.gov] 

Sent: Friday, April 04, 2014 7:59 PM 

To: Wayland, Robertj 

Subject: Re: Chapters 1, 2 and 6 from GHG Abatement Measures TSD 

Thanks! 

Have a good weekend. 

Cortney 

From: Wayland, Robertj [mailto:Wayland.Robertj@epa.gov] 

Sent: Friday, April 04, 2014 07:30 PM Eastern Standard Time 

To: Higgins, Cortney 

Cc: Culligan, Kevin <Culligan.Kevin@epa.gov>; Tsirigotis, Peter 

<Tsirigotis.Peter@epa.gov>; Srivastava, Ravi <Srivastava.Ravi@epa.gov> 

Subject: Chapters 1, 2 and 6 from GHG Abatement Measures TSD 

Cortney - 

Attached please fine Chapters 1, 2 and 6 from the GHG Abatement Measures TSD. Chapter 7 

needs a bit more editing which we'll take care of over the weekend. Please confirm receipt of 

these 3 chapters given the email issues we discussed earlier! :-) 

thanx! 

 

bob 

 

Robert J. Wayland, Ph.D. 

Leader, Energy Strategies Group 

U.S. Environmental Protection Agency 

Office of Air Quality Planning and Standards 

Sector Policies and Programs Division 

Mail Code D243-01 

Research Triangle Park, North Carolina 27709 

 

Office: (919) 541-1045 

Cell: (919) 306-2290 

Fax: (919) 541-5450 

 

Email: wayland.robertj@epa.gov 

 
***************************************** 

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<< GHG Abatement Measures - Chapter 1 04-04-2014.docx >> 

<< GHG Abatement Measures - Chapter 2 04-04-2014.docx >> 

<< GHG Abatement Measures - Ch6 4-4-14.docx >> 
DRAFT April 04, 2014 

Chapter 1: Introduction 

CAA section 111(d) requires that state plans must establish standards of performance that 

reflect the degree of emission limitation achievable through the application of the best system of 

emission reduction (BSER) that, taking into account the cost of achieving such reductions and 

any non-air quality health and environmental impact and energy requirements, the Administrator 

determines has been adequately demonstrated. Under CAA section 111(a)(1) and (d), the EPA is 

authorized to determine the BSER and to calculate the amount of emission reduction achievable 

through applying the BSER. 

As a first step towards determination of BSER, the EPA recognized that, in general, 

reductions in carbon dioxide (CO2) emissions from individual existing electric generating units 

(EGUs) can be achieved by implementing either of two basic approaches: (1) making emission 

rate improvements at affected EGUs (e.g., by improving heat rates or switching to lower carbon 

fuels), and/or (2) reducing utilization of greenhouse gas (GHG)-emitting EGUs (e.g., by reducing 

the overall demand for electricity or by shifting dispatch from higher-GHG-emitting EGUs to 

lower-GHG-emitting and non-emitting units). Accordingly, to determine BSER for reducing 

GHG emissions at affected units, the EPA evaluated numerous GHG abatement measures that 

utilize the above approaches. In its evaluation, the EPA considered only those measures that have 

been adequately demonstrated to reduce CO2 emissions from fossil fuel-fired EGUs. These 

measures included: heat rate improvements at individual EGUs, switching to lower carbon fuels 

at individual EGUs, carbon capture and sequestration at individual EGUs, shifting dispatch from 

higher-GHG-emitting EGUs to lower-GHG-emitting and non-emitting units, and reducing the 

overall demand for electricity via improvements in demand-side energy efficiency. 

Based on its evaluation of the above GHG abatement measures, the EPA identified four 

categories of demonstrated measures, or “building blocks,” that are technically viable and 

broadly applicable, and can provide cost-effective reductions in CO2 emissions from individual 

existing EGUs. These building blocks include: 

1. Lowering the carbon intensity of generation at individual affected EGUs (e.g., through 

heat rate improvements); 
DRAFT April 04, 2014 

2 

2. Reducing emissions of the most carbon-intensive affected EGUs to the extent that this 

can be accomplished cost-effectively by shifting generation to less carbon-intensive 

existing fossil fuel-fired EGUs, including NGCC units that are under construction; 

3. Reducing emissions of carbon-emitting EGUs to the extent that this can be 

accomplished cost-effectively by expanding the amount of new, lower (or no) carbonintensity generation; and, 

4. Reducing emissions of carbon-emitting EGUs to the extent that this can be 

accomplished cost-effectively by increasing demand-side energy efficiency. 

The EPA believes that for purposes of CAA section 111(d), as applied to the power 

sector, the BSER encompasses all four building blocks. The application of all four building 

blocks as BSER is consistent with current trends in the electric power sector and with strategies 

that companies and states are already taking to reduce GHG emissions. Also, the application of 

all four building blocks as BSER supports achieving cost-effective, and technically feasible 

reductions of CO2. 

The subsequent chapters in this technical support document describe EPA’s evaluation of 

all adequately demonstrated GHG abatement measures. While evaluating each measure, the EPA 

considered its technical feasibility, applicability and use, application level appropriate for BSER, 

and cost effectiveness associated with reducing GHG emissions at EGUs. 
DRAFT April 4, 2014 

Chapter 2: Heat Rate Improvement at Existing Coal-fired EGUs 

Introduction 

Based on the range of operating efficiencies for existing coal-fired electric generating 

units (EGUs), it can be presumed that EGUs are generally less efficient at converting fuel into 

electricity than is technically and economically possible. For example, the difference in operating 

efficiency of EGUs with similar design characteristics and the year to year variability in 

individual EGU efficiency indicates that there is potential for broadly applicable efficiency 

improvements through cost-effective operational and maintenance practices. These improved 

efficiencies would result in corresponding reductions in greenhouse gas emissions. 

This chapter presents an overview of existing coal-fired EGUs, design factors that 

influence efficiency, technologies to improve efficiency, previous studies estimating potential 

efficiency improvements, the proposed EPA approach to calculate efficiency improvements, and 

the estimated capital costs of those improvements. 

Overview of U.S. Existing Coal-Fired Electric Generating Units 

Coal in the United States and is predominately used for electric power generation. Most 

coal-fired EGUs in the United States burn either bituminous or subbituminous coals. The largest 

sources of bituminous coals burned in coal-fired EGUs are mines in regions along the 

Appalachian Mountains and in southern Illinois, western Kentucky and Indiana. Additional 

bituminous coals are supplied from mines in Utah and Colorado. The vast majority of 

subbituminous coals are supplied from mines in Wyoming and Montana, with many coal-fired 

EGUs burning subbituminous coals from the Powder River Basin (PRB) region in Wyoming. In 

general, the burning of lignite by U.S. electric utilities is limited to coal-fired EGUs that are 

located near the mines that supply the lignite in Texas, Louisiana, Mississippi, Montana, and 

North Dakota. At a few power plant locations in the Eastern U.S., recovered anthracite coal or 

coal refuse is burned in limited quantities. 

Existing coal-fired EGUs in the U.S. electric utility fleet use one of five basic coal 

combustion configurations: (1) pulverized coal (PC) combustion, (2) fluidized-bed combustion 

(FBC), (3) gasified coal combustion, (4) cyclone furnace combustion, or (5) stoker-fired coal 

combustion. Table 2-1 presents a summary of the operating characteristics of each of these coal 

combustion configurations. 
DRAFT April 4, 2014 

2 

Table 2-1. Characteristics of coal-firing configurations used for U.S. EGUs 

Coal-firing 

Configuration 

Coal Combustion Process 

Description Distinctive Design/Operating Characteristics 

Pulverized 

Coal 

Combustion 

Coal is ground to a fine powder that 

is pneumatically fed to a burner 

where it is mixed with combustion 

air and then blown into the furnace. 

The pulverized-coal particles burn in 

suspension in the furnace. Unburned 

and partially burned coal particles 

are carried off with the flue gas. 

Wall-fired 

An array of burners fire into the 

furnace horizontally, and can be 

positioned on one wall or opposing 

walls depending on furnace design. 

Tangential-fired 

(Corner-fired) 

Multiple burners are positioned in 

opposite corners of the furnace 

producing a fireball that moves in a 

cyclonic motion and expands to fill 

the furnace. 

Fluidized-bed 

Combustion 

(FBC) 

Coal is crushed into fine particles. 

The coal particles are suspended in a 

fluidized bed by upward-blowing jets 

of air creating a turbulent mixing of 

combustion air with the coal 

particles. Typically, the coal is mixed 

with a sorbent such as limestone (for 

SO2 emission control). FBC can be 

designed for combustion within the 

bed to occur at atmospheric or 

elevated pressures. FBC operating 

temperatures are in the range of 

1,500 to 1,650F (800 to 900o

C). 

Bubbling 

fluidized bed 

(BFB) 

Operates at relatively low gas stream 

velocities and with coarse-bed size 

particles. Air in excess of that 

required to fluidize the bed passes 

through the bed in form of bubbles. 

Circulating 

fluidized bed 

(CFB) 

Operates at higher gas stream 

velocities and with finer-bed size 

particles. No defined bed surface. 

Must use high-volume, hot cyclone 

separators to recirculate entrained 

solid particles in flue gas to maintain 

the bed and achieve high combustion 

efficiency. 

Integrated Coal 

Gasification 

Combined 

Cycle (IGCC) 

Synthetic combustible gas (“syngas”) 

derived from an on-site coal 

gasification process is burned in a 

combustion turbine. The hot exhaust 

gases from the combustion turbine 

pass through a heat recovery steam 

generator to produce steam for 

driving a steam turbine/generator 

unit. 

Coal gasification units are unique among coal-firing 

configurations because a gaseous fuel (synfuel or syngas) 

is burned instead of solid coal because the combustion 

and power generation process and combines the Rankine 

and Brayton thermodynamic cycles as is the case for a 

combined cycle power plant. 

Cyclone 

Furnace 

Combustion 

Coal is crushed into small pieces and 

fed through a burner into the cyclone 

furnace. A portion of the combustion 

air enters the burner tangentially 

creating a whirling motion to the 

incoming coal. 

Designed to burn coals with low-ash fusion temperatures 

that are difficult to burn in PC boilers. The majority of 

the ash is retained in the form of a molten slag. 

Stoker-fired 

Coal 

Combustion 

Coal is crushed into large lumps and 

burned in a fuel bed on a moving, 

vibrating, or stationary grate. Coal is 

fed to the grate by a mechanical 

device called a “stoker.” 

One of three types of stoker mechanisms can be used that 

ether feed the coal by pushing, dropping, or flipping coal 

unto the grate. 

The three technologies currently used for new coal-fired power plants are pulverized 

coal, fluidized bed (FBC), and integrated coal gasification combined cycle (IGCC). Pulverized 

coal combustion involves pulverizing the coal into a fine powder, which allows the coal to be 

burned more easily and efficiently. This is the coal-firing configuration predominately used at 
DRAFT April 4, 2014 

3 

existing EGUs, and is the most frequently selected technology for new coal-fired EGU projects. 

However, FBC EGUs are becoming more prevalent since they have a greater fuel flexibility. The 

most recent coal technology combustion development involves the integration of coal 

gasification technologies with the combined cycle electric generation process. The efficiency of 

an IGCC power plant is comparable to the latest advanced PC-fired and FBC EGU designs using 

supercritical steam cycles. The advantages of using IGCC technology can include greater fuel 

flexibility (e.g., capability to use a wider variety of coal ranks), potential improved control of 

PM, SO2 emissions, and other air pollutants, the need for fewer post-combustion control devices 

(e.g., almost all of the sulfur and ash in the coal can be removed once the fuel is gasified and 

prior to combustion), generation of less solid waste, and reduced water consumption. 

Older combustion technologies, namely cyclone furnaces and stoker-fired coal 

combustion, have been replaced at new coal-fired EGUs by more efficient methods that provide 

superior coal combustion efficiency and other advantages. However, a few remaining old stokerfired EGUs and cyclone furnaces still remain in service for a small number of existing EGUs in 

the U.S. electric utility market. 

Influence of Heat Rate on Coal-Fired EGU CO2 Emission Rate 

Heat rate is a common way to measure EGU efficiency. As the efficiency of a coal-fired 

EGU is increased, less coal is burned per kilowatt-hour (kWh) generated by the EGU resulting in 

a corresponding decrease in CO2 and other air emissions. Heat rate is expressed as the number of 

British thermal units (Btu) or kilojoules (kJ) required to generate a kilowatt-hour (kWh) of 

electricity. Lower heat rates are associated with more efficient coal-fired EGUs. 

The electric energy output for an EGU can be expressed as either as “gross output” or 

“net output.” The gross output of an EGU is the total amount of electricity generated at the 

generator terminal. The net output of an EGU is the gross output minus the total amount of 

auxiliary (or parasitic) electricity used to operate the EGU (e.g., electricity to power fuel 

handling equipment, pumps, fans, pollution control equipment, and other on-site electricity 

needs), and thus is a measure of the electricity delivered to the transmission grid for distribution 

and sale to customers. Some EGUs also produce part of their useful output in the form of useful 

thermal output (e.g., steam for heating purposes). These types of facilities are called combined 

heat and power, or CHP, facilities. 

A variety of factors must be considered when comparing the effectiveness of heat rate 

improvement technologies to increase the efficiency of a given coal-fired EGU. The actual 
DRAFT April 4, 2014 

4 

overall efficiency that a given coal-fired EGU achieves is determined by the interaction of a 

combination of site-specific factors that impact efficiency to varying degrees. Examples of the 

factors affecting EGU efficiency at a given facility include: 

 EGU thermodynamic cycle – EGU efficiency can be significant improved by using a 

supercritical or ultra-supercritical steam cycle. Supercritical and ultra-supercritical boilers 

operate above the critical point of water (approximately 374°C (705°F) and 22.1 MPa 

(3,210 psia)). As a general guideline, the thermal design efficiencies for subcritical EGUs 

are in the range of 35% to 37%, supercritical EGUs are in the range of 39% to 40%, and 

ultra-supercritical EGUs in the range of 42% to 45%. However, actual operating 

efficiencies are lower than design efficiencies. The majority of existing PC-fired EGUs in 

the U.S. electric fleet use subcritical boilers 

 EGU coal rank and quality – EGUs burning higher quality coals (e.g., bituminous) tend 

to be more efficient than EGUs burning lower quality coals (e.g., lignite). 

 EGU plant size –EGU efficiency generally increases with size because the boiler and 

steam turbine losses are lower for larger equipment compared to smaller equipment. 

However, as equipment size increases the differences in these losses start to taper off. 

 EGU pollution control systems – The electric power consumed by air pollution control 

equipment reduces the overall efficiency of the EGU.

 EGU operating and maintenance practices – The specific practices used by an individual 

electric utility company for combustion optimization, equipment maintenance, etc. can 

affect EGU efficiency. 

 EGU cooling system – The temperature of the cooling water entering the condenser can 

have impacts on steam turbine performance. Once-through cooling systems can have an 

efficiency advantage over recirculating cooling systems (e.g., cooling towers). However, 

once-though cooling systems typically have larger water related ecological concerns than 

recirculating cooling systems. 

 EGU geographic location and ambient conditions – The elevation and seasonal ambient 

temperatures at the facility site potentially may have a measureable impact on EGU 

efficiency. At higher elevations, air pressure is lower and less oxygen is available for 

combustion per unit volume of ambient air than at lower elevations. Cooler ambient 

temperatures theoretically could increase the overall EGU efficiency by increasing the 
DRAFT April 4, 2014 

5 

draft pressure of the boiler flue gases and the condenser vacuum, and by increasing the 

efficiency of a condenser recirculating cooling system. 

