Analysis of Heat Rate 

Improvement Potential at CoalFired Power Plants

May 2015

Independent Statistics & Analysis

www.eia.gov

U.S. Department of Energy

Washington, DC 20585
U.S. Energy Information Administration | Analysis of Heat Rate Improvement Potential at Coal-Fired Power Plants i

This report was prepared by the U.S. Energy Information Administration (EIA), the statistical and 

analytical agency within the U.S. Department of Energy. By law, EIA’s data, analyses, and forecasts are 

independent of approval by any other officer or employee of the United States Government. The views 

in this report therefore should not be construed as representing those of the U.S. Department of Energy 

or other federal agencies.
May 2015

U.S. Energy Information Administration | Analysis of Heat Rate Improvement Potential at Coal-Fired Power Plants 1

Introduction

The thermal efficiency of electricity production is represented by the heat rate, which measures the 

amount of energy used to generate one kilowatthour of electricity.1 A generating unit with a lower, or 

more efficient, heat rate can generate the same quantity of electricity while consuming less fuel, 

compared with a unit with a higher heat rate. Lower fuel use per unit of electricity generated also 

reduces the corresponding emissions of pollutants such as sulfur dioxide (SO2), nitrogen oxide (NOX), 

mercury (Hg), and carbon dioxide (CO2). Consequently, improving heat rates at power plants can lower 

fuel costs and help achieve compliance with environmental regulations.

During the development of the Annual Energy Outlook 2015 (AEO2015), the U.S. Energy Information 

Administration (EIA) updated its modeling capability to include the ability to evaluate the potential for 

making heat rate improvements at existing coal-fired generators. The projections in the AEO2015 are 

produced by the National Energy Modeling System (NEMS), which is a modular system consisting of 

components to represent fuel supply, end-use consumption and conversion sectors, as well as modules

for international and macroeconomic activities.

The Electricity Market Module (EMM) is the electricity supply component of the NEMS. The EMM 

performs three primary functions – capacity planning, fuel dispatching, and finance and pricing. 

Capacity planning decisions include building new plants to satisfy increases in demand and to replace

retiring plants. Planning decisions also consider retrofits of existing capacity to install pollution control 

devices. The fuel dispatching function involves operating the available capacity to meet the demand for 

electricity. The finance and pricing function considers the investment costs associated with planning 

decisions and the operating costs from dispatching activities to develop delivered prices for electricity.

Heat rate improvement is another planning activity, as it considers the tradeoff between the investment 

expenditures and the savings in fuel and/or environmental compliance costs. Potential increases in 

efficiency can vary depending in part on the type of equipment installed at a generating plant. The

EMM represents 32 configurations of existing coal-fired plants based on different combinations of 

particulate, sulfur dioxide (SO2), nitrogen oxide (NOX), mercury, and carbon emission controls (Table 1). 

These categories form the basis for evaluating the potential for heat rate improvements.

EIA entered into a contract with Leidos Corporation (Leidos) to develop a methodology to evaluate the 

potential for heat rate improvement at existing coal-fired generating plants. Leidos performed a 

statistical analysis of the heat rate characteristics of coal-fired generating units modeled by EIA in the 

EMM. Specifically, Leidos developed a predictive model for coal-fired electric generating unit heat rates 

as a function of various unit characteristics.2 Leidos employed statistical modeling techniques to create 

the predictive models.3

 1 U.S. Energy Information Administration, Frequently Asked Questions, What is the efficiency of different types of power 

plants?, accessed January 31, 2015. 2 The characteristics used to predict heat rate included attributes such as nameplate capacity, rank of coal used, NEMS plant 

type, flue-gas desulfurization status, and flue-gas particulate collector type. 3 This included algorithmic evaluation of potential descriptive variables, and piecewise linear regression analysis. A decision tree 

created 7 sub-models describing inputs for the heat rate model for different unit categorizations.
May 2015

U.S. Energy Information Administration | Analysis of Heat Rate Improvement Potential at Coal-Fired Power Plants 2

For the EMM plant types, the coal-fired generating units were categorized according to quartiles, based 

on observed4 versus predicted heat rates. Units in the first quartile (Q1), which perform better than 

predicted, were generally associated with the least potential for heat rate improvement. Units in the 

fourth quartile (Q4), representing the least efficient units relative to predicted values, were generally 

associated with the highest potential for heat rate improvement. Leidos developed a matrix of heat rate 

improvement options and associated costs, based on a literature review and the application of 

engineering judgment.