 EGU load generation flexibility requirements – Operating an EGU as a baseload unit is 

more efficient than operating an EGU as a load cycling unit to respond to fluctuations in 

customer electricity demand. 

 EGU equipment manufacturers – The efficiency specifications of major EGU 

components such as boilers, turbines, and electrical generators provided by equipment 

manufacturers can affect EGU efficiency. 

 EGU plant components – EGUs using the optimum number of feedwater heaters, highefficiency electric motors, variable speed drives, better materials for heat exchangers, etc. 

tend to be more efficient. 

Technologies to Improve Existing Coal-Fired EGU Heat Rate 

A number of studies have been conducted involving literature reviews of published 

articles and technical papers identifying potential efficiency improvement techniques applicable 

to existing coal-fired EGUs.1

 For example, a summary of the findings from one study conducted 

by the Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) is 

presented in Table 2-2. The efficiency percentages were converted to a common basis so that all 

of the data can be compared. All of the improvement technologies presented in Table 2-2 cannot 

necessarily be implemented at every existing coal-fired EGU facility in the U.S. electric utility 

fleet. The existing EGU design configuration and other site-specific factors may prevent the 

technical feasibility of using a given technology. 

Typically, these studies share as a common basis the estimated potential efficiency 

improvement percentages and costs from the engineering study originally completed by Sargent 

and Lundy in 2009 titled “Coal-Fired Power Plant Heat Rate Reductions.” It describes numerous 

well known and technically proven methods to improve efficiency of coal-fired EGUs. The study 

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

equipment and the water treatment system. Each of these main areas are expanded upon below. 

Boiler 

The systems to focus on for improving heat input within the boiler area include the 

materials handling, combustion system, boiler control system, sootblowers and the air heaters. 

                                                            

1

 See HRI Partial Bibliography at the end of this chapter. 
DRAFT April 4, 2014 

6 

Materials Handling 

The coal handling portion of materials handling typically requires about 0.07% of the 

gross electrical output of a power plant. Depending on the state of the motors and drives, 

replacing them with energy-efficient motors and variable frequency drives (VFDs) can reduce 

the auxiliary power requirements. The VFDs also limit the stress and strain on the other 

equipment. 

Coal pulverizers can be upgraded to provide more consistent size and finer coal particles. 

The fine particles improve combustion efficiency, consequently reducing fuel cost and heat rate. 

The costs for changes to the pulverizer system are significant, and historically, the projects have 

improved the heat rate justifiably only when the existing equipment has degraded. 

The bottom ash handling system may be a source for heat rate improvement. Switching 

from a water-sluicing bottom ash system to a dry drag chain system can reduce the auxiliary 

requirements and reduce the amount of water to the water treatment plant. The typical power 

requirements are about 0.1% of the plant’s gross output. 

Economizer 

The replacement of the economizer can lead substantial heat rate improvements around 

50-100 Btu/kWh, but is large capital investment (~$2-8M). Due to this high cost, economizers 

upgrades are not generally performed unless the existing equipment has degraded or a 

replacement is necessary due to the installation of new control equipment. 

Boiler Control System 

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

control capabilities can control and evaluate many aspects of the plant’s operations. Commonly 

referred to as the Neural Network (NN), computer models are able to control the plant’s 

processes by predicting performance during static and dynamic changes. Many vendors offer NN 

systems to improve the overall efficiency. NN systems are typically around $550,000-$750,000 

and offer heat rate reductions up to 150 Btu/kWh. 

Sootblowers 

Intelligent sootblowers (ISB) may be installed to improve system efficiency. The ISB 

system monitors the furnace exhaust gas temperatures and steam temperatures. Other readings 

may be incorporated into the ISB system which also communicates with the boiler control 

system. This system uses real-time data to identify which areas need sootblowing. Boiler 
DRAFT April 4, 2014 

7 

efficiency improvements have ranges from 0.3%-1.5% with capital costs around $300,000-

$500,000 and $50,000/year for fixed operating and maintenance costs. 

Air Heaters 

Air heaters operate to transfer heat between the incoming pre-combustion air and the 

effluent flue gas. These systems are critical to maintain an efficient power plant. In order to 

maintain these systems to operate most efficiently, air heater leakages must be maintained below 

6% of incoming air flow. Most leakage is due to the pre-combustion air leaking across the 

rotating section and leaving with the flue gas. This increases the flue gas volume going through 

the forced draft and induced draft fans to the emissions controls and avoids capturing the heat 

transferred between the flue gas and pre-combustion gas. The increased volume requires more 

power to pump more flue gas. Additionally, improvements to seals on the air heaters also reduce 

the leakages. Improvements to reduce air heater and duct leakages generally reduces the heat rate 

by 10-40 Btu/kWh with capital costs between $0.3-1.2M. 

A second method to improve the heat rate is to lower the air heater outlet temperature by 

controlling the acid dew point. Typically the air heater outlet is maintained at 20-30°F above the 

sulfuric acid dew point to prevent corrosion of cold-end baskets. Sorbent injections such as 

Trona or hydrated lime can be used to lower the dew point. Depending on the sizing of the air 

heater, the air heater may need to be modified in order to optimize the lower outlet temperature. 

Generally, a 40°F reduction in the air heater outlet results in 1% efficiency improvement. These 

systems are costly and depend on whether the air heater is adequate, needs modifications or 

needs a complete replacement. The capital costs can range from $1.5-18M for heat rate 

reductions of 50-120 Btu/kWh. 

Turbine 

The systems within the turbine area for which to focus heat rate improvements are the 

turbine, the feedwater heaters, the condenser, and the turbine drive and motor-driven feed 

pumps. 

Turbine 

The performance and longevity of turbines is constantly increasing with advances in 

technology. Most turbines in the industry are maintained so that the efficiency improvements are 

1-3%; however, some extremely degraded turbines may benefit up to 10% with a turbine 

overhaul. The capital costs for these projects ranges from $2-25M with heat rate reductions of 

100-300 Btu/kWh. 
DRAFT April 4, 2014 

8 

Feedwater Heaters 

The feedwater heaters are heat exchangers to heat the boiler feedwater by extracting heat 

from the steam leaving the turbine section. The efficiency can be increased by improving heat 

transfer surface area. This entails adding heat exchange surfaces to the existing heaters or adding 

additional heaters. The costs relative to the heat rate improvement associated with these projects 

typically prohibit the advancement of the project unless the feedwater heaters are in need of 

repair. 

Condenser 

To obtain the most efficiency from the condenser section, the most effective operation 

would have the steam from the turbine to reach the lowest temperature possible before entering 

the condenser. This allows for the turbine to extract as much energy from the steam as possible. 

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

water quality. To improve water quality, closed cooling water systems provide better control of 

the water quality and tube cleaning can be performed. Heat rate reductions observed from the 

condenser upgrades and maintenances are 30-70 Btu/kWh with annual fixed costs of $30,000-

$80,000. 

Boiler Feed Pumps 

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

of boiler feedwater through the heaters and boiler. Due to the high use of these pumps, 

maintenance is extremely important to ensure reliability and the most efficient operation. As the 

pumps wear and operate less efficiently, a pump overhaul may be required. The overhaul can 

reduce the heat rate by 25-50 Btu/kWh with capital costs around $250,000-$800,000. 

Flue Gas System 

Two aspects of the flue gas system that offer potential improvements to the plant 

efficiency are to improve the forced draft (FD) and induced draft (ID) fan efficiencies and 

implementation of VFDs. 

ID Fans 

One of the most important features in the fans is being able to control the flue gas flow. 

Many fans have dampers, which are the least effective and efficient option. There are many 

methods, such as variable inlet vanes (VIV), VFD, and variable pitch blades (VPB), available to 

control the flue gas flow allowing highly efficient fan performance. These upgrades or 

replacements provide a heat rate reduction of 10-50 Btu/kWh and cost between $6-$16M. 
DRAFT April 4, 2014 

9 

VFD 

It is apparent with the control that a VFD offers, the plant is able to reduce the auxiliary 

load immensely. Considering upgrading all drives, the capital costs are $6-16M with heat rate 

reductions between 10-150 Btu/kWh. 

Emission Control Technologies 

With the passage of environmental regulations, additional emission control devices have 

been and must be implemented in the power plant. These systems typically require large amounts 

of auxiliary power with their benefit being improved air quality. Even small upgrades can 

decrease the power requirements significantly while at least maintaining the same level of 

emissions reduction. The three technologies discussed are the flue gas desulfurization (FGD), the 

electrostatic precipitator (ESP), and the selective catalytic reduction (SCR) systems. 

FGD 

Coal-fired power plants contain many variances between their FGD systems. A few 

common technology improvements are discussed further in this section. Older units typically 

contained a venturi throat that increased the velocity of the fluid, but resulted in a large pressure 

drop and greater power to operate the ID fans. To improve this operation, a co-current spray 

tower quencher may replace the unit. The capital cost is about $2.5M with heat rate reductions 

around 13 Btu/kWh. 

Another technology upgrade affects the vanes and distribution plate into an absorber. The 

improvement of the gas flow coming into contact with the absorber sorbent increases SO2

capture, reduces maintenance due to erosion, and reduces the amount of energy required from the 

ID fan. Turning vanes and a perforated gas distribution plate improve gas distribution. The cost 

of the vanes is around $250,000 with heat rate reductions of 1-2 Btu/kWh. 

In a wet FGD multiple spray levels are installed to deliver the limestone slurry. If a power plant 

is operating with SO2 levels below its permit limit, turning off one spray level will reduce the 

auxiliary power necessary. If this is possible, a unit heat rate reduction of 16 Btu/kWh may be 

available. 

ESP 

The best operation for an ESP involves maintaining the maximum applied voltage, but 

below the level in which spark-over occurs. ESP energy management system (EMS) upgrades 

often help improve the ESP performance by maintaining the optimal performance and lowering 
DRAFT April 4, 2014 

10 

power consumption. The installation for this technology can be from minimal to $0.8M and can 

lower heat rate by 5 Btu/kWh. 

SCR 

For the last 15 years, SCR systems have been in use to reduce NOX emissions from 

power plants. Extensive modeling was performed to achieve the necessary reduction with 

minimum ammonia slip. The results showed that reducing pressure drop and using secondary air 

as dilution for the ammonia vaporizer can reduce the auxiliary power necessary. The heat rate 

reduction is 0-10 Btu/kWh and capital costs between $0.5-$2M with fixed and variable costs up 

to $100,000 each. 

Water Treatment System 

The water treatment system heat rate improvements can occur for the boiler water 

treatment and the cooling tower improvements. The boiler water is one of the most important 

aspects of the power plant. The quality of the water plays a huge impact on the scale buildup on 

the boiler tubes, which reduces the heat transfer in the tubes or can cause tube failures. Proper 

use of chemicals to maintain pure water is key. Also, high-quality water can reduce the 

blowdowns required, which allows for more steam in the turbine cycle. If the water is not 

properly maintained, heat transfer may be reduced up to 10%. 

Similar to the boiler water, the cooling towers are also affected by the water quality. 

Fouling and scaling remain issues for heat transfer and purity of the water. By maintaining the 

cooling water system efficiently, the overall water quality is improved, which branches into other 

aspects already mentioned. 
DRAFT April 4, 

Table 2-2. Existing coal-fired EGU efficiency improvements reported for actual efficiency improvemen

Efficiency 

Improvement 

Technology

Description 

Combustion 

Control 

Optimization 

Combustion controls adjust coal and air flow to optimize steam production for the steam turbine/generator set. However, combustion control for a coal-fired EGU is complex and impacts a number of important operating parameters including combustion efficiency, steam temperature, furnace slagging and fouling, and NOX

formation. The technologies include instruments that measure carbon levels in ash, coal flow rates, air flow ratCO levels, oxygen levels, slag deposits, and burner metrics as well as advanced coal nozzles and plasma assistcoal combustion. 

Cooling System 

Heat Loss 

Recovery 

Recover a portion of the heat loss from the warm cooling water exiting the steam condenser prior to its circulathorough a cooling tower or discharge to a water body. The identified technologies include replacing the coolin

tower fill (heat transfer surface) and tuning the cooling tower and condenser. 

Flue Gas Heat 

Recovery 

Flue gas exit temperature from the air preheater can range from 250 to 350°F depending on the acid dew point temperature of the flue gas, which is dependent on the concentration of vapor phase sulfuric acid and moistureFor power plants equipped with wet FGD systems, the flue gas is further cooled to approximately 125°F as it isprayed with the FGD reagent slurry. However, it may be possible to recover some of this lost energy in the flugas to preheat boiler feedwater via use of a condensing heat exchanger. 

Low-rank Coal 

Drying 

Subbituminous and lignite coals contain relatively large amounts of moisture (15 to 40%) compared to bitumincoal (less than 10%). A significant amount of the heat released during combustion of low-rank coals is used to evaporate this moisture, rather than generate steam for the turbine. As a result, boiler efficiency is typically low

for plants burning low-rank coal. The technologies include using waste heat from the flue gas and/or cooling wsystems to dry low-rank coal prior to combustion. 

Sootblower 

Optimization 

Sootblowers intermittently inject high velocity jets of steam or air to clean coal ash deposits from boiler tube 

surfaces in order to maintain adequate heat transfer. Proper control of the timing and intensity of individual sootblowers is important to maintain steam temperature and boiler efficiency. The identified technologies inclu

intelligent or neural-network sootblowing (i.e., sootblowing in response to real-time conditions in the boiler) a

detonation sootblowing. 

Steam Turbine 

Design 

There are recoverable energy losses that result from the mechanical design or physical condition of the st

turbine. For example, steam turbine manufacturers have improved the design of turbine blades and steam s

which can increase both efficiency and output (i.e., steam turbine dense pack technology). 

Source: National Energy Technology Laboratory (NETL), 2008. Reducing CO2 Emissions by Improving the Efficiency of the Existin

Fleet, DOE/NETL-2008/1329. U.S. Department of Energy, National Energy Technology Laboratory, Pittsburgh, PA. July 23, 200

<http://www.netl.doe.gov/energy-analyses/pubs/CFPP%20Efficiency-FINAL.pdf>. a Reported efficiency improvement metrics adjusted to common basis by conversion methodology assuming individual component e

plant as follows: 87% boiler efficiency, 40% turbine efficiency, 98% generator efficiency, and 6% auxiliary load. Based on these a

power plant has an overall efficiency of 32% and a net heat rate of 10,600 Btu/kWh. As a result, if a particular efficiency improvemto achieve a 1% point increase in boiler efficiency, it would be converted to a 0.37 % point increase in overall efficiency. Likewisedecrease in net heat rate would be converted to a 0.30% point increase in overall efficiency. 
DRAFT April 4, 2014 

12 

Previous Studies on Heat Rate Improvements 

A number of studies using varying approaches have been performed to determine 

potential efficiency improvements and associated resulting CO2 emission reductions. These 

approaches include characterizing the current U.S. coal-fired EGU fleet, identifying potential 

efficiency improvements, and applying improvement actions to existing EGUs. The approach 

taken within each study varies. Five studies are briefly summarized and compared in Table 2-3. 

Studies 1 and 2 used a benchmarking approach that evaluated the design factors that are 

known to influence efficiency and grouped EGUs based on similar design characteristics. The 

studies categorized the industry based on fuel type, location, steam cycle, and age of the boilers. 

Potential efficiency improvements were calculated based on an assumption that the lowerperforming EGUs in each group should to be able to do as well as the better performing EGUs in 

that group. Specifically, the goal for potential improvement: for each subcategory was that the 

bottom 90% of EGUs in each group improved their heat rate to the average performance of top 

10% in that group. While the studies are different in the level of detail and assumptions, the 

results of these studies overall suggest that a U.S. coal-fired EGU fleet-wide improvement 

ranging from 9% to 15% is theoretically possible. Study 3 used a less detailed approach and 

evaluated technologies applicable to bituminous and subbituminous coals to estimate potential 

fleet wide reductions. 

An alternative approach to evaluate heat rate improvement is used for Study 4. This study 

focused on the operating efficiency (synonymous with heat rate) of the entire existing U.S. coalfired EGU fleet. The authors evaluated decades of data from industrial responses to economic 

factors such as demand, coal price and energy policies. This approach determined that given 

specific changes in the coal price and a carbon tax, the industry will make heat rate 

improvements on their own. In this specific example, the coal price was assumed to be a 10% 

increase and the CO2 emissions tax at $1.64 per ton for heat rate reductions of 0.3 to 0.9%. 

Study 5 considered the fleet of coal-fired EGUs and assumes a target heat rate in order 

for the EGUs to comply with an inferred standard. As opposed to the above studies that 

determined by how much the efficiencies can improve, this approach estimated how the industry 

will meet any imposed standards and calculated the heat rates necessary to meet a standard. As it 

has not been determined with regards to how the CO2 emissions limit will be averaged, the paper 

discusses many potential options that coal-fired EGUs may have to meet new standards. These 
DRAFT April 4, 2014 

13 

options include additional options such as adding renewable, natural gas, and combined-cycle 

sources. 

The EPA observed that most of the existing studies develop fleet-wide average HRI 

potentials/goals that are higher than values considered feasible and sustainable by the power 

sector engineers with whom the EPA has informally discussed this subject. The EPA also noted 

that all existing HRI studies have relied on a single year annual average heat rate data, whereas 

many of the operational impacts on heat rate (diurnal temperatures, load following, etc) become 

more apparent in the variability of hourly performance data. We further recognized that an 

examination of heat rate data over a multiple year period, perhaps a decadal time frame might 

reveal patterns of performance that should also inform estimates of HRI potential. For these 

reasons, the EPA has developed in this TSD an additional assessment of HRI potential that draws 

on multiyear historical hourly data. While we understood that engineering judgment would still 

be essential to a proper interpretation of the results, the EPA intended that this assessment be a 

more substantial basis for estimating the fleet-wide HRI potential for coal-fired EGUs. 

Table 2-3. Summary comparison of previous studies on EGU heat rate improvements 

Study 

ID 

Study Title 

Author 

Factors Used for 

Industry Grouping 

Key Study 

Assumptions 

Study 

Results 

1 “Reducing CO2 

Emissions by 

Improving the 

Efficiency of the 

Existing Coal-fired 

Power Plant Fleet” 

NETL 

• Plant design: age and 

steam cycle 

• Category improvement is 

the bottom 90% of EGUs in 

each group improving their 

heat rate to the average 

performance of top 10% in 

that category 

• Units with capacity factors 

under 50% were removed 

from dataset 

• 15% reduction in 

overall heat rate of 

coal-fired EGUs 

2 “Improving the 

Efficiency of CoalFired Power Plants 

for Near Term 

Greenhouse Gas 

Emissions 

Reductions” 

NETL 

• Plant design: coal type, 

steam cycle, and size 

• Category improvement is 

the bottom 90% of EGUs in 

each group improving their 

heat rate to the average 

performance of top 10% in 

that category • Units with 

anomalous data, capacity 

factors under 10%, using 

less than 97% coal, and 

gasification plants were 

removed from dataset 

• Low pressure subcritical 

units and 0-200 MW 

subbituminous units 

assumed retired for goal 

• Lost generation made up by 

more efficient coal-fired 

EGUs 

• 8.7% reduction in 

overall heat rate of 

coal-fired EGUs 
DRAFT April 4, 2014 

14 

Study 

ID 

Study Title 

Author 

Factors Used for 

Industry Grouping 

Key Study 

Assumptions 

Study 

Results 

3 “Reducing Heat 

Rates of Coal-Fired 

Power Plants” 

Lehigh Energy 

Update 

 All possible heat rate 

improvements are made 

including drying of high 

moisture coal: 

• 10% improvement 

for bituminous coalfired EGU 

• 15% improvement 

for subbituminous 

coal-fired EGU 

4 “Regulating 

Greenhouse Gases 

from Coal Power 

Plants under the 

Clean Air Act” 

Resources for the 

Future 

• Analyze the actual 

operating efficiency of the 

entire fleet of U.S. coalfired EGUs 

• Assess abatement 

opportunities and costs by 

observing how coal plants 

respond to market and 

regulatory incentives to 

improve energy efficiency 

Overall efficiency 

improvements of 2 to 5%, 

from other literature studies 

10% coal price 

increase, 

corresponding to a 

tax on CO2

emissions of about 

$1.64 per ton, 

improving heat rates 

by 0.3 to 0.9 % 

5 “Closing the Power 

Plant Carbon 

Pollution Loophole: 

Smart Ways the 

Clean Air Act Can 

Clean Up 

America’s Biggest 

Climate Polluters” 

NRDC 

• Plant design: coal type 

and steam cycle 

Improvements are broken into 

3 group 

• Top 10% for each 

subcategory, no change 

• Top 11% to 49%, improve 

heat rate by 50% of the 

difference between facility 

heat rate and performance of 

top 10% in class or 600 

Btu/kWh, whichever is less 

• Bottom 50%, improve heat 

rate by 100% of the difference 

between facility heat rate and 

performance of top 10% in 

class or 600 Btu/kWh, 

whichever is less 

EPA’s Heat Rate Improvement Assessment 

This EPA assessment of fleet-wide HRI potential looks at historical data from coal-fired 

EGUs in the U.S. to identify changes to EGUs’ heat rates – the amount of heat input required, on 

average, to generate 1 kWh of electricity – that can be attributed to operation and maintenance 

practices and equipment upgrades. These heat rate changes are analyzed to determine their 

applicability to the rest of the coal-fired EGU fleet and to determine the potential heat rate 

improvement that, on average, could be achieved by the fleet. 

This data analysis portion of the study relies on unit-level heat input and gross generation 

data reported to the EPA by owners or operators of EGUs to assess in detail the changes in gross 

heat rates. Potential changes in net heat rates are then addressed later in this section. Unit-level 

evaluations allowed the EPA to recognize the significant heterogeneity of coal-fired EGUs; even 
DRAFT April 4, 2014 

15 

‘sister’ units, units built at the same time at a given facility, may display different operating 

profiles and may have different equipment, controls, fuel mixes or cooling systems. 

Based on literature reviews; informal interviews with engineering experts, vendors, and 

plant operators; and historical information collected by the EPA, we believe EGUs achieve heat 

rate improvements by: 1) operating under recommended operation and maintenance conditions 

(best practices), and 2) installing and using equipment upgrades. Best practices include no-cost 

or low-cost methods such as the installation or more frequent tuning of control systems and the 

like-kind replacement of worn existing components. Upgrades often involve higher costs and 

greater downtime, such as, extensive overhaul or upgrade of major equipment (turbine or boiler) 

or replacing existing components with improved versions. 

The EPA developed unit-level statistics from over 60 million rows of hourly data. We 

evaluate each unit on its individual performance using heat rate variability as an indicator of the 

application of best practices and potential for improvement. To estimate heat rate improvement 

through equipment upgrades we survey engineering studies, examine year-to-year trends, and 

research EGUs where such methods were applied. 

Study Population and Data 

The EGU study population consists of 884 coal- and petroleum coke-fired EGUs that 

reported both heat input2 and electrical output to the EPA’s Clean Air Markets Division in 2012.3

It includes a wide range of configurations, from 24 to 1,500 MW nameplate capacities, super and 

subcritical thermodynamic cycles, between 1 and 69 years old, and different coal ranks. It 

excludes any EGUs at any facility that reported cogeneration to the EPA or the EIA. These units 

are excluded because a portion of the heat input was used to generate electricity and/or steam 

heat. Therefore, it is difficult for the EPA, using available data, to make a meaningful 

comparison of these units’ heat rates. 

The EPA performed this study using hourly heat input (Btu), and electricity output 

(MWh) data from the Clean Air Markets Division and meteorological data from NOAA’s 

National Climatic Data Center for the years 2002-2012. As described later in this section, these 

meteorological data were used to account for temperature impacts on heat rates. The eleven year 

study period is representative of a wide range of conditions, including growth and recessionary 

                                                            

2 Sources calculate heat input using an ‘F factor’ for the carbon content of the fuel being combusted and the average 

hourly measurements of CO2 flow and concentration. 3

 Information on the Clean Air Markets Division data is available at http://ampd.epa.gov/ampd/
DRAFT April 4, 2014 

16 

economic conditions, changing electricity generation from renewable and natural gas, and 

different regulatory constraints. 

The hourly heat input and generation data used in this study is collected under the 

authority of 40 CFR part 75 (hereafter, Part 75). The EPA designed Part 75 to encourage 

complete and accurate emission measurement and reporting to support emission trading 

programs, including the Acid Rain Program and Clean Air Interstate Rule (CAIR). However, the 

EPA recognized that there will be times when emission data are not available due to monitoring 

system malfunctions or maintenance, technical challenges, or missed quality assurance/quality 

control (QA/QC) tests. When data are not available or deemed invalid (e.g., when a QA/QC test 

was not performed as required), the EPA has specified data substitution methods that are 

designed to 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 

EPA excluded substitute data reported by EGUs from this study’s dataset. These substitute data 

represent approximately 2% of all reported operating hours. In addition, we excluded partial 

hours of operation that occur during the first hour of startup and the last hour of shutdown. 

We also exclude 40 unit-years (0.5% of records) with atypical annual heat rates less than 

6,500 or greater than 15,000 Btu/kWh resulting from a variety of factors including firing of 

natural gas, very low operating time, or errors reporting gross load. Table 2-4 summarizes the 

unit counts by year for the study population used in this work. This population corresponds to 

9,350 unit-years of data at 884 distinct EGUs. 
DRAFT April 4, 2014 

17 

Table 2-4. Study Population Unit Count by Year4

Year Unit Count 

2002 833

2003 828

2004 833

2005 836

2006 845

2007 844

2008 851

2009 860

2010 865

2011 876

2012 879

NOAA’s Integrated Surface Data (ISD) product provides hourly temperature for over 

20,000 weather stations worldwide.5 Since EGU performance is sensitive to air temperature and 

barometric pressure, which vary with elevation, we use meteorological data from stations that are 

reasonably close to the EGU's location and elevation to account for the impact of ambient 

conditions. For each of the plants in this study’s database, we identified the nearest stations that 

reported a minimum of 8,400 hourly observations in the calendar year (i.e., greater than 95% of 

the hours in a year). Generally, each plant was associated with meteorological data from the two 

closest stations over the eleven-year study period. The average distance between the plant and 

station was 22 miles and the average difference in elevation was 366 feet. At nine plants we used 

data with as few as 7,000 observations in order to keep the maximum difference in elevation 

under 1000 feet. The EPA believes that nearby weather station measurements are a good 

approximation of ambient meteorological conditions at each facility. Joining the trimmed heat 

rate and hourly temperature datasets resulted in 61,848,580 hourly records for the study 

population of EGUs (see Table 2-4). 

The results of this study are based on analyses of data from the population of coal-fired 

EGUs shown in Table 2-4. These units emitted 1,606 million tons of CO2 in 2012. In contrast, 

emissions of CO2 from coal-fired EGUs in the entire U.S. electric power sector in 2012 were at 

                                                            

4 The study population for each year includes those EGUs that reported both heat input and electric generation.
DRAFT April 4, 2014 

18 

1,669 million tons according to the EIA.6

 Since the study population of EGUs accounted for over 

96% of CO2 emissions from the fleet of U.S. coal-fired EGUs, the EPA considers the results of 

this study to be applicable to the coal-fired fleet at large. 

Subcategorization 

In this analysis, units are not categorized by unit specific design characteristics or fuel 

because: (1) EGU-specific detailed design information on all factors that influence heat rate is 

not available, and (2) certain design characteristics are not easily categorized (e.g., EGUs use a 

large range of steam conditions). Several other studies do categorize EGUs broadly by capacity, 

thermodynamic cycle, and/or fuel rank. Although the EPA believes grouping by categories can 

provide a useful way of understanding the operating profile of an EGU and the fleet, the range of 

heat rates for the broad categories has significant overlap (see Figure 2-1) and therefore makes it 

challenging to develop appropriate categorization. The figure below displays available 

information on coal-fired EGUs considered in this work for the years 2009-2011 in typical 

subcategories of capacity, fuel rank, and thermodynamic cycle. As the figure reflects, the means 

are clustered and the ranges of heat rates overlap. 

 

Figure 2-1. 3-Year Average Heat Rates by Subcategory7

                                                            

6

 Preliminary 2012 results from http://www.eia.gov/tools/faqs/faq.cfm?id=77&t=3. Revised 2012 results will be 

available in March, 2014. The somewhat lower 2012 CO2 emissions total in Table 2-5 below is due to the exclusion 

of substitute data.    7 Abbreviations in the figure: BIT means bituminous, SUB means subbituminous, LIG means lignite, SUPER 

means supercritical, SUB means subcritical OVER/UNDER means greater/less than indicated MW capacity.

6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000

BIT SUPER

SUB SUPER

BIT OVER 200

PC

BIT 100 to 200

SUB OVER 100

LIG OVER 100

BIT UNDER 100

SUB UNDER 100

LIG UNDER 100

3-Year (2009-2011) Average Heat Rate (Btu/kWh)

Subcategory
DRAFT April 4, 2014 

19 

Observed Trends in the Period 2002-2012 

Three trends are notable for the study population during the period 2002-2012. 

Comparing the averages of the first three years (2002-2004) to the last three years (2010-2012), 

electric generation, capacity factor, and gross heat rate declined by 9%, 21%, and 2%, 

respectively. The decrease in coal-fired generation and capacity factor may be because of 

reduced demand for electricity resulting from the recession starting in late 2008 and greater use 

of natural gas and renewables to generate electricity. 

The 11-year average annual gross heat rate for the study population of coal-fired EGUs 

(see Table 2-4) was 9,763 (Btu/kWh). The decrease in study population annual heat rate between 

2002 and 2012 may be due to several factors. Unit efficiency may have improved or units with 

lower heat rates may have taken up a larger share of generation. In addition, changes in reporting 

methodology described later in this chapter may be partly responsible. The minimum annual heat 

rate (9,650 (Btu/kWh)) occurred in 2008, near peak generation for the years under consideration, 

and was approximately 1% below the average. Table 2-5 displays the annual heat input, 

electricity generation, capacity factor, and heat rate for the study population of EGUs. Figure 2-2 

displays the average annual gross heat rate by year and the 11-year average. 