Little or no coal-fired capacity exists for the EMM plant types with mercury and carbon control

configurations, therefore estimates were not developed for those plant types. These plant types were 

ultimately assigned the characteristics of the plants with the same combinations of particulate, SO2, and 

NOx controls. Plant types with relatively few observations were combined with other plant types having 

similar improvement profiles. As a result, 9 unique plant type combinations were developed for the 

purposes of the quartile analysis, and for each of these combinations Leidos created a minimum and a 

maximum potential for heat rate improvement along with the associated costs to achieve those 

improved efficiencies.

5

 

Leidos used the minimum and maximum characteristics as a basis for developing estimates of mid-range 

cost and heat rate improvement potential. The mid-range estimates were used as the default values for 

the Annual Energy Outlook 2015 (AEO2015) (Table 2). Table 3 contains the minimum and maximum heat 

rate improvements and costs.

Additional details regarding the background and the analytical methodology are included in the 

consultant report prepared by Leidos Corporation (Appendix).

 4 In this report, observed heat rates refer to the heat rates contained in EIA’s EMM plant file. 5 Leidos selected the plant type and quartile groupings such that each grouping contained at least 10 generating units, with the 

exception of the integrated gasification combined-cycle (IG) type, which has essentially no heat rate improvement potential. 

Some plant types and quartiles also had associated variable operation and maintenance (O&M) costs. The variable O&M costs 

were not incorporated into the NEMS EMM model at the time of this analysis. However, the impact of omitting variable O&M 

cost is expected to be small due to the relative magnitude of the capital and fixed O&M cost components.
May 2015

U.S. Energy Information Administration | Analysis of Heat Rate Improvement Potential at Coal-Fired Power Plants 3

Table 1: Existing pulverized coal plant types in the NEMS Electricity Market Module

Plant

type

Particulate

controls

SO2

controls

NOX

controls

Mercury

controls

Carbon

controls

B1 BH None Any None None

B2 BH None Any None CCS

B3 BH Wet None None None

B4 BH Wet None None CCS

B5 BH Wet SCR None None

B6 BH Wet SCR None CCS

B7 BH Dry Any None None

B8 BH Dry Any None CCS

C1 CSE None Any None None

C2 CSE None Any FF None

C3 CSE None Any FF CCS

C4 CSE Wet None None None

C5 CSE Wet None FF None

C6 CSE Wet None FF CCS

C7 CSE Wet SCR None None

C8 CSE Wet SCR FF None

C9 CSE Wet SCR FF CCS

CX CSE Dry Any None None

CY CSE Dry Any FF None

CZ CSE Dry SCR FF CCS

H1 HSE/Oth None Any None None

H2 HSE/Oth None Any FF None

H3 HSE/Oth None Any FF CCS

H4 HSE/Oth Wet None None None

H5 HSE/Oth Wet None FF None

H6 HSE/Oth Wet None FF CCS

H7 HSE/Oth Wet SCR None None

H8 HSE/Oth Wet SCR FF None

H9 HSE/Oth Wet SCR FF CCS

HA HSE/Oth Dry Any None None

HB HSE/Oth Dry Any FF None

HC HSE/Oth Dry Any FF CCS

Notes: Particulate Controls, BH – baghouse, CSE = cold side electrostatic precipitator, 

HSE/Oth = hot side electrostatic precipitator/other/none;

SO2 Controls - wet = wet scrubber, Dry = dry scrubber;

NOx Controls, SCR = selective catalytic reduction;

Mercury Controls - FF = fabric filter;

Carbon Controls - CCS = carbon capture and storage.