Table 2-5. Trends 2002-2102 

Year Heat Input 

(million Btu) 

Electric 

Generation 

(MWh-gross) 

Operating 

Hours 

Capacity 

Factor 

(%) 

Heat Rate 

(Btu/kWhgross) 

2002 18,661,321,692 1,877,860,222 6,130,609 64 9,938 

2003 18,490,002,370 1,868,191,406 6,044,559 65 9,897 

2004 18,488,140,910 1,880,068,323 6,048,381 65 9,834 

2005 18,754,700,745 1,916,068,402 6,141,697 66 9,788 

2006 18,746,450,250 1,922,588,408 6,155,013 65 9,751 

2007 18,787,425,977 1,927,419,559 6,138,888 66 9,748 

2008 18,545,285,797 1,921,820,484 6,088,562 64 9,650 

2009 16,670,621,043 1,726,641,303 5,448,438 54 9,655 

2010 17,771,232,591 1,838,417,252 5,754,116 58 9,667 

2011 17,006,597,908 1,750,427,841 5,507,574 53 9,716 

2012 15,010,214,648 1,541,305,063 4,816,547 44 9,739 
DRAFT April 4, 2014 

20 

Figure 2-2. Study population Average Gross Heat Rate by Year 

Startups and Shutdowns - Impact On the Results of This Study 

During periods of startup and shutdown, EGUs are known to operate at higher heat rates. 

Therefore, we evaluated the potential impact of such events on our evaluation. A startup event, 

as defined here, occurs when an EGU begins combusting fossil fuel and generates some 

measurable amount of electricity. Table 2-6 summarizes the study population average, 

maximum and total starts by year. On average, coal-fired EGUs start combusting fuel and 

generating electricity 11 times per year. The total number (approximately 9,000) of starts for the 

study population of EGUs has remained stable over the study period. Our data reflects that some 

coal-fired units operate in a load following capacity and may report upwards of 200 starts in a 

single year, but these units tend to have low annual capacity factors. The subset of EGUs with 

more than 20 annual startup and shutdown events is responsible for less than 4% of total 

generation in any study year. Therefore while the number of starts is an important variable at a 

small number of EGUs, its impact on heat rate performance evaluated in this study is considered 

to be marginal. 

9,500

9,550

9,600

9,650

9,700

9,750

9,800

9,850

9,900

9,950

10,000

20022003200420052006200720082009201020112012

Heat Rate (btu/kwh)

Annual Heat Rate

11-yr Avg Heat Rate
DRAFT April 4, 2014 

21 

Table 2-6. EGU Start Count by Year 

Year Average Maximum (at 

any single EGU) Total 

2002 11.1 209 9,363 

2003 10.6 194 8,936 

2004 10.7 134 9,081 

2005 11.0 183 9,265 

2006 10.5 139 8,859 

2007 10.5 164 8,908 

2008 10.4 134 8,880 

2009 10.3 178 8,902 

2010 10.5 211 9,110 

2011 10.6 206 9,295 

2012 9.9 119 8,805 

Impact of capacity factor and ambient temperature 

Two important factors that affect heat rate at an EGU are hourly capacity factor and 

ambient temperature. In this section, we examine the impact of these two variables on heat rates 

of the EGUs in the study population. 

Coal-fired units are designed to operate most efficiently at full capacity. As a unit drops 

below this level, in general, heat rate will increase. The average capacity factor over 11 years for 

the study population is 67%, but as noted above, has moved markedly over the study period. This 

study looks at utilization level at both hour and year time scales. The two are related but reveal 

different information about how an EGU is operating. For example, for a unit to achieve a high 

annual capacity factor (e.g., over 90%) it must operate at a high load for most hours in a year. At 

lower capacity factors interpreting the relationship between hourly and yearly utilization levels 

becomes more complex. For example, an EGU may run at an annual 60% capacity factor by 

operating 8 months at near full capacity and generating no electricity the rest of the year, or it 

may run at lower utilization levels for most hours of the year in response to weather, generation 

cost, and transmission constraints. 

Ambient temperature can affect heat rate in two ways: 1) the efficiency of the 

thermodynamic steam cycle8

 and, 2) in many regions of the country, as temperatures increase 

                                                            

8

 The availability of a cold heat sink in the condenser is a key factor in that cycle. The design of the heat exchanger, 

type of cooling system and availability of water all have an impact on performance. An increase in ambient air 
DRAFT April 4, 2014 

22 

electricity demand capacity factor follows. Figure 2-3 shows the average monthly capacity factor 

in 2012 alongside the climate normal monthly temperature.9 The lines intersect in the spring as 

temperatures begin to rise and the need for cooling drives electricity demand. Peak capacity 

factor and generation in most parts of the U.S. occur on the hottest days of the year. 

Figure 2-3. Monthly Capacity Factor, 2012. 

Regression Analysis

Using the hourly data set, the EPA performed three regression analyses for each unityear: heat rate onto capacity factor, heat rate onto ambient temperature and heat rate onto 

capacity factor and ambient temperature. The single variable analyses help to examine the 

relative influence of capacity factor and ambient temperature on heat rate. Since this analysis 

seeks to evaluate heat rate under normal operating conditions, we removed records with hourly 

heat rate values outside of +/- 2.6 standard deviations (1.9% of records) before performing the 

regressions.10 Similarly to partial operating hours, these outliers tend to occur during low load 

conditions. The records trimmed amount to one-fourth of a percent of the total study population 

generation. Regression results describe the goodness of fit for the model and are expressed as the 

coefficient of determination or ‘r-squared’. To represent the relative contribution of varying unit 

capacities all results are generation-weighted.11 The average study population r-squared for the 

multivariate regression is 26%. This means that hourly ambient temperature and capacity factor 

                                                                                                                                                                                               

temperature, and consequent increase in water temperature, typically lower the effectiveness of the cooling system, 

the condenser, and, therefore, overall plant efficiency. 9 Climate normal is the average of temperature (or other measure) over a prescribed 30-year interval and location. 

The chart shows the 1981-2010 climate normal monthly temperature at Baltimore-Washington Airport, MD. 10 The 2.6 standard deviation bound is used in other EPA regulatory analyses. 11 In a weighted average, each component is multiplied by a factor reflecting its importance. In this case, generationweighted r-squaredis the average of r-squared for each unit multipliedby its annual generation.

0

20

40

60

80

100

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Electric generation monthly 2012 capacity 

factor and normal temperature

Capacity Factor

(Monthly %, 2012)

Climate Normal

(BWI, MD)
DRAFT April 4, 2014 

23 

together explain 26% of the change in heat rate for the study population over the study period. 

The average study population r-squared from the single variable analysis of capacity factor is 

16%; the corresponding result for temperature is 10%. This means that approximately 16% of 

the change in hourly heat rate is attributable to capacity factor and 10% to ambient temperature. 

These results, however, conceal considerable variability. Some EGUs, typically load-following, 

have an 11-year average r-squared for capacity factor exceeding 50%. At those EGUs, the 

capacity factor is a key variable influencing changes in heat rate. 

At approximately one-fourth of the study population the response to ambient temperature 

is larger than the response to capacity factor. At individual EGUs, temperature may explain up to 

30% of the change in heat rate. These are typically, but not exclusively, units with once-through, 

fresh water, cooling systems. Identifying temperature-responsive 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. At a typical EGU, summer month heat 

rates may increase by 2-4% compared to winter months, but at a temperature-responsive EGU 

that figure may be as high as 10%. 

Our results found that as EGUs cycle more, i.e., move from base load to load following, 

capacity factor will tend to have a larger effect on heat rate. Since 2008, the study population 

capacity factors moved from the top load bin into lower load bins. This can be seen from Figure 

2-4, which compares the study population duty cycles in 2008 to 2012. A significant share of 

2008 generation occurred at EGUs running at greater than 85% annual capacity factor. In 2012, 

little generation took place in that bin, and generation was reduced by about half in the next 

lower bin (79-84% capacity factor). 
DRAFT April 4, 2014 

24 

Figure 2-4. Change in Annual Duty-Cycle 2008 and 2012 

Heat Rate Variability and Indication of Improvement Potential 

This study examines heat rate variability from the standpoint of statistical process 

control, which is utilized throughout the power industry. Several years ago, the EPA introduced 

process control charts for auditing emissions data reported under Part 75. Sources and vendors 

adopted the EPA methodology to identify potential problems early, before they significantly 

affect emission measurements. Heat rate lends itself to process control since it is the principal 

indicator that defines the quality of the electric generation process.12,13 Therefore, in general, 

high variability in heat rate values would reflect opportunities for process improvement. 

We use the relative standard deviation (RSD) of the hourly heat rates to evaluate each 

unit against its past performance and to compare with the study population. Each unit has up to 

eleven RSD values, i.e., one for each operating year between 2002 and 2012. The generationweighted mean RSD for the study population across 11 years is 5.4%. Table 2-8 summarizes 

eleven years of results for the study population by quartiles ordered by the 11-year generationweighted RSD (ascending).14 The RSD of the top quartile (3.5%) is significantly lower than the 

study population generation-weighted mean RSD of 5.4%. Notably, the EGUs in the top quartile 

are not outliers; they report a third of all generation – the most of any segment. The results 

display a wide range of heat rate variability in the study population and thereby indicate the 

potential for heat rate improvement. 

Table 2-8. RSD in reported heat rate (generation weighted) 

Quartile RSD 

Average 

RSD 

Minimum 

RSD 

Maximum 

Share of 

Generation 

1 3.5 1.6 4.2 33

2 4.7 4.2 5.3 26

3 6.1 5.3 7.0 24

4 9.8 7.0 25.2 16

                                                            

12 “The principal indicator that defines the quality of the process is heat rate.” (Fredrick & Todd, 1993. Statistical 

Process Control Methods in Performance Monitoring. Available at 

famos.scientech.us/Papers/1993/1993section11.pdf) 

13 Since accurate measurement is essential to process control the introduction of increasingly sophisticated digital 

control systems (DCS) presents new opportunities for finding inefficiencies. Vendors (ABB, Seimens, Emerson) 

claim heat rate improvements of 2-5 percent can result from upgrading to a modern DCS and advanced control 

technologies. The improvement can be even higher if system-wide real-time optimization is included. 14 Nine EGU RSD values exceeded 2.6 standard deviations above the mean and were removed from the results in the 

table.
DRAFT April 4, 2014 

25 

The study also examined EGU heat rate variability using the residual heat rate. The 

residual in a regression analysis is the difference between the observed value of the dependent 

variable (heat rate) and the predicted value. The intercept is the value where the linear regression 

crosses the y-axis. For each EGU, we calculated the residual heat rate by summing the residual 

for each hour to the intercept value. The standard deviation of the residual heat rate statistic is 

used to understand the amount of variability that is not explained by capacity factor and 

temperature. 

The average RSD corresponding to residual heat rate variability for each EGU is the 

generation-weighted average of up to eleven annual values. The study population generationweighted mean RSD over the study period is 4.5%. This percentage represents the total 

variability across the study population that our analysis could not explain by hourly capacity 

factor or ambient temperature. Possible causes of this variability include changes in plant 

equipment, operating procedures and maintenance, fuels (particularly coal rank), reporting 

methodology, and unexplained factors. There is no temporal trend evident in the RSD. Table 2-9 

summarizes the study population generation-weighted average RSD of residual heat rate over the 

study period in quartiles ordered by the 11-year generation-weighted RSD (ascending). 

Table 2-9. RSD of residual heat rate (generation weighted)15

Quartile RSD 

average 

RSD 

Minimum 

RSD 

Maximum 

1 2.7 0.0 3.2 

2 3.6 3.2 4.1 

3 4.7 4.1 5.3 

4 6.9 5.3 10.4 

The weighted average RSD of the top quartile is 2.7% – well below the study population 

average of 4.5 %. This means that the residual hourly heat rates of these units generally stay in a 

narrow range within a given year. The maximum RSD in the top quartile is 3.2%. From the 

statistical process control point of view, these units appear to have low variability. 

The weighted average RSD of the bottom quartile is 6.9%, which is over twice that of the top 

quartile. This spread indicates that there is likely room for improvement in study population 

operation to reduce variability and heat rate. 

                                                            

15 This table excludes nine units where RSD exceeded 2.6 standard deviations from the mean. 
DRAFT April 4, 2014 

26 

Heat rate variability and performance 

To examine the association between heat rate variability and heat rate performance this 

study examined the RSD for unit-year heat rates calculated from reported data. The study 

population generation-weighted annual RSD ranges between 5% and 6% during the study period. 

Figure 2-5 below summarizes the results of regressing RSD of heat rate onto annual heat rate.16

The r-squared result is 57%. These results indicate that, other factors held equal, if an EGU 

reduces heat rate variability, generally heat rate performance will improve. 

Figure 2-5. Regression analysis of reported heat rate RSD onto annual heat rate 

Units with large heat rate changes 

Over one third of the study population (355 units) reported at least one year-to-year 

change in heat rate greater than +/- 8.5%.17 We consider this magnitude to be in the upper range 

of what would be expected due to changes in fuel rank, operations and maintenance, or plant 

equipment. Table 2-10 presents the counts by three categories: EGUs with at least one year-toyear decrease in heat rate > 8.5%; units with at least one year-to-year increase in heat rate > 

8.5%; and, units with both. We examined whether the large heat rate changes were due to a yearto-year changes in capacity factor and found no correlation between the year-to-year changes in 

heat rate and capacity factor for any of the three groups in Table 2-10.18 This would indicate that 

other factors account for these large changes to heat rate. The EPA’s research found that 

approximately two-thirds of the large decreases in heat rate can be associated with changes in 

                                                            

16 The regression analysis was performed on 9,348 unit-years of study data which were trimmed to remove values 

outside 2.6 standard deviations.

17 After removing unit-years where annual capacity factor fell under 50 percent the count is 313 EGUs. 18 The correlation remains weak even when limited to cases where capacity factor changed more than 30 percent. 

y = 0.002x - 14.254

R2 = 0.5704

5.0

5.2

5.4

5.6

5.8

6.0

6.2

9600 9650 9700 9750 9800 9850 9900 9950

RSD heat rate % 

(generation weighted)

Heat Rate
DRAFT April 4, 2014 

27 

reporting method implemented to provide more accurate heat input data.19 The large changes 

noted at the remaining one-third could not be explained by changes in reporting methodology. 

Moreover, we found no correlation between changes in reporting method and heat rate RSD. 

Table 2-10. Year-to-Year Heat Rate Change 

Description Count 

Correlation of 

heat rate to 

capacity factor 

Units with only year-to-year heat rate decrease > 8.5% 166 .1 

Units with only year-to-year heat rate increase > 8.5% 80 .1 

Units with both year-to-year heat rate decrease and increase > 8.5% 355 .1 

The breakdown of the ‘large decrease’ EGUs by quartile, in Table 2-11 below, is consistent with 

the study population results shown in Table 2-8. This does not imply that the changes associated 

with a large year-to-year decrease, which may include operations and maintenance, more 

accurate reporting methods, or new equipment, do not affect heat rate variability. If they occur as 

part of an engineering effort to improve efficiency, heat rate variability may also be reduced. 

Table 2-11. RSD in reported heat rate of 166 ‘large 

decrease’ EGUs (generation weighted) 

Quartile RSD 

Average 

RSD 

Minimum 

RSD 

Maximum 

1 4.0 2.3 4.8 

2 5.3 4.8 5.9 

3 6.6 5.9 7.5 

4 10.5 7.6 26.5 

Assessment of heat rate improvement potential via best practices 

As mentioned before, across the study period, the effects of hourly capacity factor and 

ambient temperature explain a generation-weighted average of 26% of the change in study 

population heat rate.20 This means that on average 74% of the change remains unexplained after 

                                                            

19 EPA Reference method 2 specifies the normal procedure for measuring stack gas volumetric flow rate during a 

relative accuracy test audit. Methods 2F, 2G, 2H and CTM-041 are approved alternatives. Methods 2F and 2G 

correct measured flow rates for angular (non-axial) flow, Method 2H (for circular stacks) and conditional test 

method CTM-041 (method J, for rectangular stacks and ducts) are used to correct measured flow rates for velocity 

decay near the stack wall, using a “wall effects adjustment factor”. These alternative methodologies are optional. 

Therefore, given the additional complexity and cost of using these alternatives a source is likely to use them only if 

the results are significantly lower volumetric stack gas flow. The EPA was unable to draw conclusions about the 

effect of changes in flow reporting methods on fleet heat rate performance.

20 The 26% result is the generation weighted average of r-squared values from the multivariate regression analysis.
DRAFT April 4, 2014 

28 

controlling for those factors. The residual heat rate analysis determined there is significant 

variation in the operation of EGUs. Since lower heat rate variability is associated with lower heat 

rate, other factors held equal, the range of variation indicates that significant potential heat rate 

improvement is available through the application of best practices. 

To control for known factors, the EPA constructed a model that groups each EGU’s 

hourly heat rate data into 14 temperature bins and 12 capacity factor bins, resulting in a 12 by 14 

matrix of 168 bins.21 For a given EGU, a temperature and capacity factor bin will have all the 

relevant hourly values over the eleven-year study period. For each bin with 15 or more values the 

model finds the reported hourly heat input value corresponding to the 10th percentile(p10).22

This means that approximately 90% of the heat input values in that bin exceed p10. For each 

unit, the model reduces the reported hourly heat input greater than p10 by a percentage of the 

distance between the reported value and p10, e.g., 50% of the difference. The same statistical 

procedure is applied to every hour of heat input data in each bin. These reduced hourly heat input 

values are then used to calculate a reduced 11-year average heat rate for each unit. The percent 

difference between a unit’s reported 11-year average heat rate and the heat rate that corresponds 

to reduced heat inputs is the potential heat rate improvement for that unit.23 Using this approach, 

those units with the lowest variability (e.g., in the top quartile of residual heat rate variability) 

take proportionally smaller reductions. 

Table 2-12 below shows the model results with options of 10% to 50% stringency. For example, 

reducing reported heat input 10 % of the distance to the p10 value achieves a 1.3% study 

population wide reduction. Alternatively, a 50% reduction will result in a 6.7% study population 

wide improvement in heat rate. In effect, the model proportionately reduces heat rate variability 

and improves performance for each unit while controlling for temperature and capacity factor. 

The heat rate improvement for the study population is derived from the performance of each 

individual EGU as compared to its own record. 

                                                            

21 The matrix provides up to 168 bins but only 164 contained hourly values. Temperature bins ranged from -20 to 

greater than 110 with 10 degrees F in each. Capacity factor bins ranged from 0% to greater than 110% with 10% in 

each. 

22 Performing the calculation with a minimum of 30 values in each bin has a modest effect on the results in Table 2-

12. For example, a 30% reduction obtains a 3.9% fleet wide improvement in heat rate (rather than 4.0%). 23 Heat rate is calculated as the sum of heat input (btu, reported or reduced) divided by the sum of generation (kWh) 

for the given population and time period.  
DRAFT April 4, 2014 

29 

Table 2-12. Assessment of heat rate improvement potential via best practices 

% Reduction from 

reported heat input 

to p10 

Study population 

heat rate 

(Btu(kWh-gross)24

Reduced study 

population heat 

rate (Btu/kWhgross) 

Study population 

heat rate 

improvement (%) 

10 

9,755 

9,625 1.3 

20 9,495 2.7 

30 9,365 4.0 

40 9,235 5.3 

50 9,105 6.7 

Assessment of potential heat rate improvement via equipment upgrades 

The EPA inspected the study population to find examples of EGUs that made significant 

year-to-year improvements in heat rate. After filtering out those cases that may have been the 

result of changes in capacity factor, reporting method, or other events, we identified 16 EGUs 

that reported year-to-year heat rate improvements of 3-8%. In two of these cases we were able to 

identify equipment upgrades responsible for 2-3% heat rate improvement using the applicable 

estimates from the Sargent & Lundy 2009 study. Similarly, in the other cases, while our research 

was unable to confirm specific equipment upgrades, based on the elimination of other possible 

explanations we believe that equipment upgrades were the most likely cause of some of the 

observed heat rate improvements. 

The EPA also reviewed the engineering studies available in the literature and selected the 

Sargent & Lundy 2009 study as the basis for our assessment of heat rate improvement potentials 

from equipment and system upgrades. We focused on some thirteen heat rate improvement 

methods discussed by Sargent & Lundy, seen in Table 2-13. We used the average of the 

estimated $/kW costs for each method to develop the cost-ranked list of heat rate improvement 

methods (lowest cost at the top, highest at the bottom) shown in Table 2-13. The first nine items 

in Table 2-13 contribute about 15 percent of the total average $/kW cost for all items. We believe 

it is reasonable to consider those nine no-cost and low-cost heat rate improvement methods as 

belonging in the category of what has been described above as best practices. The remaining four 

                                                            

24 Fleet heat rate for entire study population is 9,763; the 9,755 value is derived from the dataset that includes hourly 

temperature values.
DRAFT April 4, 2014 

30 

methods are higher cost heat rate improvement items that we believe properly fall into the 

category discussed here as upgrades. Using an average of the ranges of potential Btu 

improvements estimated by Sargent & Lundy for the four upgrade methods, upgrades, as defined 

here, could provide a 4% heat rate improvement if all were applied on an EGU that has not 

already made these upgrades. 

Table 2-13. Sargent & Lundy Heat Rate Improvement Methods 

No-Cost and Low-Cost Options 

Condenser Cleaning 

Intelligent Soot Blowers 

ESP Modification 

Boiler Feed Pump Rebuild 

Air Heater and Duct Leakage Control 

Neural Network 

SCR System Modification 

FGD System Modification 

Cooling Tower Advanced Packing 

Higher Cost Options 

Economizer Replacement 

Acid Dew Point Control 

Combined VFD and Fan 

Turbine Overhaul 

We also examined the annual heat rate trend line for each unit developed using the 

method of least squares. Using the slope of the trend line, 2002-2012, as an indicator of heat rate 

performance of an EGU, a negative slope would indicate that the heat rate has improved. The 

annual trend line incorporates performance due to operating conditions (capacity factor, 

temperature), coal rank, maintenance, reporting method changes, equipment upgrades, and other 

factors. Over 40% of units have a positive slope. This would imply that equipment maintenance 

and upgrades at a significant fraction of the study population have not been sufficient even to 

maintain the status quo. 

Combined study population results 

The EPA’s analysis finds that a total of 6% heat rate improvements for the coal study 

population can be achieved through two types of changes: best practices that have the potential 

to improve heat rate by 4% and equipment upgrades that have the potential to improve heat rate 

by 2%. 
DRAFT April 4, 2014 

31 

The best practices results are supported by the variability analysis using 11 years of 

hourly data applied to each unit. This analysis found that the top quartile of EGUs reported 

significantly lower heat rate variability than the study population average. Reducing heat rate 

variability will generally also improve heat rate performance, other factors held equal. We found 

that a 4% improvement is determined by conservatively reducing heat input by 30% of the 

difference between the reported value and p10 in each unit’s capacity factor and ambient 

temperature bins. The 30% approach is in the middle of the range of options shown in Table 2-12 

and is comparable to other approaches for measuring potential fleet heat rate improvement. For 

example, if each unit achieved heat rate performance equal to its best three-year moving average, 

the study population as a whole would post a 3.9% heat rate improvement. The best two-year 

moving average would achieve nearly a 5% improvement and the best single year over 6%. EPA 

believes that the minimum three-year moving average heat rate is a reasonable target for the 

improvement potential from applying best practices. Single year results could be due to unusual 

conditions, such as, an extended outage or weather. Using three consecutive years tends to 

smooth out the effect of equipment maintenance cycles and unusual meteorological patterns. 

The equipment upgrades results are supported by numerous studies25 and by the EPA’s 

analysis of the costs and associated improvements in heat rate that can be attributed to equipment 

and system upgrades. We considered that a 4% reduction in heat rate might be achieved on a 

coal-steam unit by applying the four higher cost upgrade actions described in Table 2-13 above. 

However, because details of current actual unit configurations are unknown, and some units may 

have applied at least some of the upgrades, we conservatively estimate the heat rate improvement 

potential for upgrades at 2%. The EPA considers the results of this study to be applicable to the 

U.S. coal-fired fleet at large since the study population of EGUs accounted for over 96% of 2012 

electric sector CO2 emissions from coal. 

Sensitivity Analysis Removing Planned or Announced EGU Retirements 

The EPA’s research found 230 EGUs that have announced they will retire before 2016.26

A sensitivity analysis was applied to the EGUs in the study population that plan to operate 

through 2015. The results are identical to the full population – both achieve a heat rate reduction 

of 4% under the 30 percent difference option described in best practices.

                                                            

25 See discussion in Table 2-3 above, and the HRI Partial Bibliography at the end of this section 26The EPA research was derived from Ventyx Velocity Suite New Entrants database (proprietary) and other sources, 
DRAFT April 4, 2014 

32 

Heat Rate Improvement – Economics 

Most of the methods that can be applied to achieve a sustained Heat Rate Improvement 

(HRI) on a coal-steam EGU will entail a capital cost. These HRI capital costs can be economic to 

incur if they yield sufficient reductions in other current or potential costs, particularly reductions 

in coal fuel cost and any cost related to CO2 emissions. For the purpose of this TSD analysis, it is 

assumed that HRI can be economic if the annualized net savings (coal cost savings plus CO2

emission cost savings minus capital cost) is positive: 

Annual Net HRI Savings = Coal Cost Savings + CO2 Emission Cost Savings – Capital Cost27

Heat Rate Improvement Capital Cost Assumption 

The 2009 Sargent & Lundy study describes numerous well known and technically proven 

HRI methods for coal-steam EGUs. The study includes an estimated min-max range of heat rate 

improvement, and the min-max range of associated capital cost for each HRI method, for units 

ranging in size from 200 MW to 900 MW. If these methods and unit sizes are combined, as 

though they were all applied on a single EGU, the following range of Sargent & Lundy estimated 

Btu reductions and associated range of capital costs are obtained: 

Combined Min-Max HRI Btu Reduction: 415-1205 Btu 

Combined Min-Max HRI Capital Cost: $40-150/kW 

EPA Assumed Combined HRI Capital Cost: $100/kW 

The wide ranges of estimated HRI Btu and costs are indicative of the wide range of real 

differences in the many details of site specific EGU designs, fuel types, age, size, ambient 

conditions, current physical condition, etc. This TSD analysis therefore assumes $100/kW as a 

representative combined HRI capital cost to achieve whatever HRI Btu reduction is possible at 

an average site. The effect of a lower HRI cost is also examined. 

Heat Rate Reduction Assumption 

The weighted average annual net heat rate of the U.S. coal-steam EGU fleet in 2020 is 

projected at 10,450 Btu/kWh in the EPA’s IPMv5.13 Base Case modeling. As indicated by the 

Sargent & Lundy estimates given above, HRI methods could possibly reduce this average coal 

fleet heat rate by about 400 to 1200 Btu/kWh, or by about 4% to 12% of the projected 2020 

                                                            

27 This TSD analysis assesses a broadly combined application of multiple HRI methods. As estimated in the 2009 

Sargent & Lundy study most HRI-related O&M costs are sufficiently small relative to the associated annualized 

capital costs, such that they do not materially affect the economics of broadly combined HRI methods. The analysis 

therefore does not consider the small economic impact of HRI-related O&M costs. 
DRAFT April 4, 2014 

33 

average, provided that all units were able to apply all of the combined HRI methods. The proviso 

is important to this analysis because the EPA expects that a significant fraction of the coal fleet 

has already applied some or many of the available HRI methods.28 

The EPA does not have sufficient site specific information to accurately estimate what 

percentage of the fleet has adopted various HRI methods, nor how effectively, and is not aware 

of any other investigator having sufficient information. HRI potential can therefore not be 

estimated at this time through analysis of the current equipment configurations of the coal steamEGU fleet. The EPA therefore analyzed 11 years of historical heat rate data and the literature on 

HRI methods, as discussed earlier in this TSD, to estimate that the U.S. coal-steam EGU fleet 

might reasonably be expected to reduce its annual average gross heat rate by about 6%. 

The EPA understands that any HRI method that reduces gross heat rate will also reduce 

net heat rate, and that some HRI methods reduce net heat rate without reducing gross heat rate. 

We expect that the HRI potential on a net output basis is somewhat greater than on a gross output 

basis, primarily through upgrades that result in reductions in auxiliary loads. For purposes of this 

TSD the EPA conservatively assumes that the coal fleet average net heat rate can be reduced by 

6%. 

Heat Rate Improvement Breakeven Economic Analysis 

Figure 2-6 presents a simple breakeven economic analysis for combined HRI methods 

using the assumptions described above, also assuming there is no CO2 emission cost that is 

reduced via HRI. 

                                                            

28 Based on the EPA informal discussions with Sargent & Lundy and other power sector engineering firms. The 

EPA has found no comprehensive data set on the extent to which specific HRI methods have already been applied at 

individual EGUs. The EPA believes that many EGU owners consider such information to be confidential. 
DRAFT April 4, 2014 

34 

Figure 2-6. HRI Breakeven Economics 

Notes: 

1. Capital cost S/MWh assumes the following: HRI capital cost = $100/kW; capital charge rate 

= 14.3%; IPM projected 2020 annual capacity factor = 78% 

2. Coal fleet average 2020 net heat rate = 10,450 Btu/kWh; heat rate reduction = 6% 

Figure 2-6 shows that the average fleet-wide savings in coal cost would become greater 

than the annualized capital cost of an average 6% reduction in heat rate when the average fleetwide coal cost exceeds about $3.25/MMBtu. For comparison, the average U.S. power sector 

delivered cost of coal in 2020 is projected in EPA’s IPMv5.13 Base Case modeling at 

$2.62/MMBtu. For different assumptions, the HRI economic breakeven point would change 

directionally as follows: 

 If the HRI capital cost were on average less than the assumed $100/kW, 6% HRI would 

then become economic at lower coal costs. For example, if the average capital cost were 

actually $75/kW, a fleet-wide 6% HRI would become economic at an average coal cost 

of about $2.50/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 2012.29 This 

sensitivity indicates that fuel cost savings alone would make it economic for some of 

those EGUs currently using high cost bituminous coals to make HRI investments. 

                                                            

29 EIA, Electricity DataTable 7.4, Average Weighted Cost of Fossil Fuels for the Electric Power Industry 2002-

2012, http://www.eia.gov/electricity/annual/html/epa_07_04.html 

0.00

0.50

1.00

1.50

2.00

2.50

3.00

1.00 2.00 3.00 4.00

$/MWh‐net

Coal Cost  $/MMBtu

Coal Cost Savings   $/MWh‐net Capital Cost  $/MWh‐net

HRI Capital Cost = $100/kW
DRAFT April 4, 2014 

35 

 At an EGU net heat rate that is higher than the IPM projected 2020 average value of 

10,450 Btu/kWh, 6% HRI could be economic at coal costs lower than the values 

mentioned above. 

 If the average heat rate reduction were only 4% instead of the assumed 6%, at a cost of 

$100/kW, average coal costs would have to exceed $4/MMBtu for 4% HRI to be 

economic fleet wide, 

 But, if the average heat rate reduction were 4% at a cost of $50/kW, HRI could become 

economic at an average coal cost of about $2.50/MMBtu. 

 If there were additional HRI savings due to avoided future CO2 emission costs, HRI 

could become economic at lower coal costs, or at higher capital costs, or at lower heat 

rate reduction percentages. 

Estimated Fleet-wide Coal EGU CO2 Reduction and Cost via HRI 

It is possible to make an order-of-magnitude estimate of the fleet-wide extent and costeffectiveness of HRI using reasonable assumptions as in the following example: 

Fleet-wide 2020 Assumptions (basis: similar to IPMv5.13 Base Case): 

 Coal fleet capacity applying combined HRI methods = 244,000 MW 

 Average CO2 emission rate = 0.976 tonne/MWh net 

 Average net heat rate = 10,450 Btu/kWh net 

 Average capacity factor = 78% 

 Pre-HRI CO2 emissions = 1.62 billion tonne/yr (calculated) 

 HRI Btu and CO2 reduction = 6% 

 HRI capital cost = $100/kW 

 Annual capital charge rate = 14.3% 

 Average coal cost = $2.62/MMBtu 

Estimated Fleet-wide Results: 

 Fleet-wide CO2 reduction via HRI = 97 million tonne/yr 

 Total HRI capital cost = $24 billion 

 Annualized HRI capital cost = $3.5 billion 

 Annual coal cost savings (cost) = $2.7 billion 
DRAFT April 4, 2014 

36 

 Annual net savings (cost) = ($0.8 billion) 

 Annual net savings (cost) of CO2 reduction = ($7.7/tonne) 

Conclusion - HRI Economics 

This necessarily simplified HRI economic analysis supports the following summary conclusions: 

 Some degree of HRI is already economic for high heat rate – high coal cost EGUs 

 If a fleet-wide average 6% HRI is technically feasible, it would also be economic on the 

basis of fuel savings alone, before consideration of the value of the associated CO2 

emission reductions, on a fleet-wide basis at today’s coal prices if the associated average 

capital cost is about $75/kW or less. 

 If a fleet-wide average 6% HRI is technically feasible, and the associated average capital 

cost is as much as $100/kW, 6% HRI could become economic on the basis of fuel 

savings alone, before consideration of the value of the associated CO2 emission 

reductions, if/when average coal prices rise to about $3.25/MMBtu (IPM projects coal at 

$2.62/MMBtu in 2020). 

 Even at a capital cost of $100/kW and an IPM projected 2020 coal price of 

$2.62/MMBtu, the fleet-wide cost of CO2 reduction via 6% HRI would be a relatively 

low $7.7/tonne. 

Thus, although there is currently some uncertainty associated with the costs of achieving a 

particular fleet-wide amount of HRI, it is clear that HRI is an available low-cost approach to CO2

reduction for existing coal-fired EGUs 

Definitions/Abbreviations

Btu British thermal unit 

capacity factor 

electricity generation expressed as a percentage of maximum 

electricity generation (i.e., actual generation / maximum potential 

generation) 

CO2 carbon dioxide 

EGU electric generating unit 

EIA Energy Information Administration 

EPA Environmental Protection Agency 

heat input amount of energy consumed in a combustion unit (e.g., boiler) 

expressed in Btu 

heat rate improvement decrease in the amount of heat input required to generate 1 kWh of 

electricity 

heat rate gross heat input required to generate 1 kWh of electricity, expressed 

in gross Btu/kWh. 

MMBtu million Btu 
DRAFT April 4, 2014 

37 

MW megawatt 

PC pulverized coal (boiler) 

RSD Relative standard deviation 

S & L report 

Sargent & Lundy engineering study on the potential heat rate 

improvement from equipment upgrades (EPA 2009 version) 

[Available at: 

http://www.epa.gov/airmarket/resource/docs/coalfired.pdf] 

start 

a startup event in which an EGU begins combusting fossil fuel and 

generates some measurable amount of electricity before ceasing fossil 

fuel combustion 

unit-year data for one EGU over a one year period 

Docket Datasets 

Name Description 

hour_QA_data.txt 2002-2012 hourly dataset 

hour_QA_regression_data.txt 2002-2012 hourly dataset for regression analysis 

units_885.txt List of study units and characteristics 

year_bin_10_50_data.txt 2002-2012 unit-year binned results at 10 – 50% difference 

options 
DRAFT April 4, 2014 

38 

HRI Partial Bibliography 

PowerEng 2002, “Heat Rate Optimization Pays Dividends,” Power Engineering, January 1, 

2002, available at http://www.power-eng.com/articles/print/volume-106/issue-1/features/heatrate-optimization-pays-dividends.html

NETL 2008, Reducing CO2 Emissions by Improving the Efficiency of the Existing Coal-fired 

Power Plant Fleet, DOE/NETL-2008/1329, July 2008 

NETL 2009, Opportunities to Improve the Efficiency of Existing Coal-fired Power Plants, 

Workshop Report, NETL July 2009, available at http://www.netl.doe.gov/energyanalyses/pubs/NETL%20Power%20Plant%20Efficiency%20Workshop%20Report%20Final.pdf

NETL 2010, Improving the Thermal Efficiency of Coal-Fired Power Plants in the United States, 

DOE/NETL Technical Workshop Report, February 2010, available at 

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

ficCoalFiredPowerPlants-TechWorkshopRpt.pdf

NETL 2010a, Improving the Efficiency of Coal-Fired Power Plants for Near Term GHG 

Emissions Reductions, DOE/NETL-2010/1411, April 2010, available at 

http://www.alrc.doe.gov/energy-analyses/refshelf/PubDetails.aspx?Action=View&PubId=307

Sargent & Lundy 2009, Coal-Fired Power Plant Heat Rate Reductions, SL-009597, Final Report, 

January 2009, available at http://www.epa.gov/airmarkets/resource/docs/coalfired.pdf

Storm 2009, “Applying the Fundamentals for Best Heat Rate Performance of Pulverized Coal 

Fueled Boilers, Storm Technologies, Inc, EPRI 2009 Heat Rate Conference, available at 

http://www.stormeng.com/pdf/EPRI2009HeatRateConference%20FINAL.pdf

NRDC 2013, Closing the Power Plant Carbon Pollution Loophole, NRDC Report R:12-11-A, 

March 2013 available at http://www.nrdc.org/air/pollution-standards/files/pollution-standardsreport.pdf

Lehigh 2009, Reducing Heat Rates Of Coal-Fired Power Plants, Lehigh Energy Update, January 

2009, available at http://www.lehigh.edu/~inenr/leu/leu_61.pdf

ESC/OnLocation, Efficient Heat Rate Benchmarks for Coal-Fired Generating Units, draft, B. 

Roberts, Economic Sciences Corporation, L Goudarzi, OnLocation, Inc., 1998, available at 

http://www.onlocationinc.com/heatratepaper.pdf

CRS 2013, Increasing the Efficiency of Existing Coal-Fired Power Plants, Congressional 

Research Service, December 2013, available at http://www.fas.org/sgp/crs/misc/R43343.pdf

Evonik/VGB 2008, “Power Plant Performance Reporting and Improvement under the Provision 

of the Indian Energy Conservation Act – Output 1.1”, Evonik/VGB 2008, available at 

http://www.emt-india.net/PowerPlantComponent/Output1.1/Output1.1.pdf

IEA 2010, Power Generation from Coal - Measuring and Reporting Efficiency Performance and 

CO2 Emissions, OECD/IEA-CIAB 2010, available at 

http://www.iea.org/ciab/papers/power_generation_from_coal.pdf

EPRI 2009, Renewed Interest in Reducing Heat Rate, EPRI Journal, Spring 2009, available at 

http://mydocs.epri.com/docs/CorporateDocuments/EPRI_Journal/2009-

Spring/1019287_Heat%20Rate.pdf
DRAFT April 4, 2014 

39 

EPRI/Korellis 2011, Identifying Ways to Improve Plant Heat Rate, Energy-Tech Magazine, 

March 2011, available at http://www.energy-tech.com/article.cfm?id=30528

EPRI 2011a , Opportunities to Enhance Electric Energy Efficiency in the Production and 

Delivery of Electricity, EPRI Technical Report 1024651, November 2011, available at 

http://www.google.com/url?sa=t&rct=j&q=&esrc=s&frm=1&source=web&cd=1&ved=0CCsQF

jAA&url=http%3A%2F%2Fwww.pserc.wisc.edu%2Fdocuments%2Fpublications%2Fspecial_in

terest_publications%2FEPRI_Electricity_Use_Report_Final_1024651.pdf&ei=Qo9yUvmwMY

Xb4AOZz4GYAw&usg=AFQjCNElzekbtoSNCR5SKFwkfbKx83p0Uw&bvm=bv.55819444,d.

dmg

RFF 2013, Regulating Greenhouse Gases from Coal Power Plants under the Clean Air Act, RFF 

DP 13-05, February 2013, available at http://www.rff.org/RFF/documents/RFF-DP-13-05.pdf
DRAFT April 4, 2014 

1 

Chapter 6: Fuel Switching 

Coal-to-Natural Gas Switching 

Introduction 

Firing natural gas in a boiler designed for coal-fired generation is one approach to reducing the 

output-based CO2 emissions rate (lbs/MWh) in these boilers. The CO2 emission rate is reduced 

when natural gas is substituted for coal because the gas has a much higher percentage of 

hydrogen and a lower percentage of carbon than the coal it replaces. When quantities of gas and 

coal are burned with oxygen from air to produce the same amounts of heat, the higher hydrogen 

content of natural gas produces more water vapor (H2O) than coal, but far less CO2. 

The discussion below focuses solely on the conversion of an existing coal-fired boiler to burn 

natural gas instead of, or along with, coal. There are other technical options for gas substitution 

in an existing coal-steam EGU that are not examined in any detail here. They include: 

 Repowering an existing coal EGU by providing heat input to the boiler from the exhaust 

of a newly installed gas turbine generator; and, 

 Gasification of coal, producing substitute natural gas (SNG) that provides heat input to 

the existing coal-fired boiler. 

These other options have higher capital cost and thus would not be as economic as the direct 

substitution of natural gas in an existing coal boiler, for reasons that will become apparent in this 

analysis. 

This chapter evaluates the cost-effectiveness of widespread adoption of coal-to-gas switching at 

a national level for the purpose of setting CO2 emissions goals consistently in each state. 

Description of Technology 

 Engineering Considerations 

Most existing coal-fired EGU boilers can be modified to switch to 100% gas input, or to co-fire 

gas with coal in any desired proportion. This transition typically requires at least some plant 

modifications and might have some negative impact on the efficiency of the unit as described 

later in this chapter. 
DRAFT April 4, 2014 

2 

A conversion from coal to gas firing first requires either an existing natural gas delivery system 

to the boiler or the installation of a new gas pipeline to serve the boiler. While it is sometimes 

assumed that a need to install a new gas pipeline would render the conversion uneconomic, this 

analysis will show that the cost of a new gas pipeline is not likely to be the determining factor for 

the project’s economic merit, given the significance of the change to the cost of fuel for 

generation from the converted boiler. 

Conversion to natural gas firing in a coal-fired boiler typically involves installation of new gas 

burners and supply piping, modifications to combustion air ducts and control dampers, and 

possibly modifications to the boiler’s steam superheater, reheater, and economizer heating 

surfaces that transfer heat from the hot flue gas exiting the boiler furnace. The conversion may 

also involve some modification of downstream air pollution emission control equipment. 

Engineering studies are performed to assess changes in furnace heat absorption and exit gas 

temperature; material changes affecting heat transfer surfaces; the need for sizing of flue gas 

recirculation fans; and operational changes to sootblowers, spray flows, air heaters, and emission 

controls. 

Whether co-firing with coal or switching completely to natural gas, boilers will become less 

efficient due to the high hydrogen content of natural gas. When combusted, the additional 

hydrogen yields increased moisture content (water vapor) in the flue gas. The increased 

moisture content, in turn, results in additional heat lost up the stack instead of being directed 

towards electricity generation. Additionally, depending on the design of the boiler and extent of 

modifications, some boilers may incur some derate (reduction in generating capacity) in order to 

maintain steam temperatures at or within design limits, or for other technical reasons. 

Even with a decrease in boiler efficiency, the overall net output efficiency of a coal-steam boiler 

EGU that switches from coal to natural gas firing may change only slightly, depending on how 

much auxiliary load is converted to net output by avoiding the need to run coal pulverizers, 

conveyors, ash sluice pumps, and relevant air pollution control equipment (e.g., PM and SO2

controls). 

Fuel Considerations 

Delivery of natural gas via pipeline is critical for conversion of a coal-fired boiler to a gas-fired 

boiler. Some coal boilers are connected to the natural gas pipeline network for purposes of using 
DRAFT April 4, 2014 

3 

gas as a startup fuel, or are located at facilities with onsite gas-fired generators. These boilers are 

likely able to co-fire to some degree with gas (at least 10% total output1) without constructing 

additional gas pipeline capacity. For purposes of this analysis, the EPA conservatively assumed 

that gas use of 10% or greater at these boilers, or any gas use at boilers without an existing gas 

pipeline, would require construction of additional pipeline capacity. 

Unlike coal, natural gas cannot be stored in quantities sufficient for sustained utilization on site. 

To the extent that firm (uninterruptible) gas supply is contractually unavailable or costprohibitive, any potential interruption in gas supply could impact the ability of the unit to 

continue operating without increasing its CO2 emissions rate (since it would likely need to 

substitute more CO2-intensive fuel for the unavailable natural gas). Additionally, for boilers that 

switch to 100% gas, interruption in gas impacts the ability of the unit to continue generating at 

all if gas is unavailable. For these reasons, an EGU switching to a large percentage of gas use 

may elect to install more than one new gas supply pipeline from separate sources. Although the 

EPA assumes the addition of one gas pipeline in the simplified cost analysis presented below, it 

will be seen that pipeline cost will generally not be the main driver of economic feasibility. 

Cost and Performance Impacts of Coal-to-Gas Switching 

The analysis described in this section presents a hypothetical conversion of a boiler from burning 

100% coal to burning varying proportions of gas (10%, 50%, and 100%). The capital cost of 

modifying a coal boiler to switch to natural gas includes the new gas burners and piping, 

combustion air ductwork and control damper modifications, air heater upgrades, gas 

recirculating fans, control systems modifications, and other site-specific modifications, as well as 

any pipeline installation costs that would be necessary to supply the unit’s assumed level of gas 

combustion following the conversion. 

For this analysis, the EPA assumes capital costs for pulverized coal (PC) and cyclone boiler 

modifications are as follows2

: 

$/kW = 267*(75/MW)0.35 (pulverized coal) 

                                                            

1 Based on assumed use of Class 1 igniters (10% of burner capacity) as defined in NFPA 85 Boiler and Combustion

Systems Hazards Code. 2 EPA assumptions on costing and performance associated with coal‐to‐gas conversion and pipeline additions in

this analysis are generally consistent with assumptions presented and discussed in EPA’s power sector modeling

documentation, Chapter 5.7, at: http://www.epa.gov/airmarkets/progsregs/epa‐ipm/docs/v513/Chapter_5.pdf
DRAFT April 4, 2014 

4 

$/kW = 374*(75/MW)0.35 (cyclone) 

Based on the above formula, a 500 MW pulverized coal unit would have a capital cost of 

$137/kW to convert the boiler such that it could burn any proportion of natural gas. For this 

illustrative example, to support 100% gas combustion we assume that a 50-mile gas pipeline3 at 

$50 million, 4 or $100/kW for a 500 MW unit, is also required, which raises the unit’s total 

capital cost for conversion to $237/kW. Black & Veatch also used a similar cost level in a recent 

case study.5

 At a 14.3% capital charge rate6 and 75% annual capacity factor, the total capital cost 

in this example equates to an annualized capital cost of about $5/MWh. This $/MWh capital cost 

is relatively insignificant compared to the increase in fuel cost discussed later. 

Due to a reduced need for operators, maintenance materials, and maintenance staff, fixed O&M 

costs are reduced by 33% as a result of switching from coal to 100% gas. Similarly, variable 

O&M costs are reduced by 25% due to reduced waste disposal, reduced auxiliary power 

requirement, and miscellaneous other costs. 

EPA also assumed for this analysis that there would be no derate in the net EGU output, and 

estimated that the impact on net heat rate for an average unit would be a 3% increase for a switch 

from coal to 100% natural gas firing. The assumed 3% increase in net heat rate is conservative 

compared to the 2% assumption used by Black & Veatch in their previously mentioned case 

study. 

Cost of Fuel 

For this analysis, the EPA uses base case projections for delivered gas prices that are about 

double projected delivered coal prices on average ($2.62/MMBTU for coal, $5.36/MMBTU for 

                                                            

3 Based on EPA analysis, the majority of existing coal units would require less than 50 miles of new gas pipelines to

switch fuels from coal to 100% natural gas.  See Chapter 5 and Table 5‐22 of Documentation for EPA Base Case

v.5.13 Using the Integrated Planning Model, available at: http://www.epa.gov/airmarkets/progsregs/epa‐

ipm/BaseCasev513.html

4 For those plants that require additional pipeline capacity, the average capital cost of constructing new pipelines is

assumed to be approximately $1 million per mile of pipeline built, which is consistent with assumptions used in

EPA’s IPM modeling. 5 A Case Study on Coal to Natural Gas Fuel Switch, Black & Veatch, Power‐Gen International, December 2012,

available at http://bv.com/redirects . 6 Capital charge rate at 14.3% is the average of the regulated utility and unregulated merchant rates as used in

IPMv5.13 for environmental retrofits having a 15 year book life.  
DRAFT April 4, 2014 

5 

gas).7

 As a result, the fuel cost for a typical converted boiler burning 100% gas is expected to be 

at least double its prior fuel cost on an output basis as well ($27/MWh for coal, $57/MWh for 

gas).8,9 Compared to the estimated $5/MWh capital cost impact presented above, a $30/MWh 

increase in fuel cost would make the difference in fuel costs the most significant driver of project 

economics when switching from coal to gas in a coal boiler.10 This difference would increase 

with higher gas prices, which would be projected to result from an increase in overall gas 

demand caused by widespread adoption of gas co-firing. 

Emission Reduction Potential 

The CO2 reduction potential is directly related to the amount of gas co-fired, and is due largely to 

the different carbon intensities of each fuel. More reductions in CO2 rate are achieved at higher 

levels of gas co-firing as shown in Table 6-1. At 10% gas co-firing, the net emissions rate 

(lbs/MWh net) of a typical unit would decrease by approximately 4%. At 100% gas co-firing, 

the net emissions rate (lbs/MWh net) of a typical unit would decrease by approximately 40%. 

Table 6-1. CO2 Rates at Various Levels of Natural Gas Co-Firing 

Case Heat Rate CO2 Rate

(lbs/MWh net)

Reduction in CO2 Rate from 100% Coal

(lbs/MWh net)

100% Coal 10,340 2,108 N/A

10% Gas 10,370 2,021 4%

50% Gas 10,490 1,673 21%

100% Gas 10,640 1,239 41%

In addition to reducing CO2 emissions, natural gas co-firing at a coal-fired steam EGU will 

generally also reduce criteria air pollution. Reducing CO2 and criteria air pollution will result in 

                                                            

7 EPA Base Case 5.13, projections for 2020    8 This estimated fuel cost also accounts for the decrease in efficiency that results from switching from coal to gas in

a boiler, as well as the decrease in parasitic power consumption. 9 Combusting natural gas using combined‐cycle turbine technology can remain economically attractive

notwithstanding these types of fuel price differentials because combined cycle turbine technology converts a

substantially higher share of the fuel’s heat input into electricity output as compared to boiler technology.  The

$/MWh impact of a higher gas price in that instance is significantly mitigated by higher MWh output produced for

a given amount of heat input from the fuel purchased. 10 This demonstration assumes that the converting boiler in question remains a “price taker” in the fuel

marketplace, such that the projected gas and coal prices would be unaffected by this hypothetical unit’s potential

decision to convert.  However, if enough other units might be expected to make similar conversions, the aggregate

increased demand for natural gas would be likely to further increase the price differential between coal and gas,

making fuel costs an even more influential factor in the evaluation of such a project’s economic merit.
DRAFT April 4, 2014 

6 

climate benefits and human health co-benefits. The impacts of these pollutants on the 

environment and health are discussed in detail in Chapter 5 of the RIA for this proposed rule. 

For this analysis, EPA estimated the PM2.5-related human health co-benefits of SO2, NOX, and 

direct-PM2.5 emission reductions attributable to a range of natural gas co-firing levels at an 

illustrative coal steam unit burning bituminous coal in 2020.11 The estimated monetized cobenefits do not include climate benefits or health effects from direct exposure to NO2, SO2, and 

HAP; ecosystem effects; or visibility impairment. Only the unit-level emissions of SO2, NOX and 

direct-PM2.5 are considered in this illustrative exercise. Additionally, emissions from the 

extraction and transport of the fuels used by these technologies are not considered. Furthermore, 

there may be differences in upstream greenhouse gas emissions (in particular, methane) from 

different technologies but those were not quantified for this assessment. The estimated avoided 

emissions under 10% gas co-firing and a 100% switch to gas are presented Table 6-2. 

Table 6-2. Avoided Emissions at Various Levels of Co-Firing, based on Illustrative Unit 

(lbs/MWh net) 

 

10% 

Gas 

100% 

Gas 

SO2 0.3 3.1 

NOX 0.2 2.04 

PM2.5 0.02 0.2 

To estimate human health co-benefits for this illustrative coal steam unit, the EPA used PM2.5-

related benefit-per-ton estimates for SO2, NOX, and direct-PM2.5 emission reductions described 

in detail in Chapter 5 of the RIA for this proposal. To estimate the benefits associated with cofiring, we determine the emission reductions for co-firing in Table 6-2 and apply the 2020 social 

benefit values discussed in Chapter 5 of the RIA for this proposal. Specifically, we multiply the 

reduction in SO2, NOX, and direct-PM2.5 emissions by the PM2.5-related benefit per-ton estimates, 

and add those values to get a measure of 2020 benefits. Table 6-3 shows the PM2.5-related 

benefits expected based on the estimated emission reductions that would occur in this illustrative 

example. These estimates are purely illustrative as the EPA does not assert a specific location for 

the illustrative electricity generation technologies and is therefore unable to specifically 

                                                            

11 The illustrative unit in this analysis was assumed to be a 500 MW coal‐steam unit burning bituminous coal with a

heat rate of 10,339 btu/kWh (net) operating at 75% capacity factor.  Furthermore, this unit was assumed to

operate a wet scrubber, cold‐side ESP, and SNCR.
DRAFT April 4, 2014 

7 

determine the population that would be affected by their emissions. Therefore, the benefits for 

any specific unit can be different than the estimates shown here. 

Table 6-3. Rounded PM2.5-related Co-benefits ($/MWh net) of Gas Co-firing (2011$) 

Health Co‐benefit Discount Rate

   3% Discount Rate 7% Discount Rate

Gas Co‐firing 10% $6.5 to $15 $5.9 to $13

Gas Co‐firing 100% $67 to $150 $61 to $140

Note: All estimates are rounded to two significant figures. Co‐benefits are based on national benefit‐per‐ton estimates for directly emitted

PM2.5 and PM2.5 precursors, SO2 and NOX. It is important to note that the monetized health co‐benefits do not include reduced health effects

from ozone or direct exposure to NO2, SO2, and HAP; ecosystem effects; or visibility impairment. Emissions of directly emitted particles are

disaggregated into EC+OC or crustal components using the method discussed in Appendix.12 5A of the RIA for this proposal. The health co‐

benefits reflect the sum of the PM2.5 co‐benefits and reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) to

Lepeule et al. (2012)).

The precise incremental health co-benefits associated with lower emissions would depend 

primarily on the location of the co-firing unit, the specific types of coals that natural gas would 

replace, and the pollution controls installed on that unit. This illustrative assessment is unable to 

account for these characteristics. However, these factors will not change the qualitative 

conclusion. There will always be incremental human health co-benefits associated with co-firing 

natural gas in an existing coal steam boiler, independent of the location, coal type, and operating 

pollution controls. 

A related beneficial use of natural gas in existing coal boilers can be via gas reburning, a NOx 

reduction technology.13 Gas reburning involves firing natural gas (between 10 and 25% of total 

heat input) above the primary combustion zone in the boiler furnace. This upper-level firing 

creates a slightly fuel-rich zone. NOx produced in the primary zone of the furnace is "reburned" 

in this zone and converted to molecular nitrogen and other reduced nitrogenous species. Overfire 

air is injected downstream of the reburn zone to burn out the remaining combustibles and convert 

                                                            

12 Krewski D.; M. Jerrett; R.T. Burnett; R. Ma; E. Hughes; Y. Shi, et al. 2009. Extended Follow‐Up and Spatial Analysis

of the American Cancer Society Study Linking Particulate Air Pollution and Mortality. HEI Research Report, 140,

Health Effects Institute, Boston, MA.

Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 2012. “Chronic Exposure to Fine Particles and Mortality: An Extended

Follow‐Up of the Harvard Six Cities Study from 1974 to 2009.” Environmental Health Perspectives, July, 120(7):965‐

70.

13 DOE/NETL 2001, Evaluation of Gas Reburning and Low‐NOx Burners on a Wall‐Fired Boiler, DOE/NETL‐

2001/1143, February 2001, available at

http://www.netl.doe.gov/File%20Library/Research/Coal/major%20demonstrations/cctdp/Round3/GRLNBPPA.pdf
DRAFT April 4, 2014 

8 

the reduced nitrogenous species to molecular nitrogen. The heat input from gas would 

approximately substitute for a similar heat input from coal, thus reducing CO2 and other coal 

emissions in a manner similar to gas co-firing as discussed above. 

Cost of Reductions and Cost Effectiveness 

This analysis examines the average $/tonne14 cost of avoided CO2 that results from applying a 

range of natural gas co-firing levels to a typical baseload coal boiler. We capture the capital 

costs of boiler modifications and new pipeline construction (assuming 50 miles of new 

pipeline),15 decreased FOM and VOM costs, and incremental fuel costs (based on IPMv5.13 

Base Case average delivered fuel price projections for coal and gas in 2020). For a typical coal 

boiler at current base case fuel prices, the average cost of avoided CO2 ranges from $83/tonne for 

100% gas switch to $150/tonne for co-firing at 10% (see Table 6-4). 

Table 6-4. Average Cost of Avoided CO2 and CO2 Emission Rate Reductions from 100% Coal at 

Various Levels of Natural Gas Co-Firing at Base Case Projected Gas Price ($5.36/MMBtu) 

Case Average Cost of Avoided CO2

($/tonne)

Change in CO2 Rate from 100% Coal

(lbs/MWh net)

100% Coal N/A N/A

10% Gas 150 4%

50% Gas 91 21%

100% Gas 83 41%

Note: Based on a typical 500 MW bituminous coal steam unit operating at 75% capacity factor.  Assumes

construction of new 50‐mile pipeline. EPA estimated reduced total capital costs for the 50% and 10% gas cases; for

example, total capital cost for 10% gas was estimated to be about one‐half of the capital costs for the 100% gas

case.

However, widespread adoption of gas co-firing would increase overall gas demand and place 

upward pressure on the natural gas price, which would consequently increase the average cost of 

avoided CO2 of a potential boiler conversion. 

   

Conclusion 

                                                            

14 This document uses “tonne” to refer to a metric tonne.  All control costs in this analysis are presented in dollars

per metric tonne, or “$/tonne.” 15 Based on EPA analysis, the majority of existing coal units would require less than 50 miles of new gas pipelines to

switch fuels from coal to 100% natural gas.  See Chapter 5 and Table 5‐22 of Documentation for EPA Base Case

v.5.13 Using the Integrated Planning Model, available at: http://www.epa.gov/airmarkets/progsregs/epa‐

ipm/BaseCasev513.html
DRAFT April 4, 2014 

9 

Switching from coal to gas is a relatively costly approach to CO2 reductions at existing coal 

steam boilers when compared to other measures such as heat rate improvements and re-dispatch 

of generation supply to other existing capacity with lower CO2 emission rates. Moreover, this 

analysis shows that coal-to-gas conversion of an existing boiler is less efficient than constructing 

a new natural gas combined cycle (NGCC) turbine in its place. For example, replacing the coal 

steam plant discussed above with a new NGCC facility would reduce the net CO2 emission rate 

of the generating capacity by 62% at a cost of about $50/tonne of avoided CO2 under the base 

case projected gas price and about $81/tonne of avoided CO2 at a future gas price 50% higher 

than the base case projection. [INSERT CROSS-REFERENCE TO LOCATION IN RULE 

MATERIALS WHERE WE EXPLAIN WHY WE ARE NOT CONSIDERING NEW NGCC 

POTENTIAL TO REPLACE EXISTING COAL AS A REDUCTION MEASURE FOR 

CRAFTING STATE GOALS.] 

The EPA is considering cost-effectiveness at a national level for the purpose of setting emissions 

goals consistently in each state. While this analysis suggests that cost-effective reductions of 

CO2 are not available on a national basis from widespread adoption of natural gas co-firing, it 

does not preclude the potential for individual EGUs to utilize co-firing as a way to reduce CO2

and other emissions, nor does it preclude states from factoring in that unit-level potential into the 

design of state plans for compliance with the 111(d) standard. EPA notes that there are utilities 

that see merit in converting some existing coal units to burn 100% gas, and several are currently 

doing so.16,17

   

                                                            

16 Reuters 2014, “Southern to repower three Alabama coal power plants with natgas,” Reuters U.S. Edition,

January 16, 2014  , available at http://www.reuters.com/article/2014/01/16/utilities‐southern‐alabama‐

idUSL2N0KP1WA20140116

17 Dominion 2012, “Dominion Virginia Power Proposes To Convert Bremo Power Station From Coal To Natural

Gas,” Dominion News, September 5, 2012, available at http://dom.mediaroom.com/2012‐09‐05‐Dominion‐

Virginia‐Power‐Proposes‐To‐Convert‐Bremo‐Power‐Station‐From‐Coal‐To‐Natural‐Gas
DRAFT April 4, 2014 

10 

Biomass Co-firing 

Introduction 

Co-firing biomass in existing boilers designed for coal-fired generation is another approach to 

potentially reduce the output-based CO2 emissions rate (lbs/MWh) of these boilers. In the 

analysis presented in this technical support document, the physical CO2 emissions rate at the 

boiler stack could increase or decrease, depending on the amount of coal energy replaced by 

biomass energy and differences in the properties of a selected biomass and the coal it replaces.18 

There are many possible combinations of coals and biomass types that could be co-fired. Sitespecific economics and accessibility would determine which combinations might actually be 

feasible. This TSD analysis does not attempt to estimate an economically feasible national 

average increase or decrease in CO2 emission rate via biomass co-firing. Instead, this analysis 

simply employs one reasonably representative case to evaluate the cost effectiveness of biomass 

energy substitution in reducing the physical CO2 emission rate based only on the CO2 coming 

from coal. This analysis indicates that while the co-firing of biomass with coal is technically 

feasible as a means of reducing the coal-based CO2 emission rate due to the substitution of 

biomass for coal, it has limited economic feasibility due to the generally higher cost of energy 

from biomass as compared to coal. This general finding largely explains the very limited amount 

of biomass co-firing currently practiced in the U.S. It is also consistent with findings by others, 

including a study by the State of Maryland19 that concluded as follows: 

“Due to the higher cost of biomass fuels when compared to coal, cofiring with biomass 

will lead to an increase in fuel costs. Without consideration for any environmental 

benefits, it is unlikely that any Maryland coal-fired facility would make the investments 

required to cofire with a more expensive and less efficient fuel.” 

Based on the basic analysis of the cost effectiveness of biomass energy substitution in reducing 

the physical CO2 emission rate based only on the CO2 coming from coal presented below, the 

                                                            

18 Fuel properties particularly affecting relative CO2 emission rates are: higher heating value, carbon and hydrogen

contents, and as‐fired moisture content.    19 The Potential for Biomass Cofiring in Maryland, Maryland Department of Natural Resources, March 2006, (pg 53)

http://esm.versar.com/pprp/bibliography/PPES_06_02/PPES_06_02.pdf
DRAFT April 4, 2014 

11 

EPA concludes in this TSD that biomass co-firing would not be a cost-effective measure on 

which to base state goals. 20 

This TSD’s analysis indicates that while the co-firing of biomass with coal is technically 

feasible, in some cases it can yield increases in the stack emission rate of CO2 (lb/MWh) and has 

limited economic feasibility given the delivered cost of available biomass versus the cost of coal. 

Description of Technology 

Engineering/Economic Considerations 

The technical feasibility of biomass co-firing in existing coal-fired boilers has been thoroughly 

investigated in many research and engineering studies, as well as in test burns at coal power 

plants in the U.S. and globally.21 It has been demonstrated that the boiler and related systems of 

almost any existing coal-fired EGU can accept or be modified to support co-firing of at least 

some small percentage of biomass. In some cases, major modifications can be made to support a 

switch to 100% biomass. 

A decision to actually modify an existing coal-fired boiler for biomass co-firing at any 

percentage level depends on numerous technical and economic factors, including reliable 

availability of suitable biomass at an economic cost; adequate onsite space for biomass receiving, 

storage, preparation, and handling systems; potential corrosive effects of biomass ash in the 

boiler furnace; potential impacts of co-firing on boiler efficiency even at low biomass 

percentages, and the likely reduction (derate) in unit generating output at very high biomass 

percentages. 

                                                            

20 This analysis does not include evaluation of stack biogenic CO2 emissions relative to the net landscape and

process‐related carbon fluxes associated with the production and use of the biogenic feedstocks combusted. Issues

related to methods for assessing biogenic CO 2 emissions from stationary sources are currently being evaluated by

the EPA. In general, the overall net atmospheric contribution of CO 2 resulting from the use of a biogenic feedstock

by a stationary source, such as an EGU, will ultimately depend on the stationary source process and the type of

feedstock used, as well as the conditions under which that feedstock is grown and harvested. In September 2011,

the EPA submitted a draft Accounting Framework to the Science Advisory Board (SAB) Biogenic Carbon Emissions

(BCE) Panel for peer review. The SAB BCE Panel delivered its Peer Review Advisory to the EPA on September 28,

2012. In its Advisory, the SAB recommended revisions to the EPA's proposed accounting approach, and also noted

that biomass cannot be considered carbon neutral a priori, without an evaluation of the carbon cycle effects

related to the use of the type of biomass being considered.   21 See Partial Bibliography – Biomass Co‐firing at end of this section.
DRAFT April 4, 2014 

12 

There are considerable physical differences between coal and biomass that will generally limit 

the extent to which biomass can be reasonably used to replace coal in a boiler. For example, 

compared to most coals, many solid biomass fuels have both a significantly higher as-fired 

moisture content and a significantly lower heating value per unit of weight. Most solid biomass 

fuels are also significantly less dense than most coals. For example, a typical biomass might have 

twice the moisture, half the heating value, and less than half the density of coal.22 Important 

consequences of these physical differences are that the weight of biomass needed to provide a 

given amount of heat energy could be twice the weight of the coal it replaces, and the volume 

(cubic feet) of biomass needed could be four-to-eight times the volume of coal replaced. 

Biomass requires space for storage after delivery to a facility, and the length of time that the 

biogenic material would remain on site prior to use can differ. For example, wood chips could 

be delivered year-round while crop residue delivery would follow specific seasons in which the 

crop was grown. As noted above, the four-fold or greater increase in volume occupied by 

biomass relative to coal means that the necessary additional storage space could be large. Stored 

biomass can be at even greater risk of spontaneous combustion than stored coal; this may limit 

the safe height of biomass piles and further increase storage area requirements.23

The volumetric differences alone can have other unexpected consequences. For this analysis, 

experienced EPA engineering staff estimated that a 500 MW baseload coal plant co-firing 10% 

biomass and receiving biomass deliveries 10 hours per day and 5 days per week would require a 

20-ton truck delivery to the plant every 10 minutes, in addition to the ongoing coal deliveries. 

Limiting traffic issues may arise in some situations. Also, because of the low energy density of 

biomass and its relatively higher transportation cost per unit of delivered energy, it may only be 

economically viable to transport biomass a limited distance from where it is grown. This could 

limit the both the percentage of biomass co-firing in a single boiler and the maximum MW 

output from biomass at a single site. 

The relatively higher moisture content and lower heat content of biomass reduces boiler 

efficiency, and typically requires a derating in unit generation at very high co-firing percentages 

as furnace volume and boiler fan capacities become inadequate. 

                                                            

22 Biomass Energy Data Book‐ Edition 4, October 2012, DOE‐EERE‐ORNL,  http://cta.ornl.gov/bedb/index.shtml 23 Properties of Wood Waste Stored for Energy Production, Purdue University, 2011,

http://www.extension.purdue.edu/extmedia/ID/ID‐421‐W.pdf  
DRAFT April 4, 2014 

13 

For all of the above reasons, the EPA assumed for this analysis that coal-steam EGU boilers will 

generally only co-fire with biomass to a limited degree. While the actual level at which any 

plant can co-fire with biomass is highly site-specific, this analysis adopts the assumption used in 

EPA’s fleet wide IPM modeling of the electric power sector: a reasonable average limit on 

biomass co-firing is up to 10% on any single boiler, not to exceed 50 MW total biomass powered 

output at an individual plant site. This amount of co-firing has been used as representative 

practical limit in other studies as well.24 

Costs and Performance Impacts of Retrofitted Biomass Co-firing 

For this analysis the EPA adopted capital and O&M costs, and performance impacts for 

retrofitted biomass co-firing capability that are approximately representative of EPA assumptions 

used in its IPM modeling and discussed in the documentation for IPM v.5.13.25

EPA estimated that the capital cost to install 50 MW of biomass co-firing capability would be at 

least $10 million.26 As applied to a 500 MW coal unit, the minimum cost of this 10% co-firing 

capability would then be $20/kW. Fixed O&M cost was estimated by EPA engineering staff to 

be 10% greater than with coal alone, and variable O&M cost was estimated to remain 

unchanged. 

The heat rate impact (Btu/kWh) of 10% biomass co-firing as estimated by EPA engineering staff 

for this analysis was an increase of slightly more than 1% compared to coal alone. At low 

biomass cofiring rates, this factor slightly affects calculated biomass fuel consumption and any 

associated CO2 emission from biomass. 

Cost of Fuel 

For this analysis, the EPA uses a delivered biomass cost of $4/MMBtu, representative of 

delivered woody crops grown specifically for energy-generating combustion,27 and roughly 50% 

                                                            

24 The Potential for Biomass Cofiring in Maryland, Maryland Department of Natural Resources, March 2006,

http://esm.versar.com/pprp/bibliography/PPES_06_02/PPES_06_02.pdf 25 See Sec 5.3, pg 5‐19 at: http://www.epa.gov/airmarkets/progsregs/epa‐ipm/docs/v513/Chapter_5.pdf 26 Generally consistent with EPA assumptions in IPM modeling; also see the following source using the same

retrofit capital cost assumption: Cofiring Biomass and Coal for Fossil Fuel Reduction and Other Benefits – Status of

North American Facilities in 2010, USDA, August 2012, http://www.fs.fed.us/pnw/pubs/pnw_gtr867.pdf

27 Average biomass price as projected by EPA modeling in IPMv5.13 Base Case
DRAFT April 4, 2014 

14 

greater than IPM projected 2020 average delivered coal costs.28 This analysis also considers a 

sensitivity scenario assuming a higher $6/MMBtu biomass price. 

The EPA recognizes that the cost of biomass is highly site-specific, and in some cases could be 

largely comprised of collection and transportation cost (as is the case for opportunity fuels with 

little to no other market value). The transportation component depends primarily on the distance 

that biomass needs to be transported. For example, the EPA engineering staff estimate that for a 

one-way distance of 50 miles with a 20-ton semi-trailer truck, transportation costs could be $10-

20/ton. For biomass at a total delivered price of $4/MMBtu with an indicative heating value of 

5,000 Btu/lb (higher heating value (HHV) basis), transportation cost in this example case could 

account for 25-50 percent of the total delivered biomass cost. In any case, it is the total delivered 

price of biomass on a $/MMBtu basis that will primarily determine the economic feasibility of 

biomass co-firing. 

Emission Reduction Potential 

The CO2 reduction potential of biomass co-firing is directly related to the amount and type of 

biomass co-fired and is due to the difference in heating value, moisture content and 

hydrogen/carbon ratios29 for a selected biomass fuel compared to the particular coal it replaces. 

The types of biomass typically available to EGUs in the United States include woody-based 

feedstocks such as wood chips, forest industry byproducts, and to a lesser degree agricultural 

crop residues, as well as emerging dedicated energy crops such as switchgrass and short-rotation 

woody crops.30 In general, when comparing coal-only versus co-firing coal with biomass, cofiring may result in either an increase or decrease in the stack CO2 emission rate. 

Cost of Reductions and Cost Effectiveness 

In order to evaluate cost-effectiveness of potential reductions, the EPA first estimated the cost of 

avoided coal CO2 emissions in a hypothetical scenario where biomass CO2 emissions are not 

included in total stack CO2 emissions (in effect, biogenic CO2 emissions are subtracted from 

                                                            

28 EIA, Electric Power Annual 2012 – Electricity (Table 7.4)

http://www.eia.gov/electricity/annual/html/epa_07_04.html 29 IFRF Combustion Handbook, Combustion File No. 23, What is Biomass? (Van Krevelen Diagram),

http://www.handbook.ifrf.net/handbook/cf.html?id=23 30 Biomass Combined Heat and Power Catalog of Technologies, U.S. EPA, September 2007,  

http://www.epa.gov/chp/documents/biomass_chp_catalog.pdf
DRAFT April 4, 2014 

15 

total CO2 emissions measured at the stack). The estimated results presented below are based on 

a reasonably representative case using a baseload bituminous coal-fired boiler with a net heat 

rate of 10,340 btu/kWh that shifts from 100% bituminous coal to 90% coal and 10% biomass 

(assuming fuel prices of $2.62/MMBtu for coal in 2020 as projected in IPMv5.13 Base Case and 

$4/MMBtu for biomass as explained above). When biogenic stack emissions are not counted as 

part of total emissions, the cost of avoided CO2 for a “typical” baseload coal boiler co-firing 10% 

biomass is $30/tonne. This estimated cost of avoided coal CO2 emissions would increase if CO2

emissions from the co-fired biomass were included. At higher delivered fuel price differentials, 

the cost of avoided coal CO2 emissions would increase (for example, at a biomass price of 

$6/MMBtu, cost of avoided CO2 is $80/tonne if CO2 emissions from biomass are not counted). 

Conclusion 

Replacing some coal with low levels of biomass co-firing may result in stack CO2 emission 

increases.31 Even if biogenic CO2 emissions are not counted as part of stack emissions, biomass 

co-firing is a relatively costly approach to CO2 reductions at existing coal steam boilers when 

compared to other measures such as heat rate improvements and re-dispatch of generation supply 

to other existing capacity with lower CO2 emission rates. 

The EPA is considering cost-effectiveness at a national level for the purpose of setting emissions 

goals consistently in each state. While this analysis concludes that cost-effective reductions of 

CO2 are not available on a national basis from widespread adoption of biomass co-firing, it does 

not preclude the potential for individual EGUs to utilize co-firing as a way to reduce overall CO2

emissions, nor does it preclude states from factoring in that unit-level potential into the design of 

state plans for compliance with the 111(d) standard.32 

Partial Bibliography for Technical Feasibility of Biomass Co-firing 

(a) Briggs, J. and J. M. Adams, Biomass Combustion Options for Steam Generation, Presented at 

Power-Gen 97, Dallas, TX, December 9 – 11, 1997. 

                                                            

31 Depending on biogenic feedstocks used and whether or not an assessment system is applied that evaluates

biogenic CO2 emissions from the stack in relation to the terrestrial carbon cycling associated with the production

and use of that biogenic feedstock. 32 EPA notes that states will need to consider any future EPA finding regarding an assessment framework that

considers carbon fluxes on the biogenic feedstock production landscape applied when evaluating net stack CO2

emissions from biomass co‐firing.
DRAFT April 4, 2014 

16 

(b) Grusha, J and S. Woldehanna, K. McCarthy, and G. Heinz, Long Term Results from the First 

US Low NOx Conversion of a Tangential Lignite Fired Unit, presented at 24th International 

Technical Conference on Coal & Fuel Systems, Clearwater, FL., March 8 – 11, 1999. 

(c) EPRI, Biomass Co-firing: Field Test Results: Summary of Results of the Bailly and Seward 

Demonstrations, Palo Alto, CA, supported by U.S. Department of Energy Division of Energy 

Efficiency and Renewable Energy, Washington D.C.; U.S. Department of Energy Division 

Federal Energy Technology Center, Pittsburgh PA; Northern Indiana Public Service Company, 

Merrillville, IN; and GPU Generation, Inc., Johnstown, PA: 1999. TR-113903. 

(d) Laux S., J. Grusha, and D. Tillman, Co-firing of Biomass and Opportunity Fuels in Low NOx 

Burners, PowerGen 2000 - Orlando, FL 

(e) Tillman, D. A., Co-firing Biomass for Greenhouse Gas Mitigation, presented at Power-Gen 

99, New Orleans, LA, November 30 – December 1, 1999. 

(f) Tillman, D. A. and P. Hus, Blending Opportunity Fuels with Coal for Efficiency and 

Environmental Benefit, presented at 25th International Technical Conference on Coal Utilization 

& Fuel Systems, Clearwater, FL., March 6 – 9, 2000 

(g) Tillman D A, Harding N S (2004) Fuels of opportunity: characteristics and uses in 

combustion systems. Elsevier, Oxford, UK 

(k) http://esm.versar.com/pprp/bibliography/PPES_06_02/PPES_06_02.pdf 

(h) Tillman D, Conn R, Duong D (2010) Coal characteristics and biomass cofiring in pulverized 

coal boilers. In: Electric Power, Baltimore, MD, USA, 18 - 20 May, 2010 

(i) Renewable and Alternative Energy Fact Sheet – Co-firing Biomass with Coal, Pennsylvania 

State University, 2010, http://pubs.cas.psu.edu/FreePubs/PDFs/ub044.pdf 

(j) Fernando R, Cofiring High Ratios of Biomass with Coal, IEA Clean Coal Centre (CCC/194), 

January 2012 

(k) DOE-EERE-ORNL, Biomass Energy Data Book- Edition 4, October 2012, 

http://cta.ornl.gov/bedb/index.shtml