Source: U.S. Energy Information Administration/Leidos Corporation.
May 2015

U.S. Energy Information Administration | Analysis of Heat Rate Improvement Potential at Coal-Fired Power Plants 4

Table 2: Heat rate improvement (HRI) potential and cost (capital, fixed O&M) by Plant Type and 

quartile as used for input to NEMS 

Plant type

and quartile combination Count of total units

Percentage HRI 

potential

Capital cost 

(million 2014 

$/MW)

Average fixed O&M 

cost (2014 $/MW-yr)

B1-Q1 32 (s) 0.01 200

B1-Q2 15 0.8% 0.10 2,000

B1-Q3 18 4% 0.20 4,000

B1-Q4 20 6% 0.90 20,000

B3-Q1 13 (s) 0.01 300

B3-Q2 24 0.7% 0.05 1,000

B3-Q3 16 6% 0.20 3,000

B3-Q4 15 9% 0.60 10,000

B5C7-Q1 16 (s) (s) 80

B5C7-Q2 42 0.8% 0.03 700

B5C7H7-Q3 84 7% 0.10 2,000

B5C7H7-Q4 59 10% 0.20 4,000

B7-Q1 27 (s) (s) 70

B7-Q2 25 0.8% 0.04 800

B7-Q3Q4 30 7% 0.30 5,000

C1H1-Q1 148 (s) 0.01 200

C1H1-Q2 117 0.8% 0.10 2,000

C1H1-Q3 72 4% 0.40 8,000

C1H1-Q4 110 7% 1.00 30,000

C4-Q1 15 (s) (s) 80

C4-Q2 27 0.8% 0.04 900

C4-Q3 32 6% 0.20 2,000

C4-Q4 39 10% 0.30 5,000

CX-Q1Q2Q3Q4 15 7% 0.20 4,000

H4-Q1Q2Q3 13 3% 0.20 3,000

IG-Q1 3 (s) (s) 60

Total set 1,027 4% 0.30 6,000

(s) = less than 0.05% for HRI potential or less than 0.005 million $/MW for capital cost.

Source: U.S. Energy Information Administration/Leidos Corporation.
May 2015

U.S. Energy Information Administration | Analysis of Heat Rate Improvement Potential at Coal-Fired Power Plants 5

Table 3: Minimum and maximum heat rate improvement (HRI) parameters

Plant type and quartile 

combination

Count of total 

units

Percentage HRI 

potential

Capital cost 

(million 2014 

$/MW)

B1-Q1 32 (s) 0.007

B1-Q2 15 0.3% - 1.2% 0.096 - 0.11

B1-Q3 18 2.1% - 6.4% 0.20 - 0.26

B1-Q4 20 3.5% - 9.4% 0.76 - 0.99

B3-Q1 13 (s) 0.01

B3-Q2 24 0.3% - 1.2% 0.047 - 0.056

B3-Q3 16 3.1% - 8.2% 0.19 - 0.30

B3-Q4 15 5.1% - 13% 0.50 - 0.72

B5C7-Q1 16 (s) 0.003

B5C7-Q2 42 0.3% - 1.2% 0.031 - 0.036

B5C7H7-Q3 84 3.6% - 9.5% 0.11 - 0.16

B5C7H7-Q4 59 6.0% - 15% 0.18 - 0.25

B7-Q1 27 (s) 0.002

B7-Q2 25 0.3% - 1.2% 0.035 - 0.042

B7-Q3Q4 30 3.8% - 9.8% 0.27 - 0.40

C1H1-Q1 148 (s) 0.006

C1H1-Q2 117 0.3% - 1.2% 0.12 - 0.13

C1H1-Q3 72 2.0% - 6.0% 0.36 - 0.49

C1H1-Q4 110 3.6% - 9.6% 1.1 - 1.5

C4-Q1 15 (s) 0.002

C4-Q2 27 0.3% - 1.2% 0.041 - 0.048

C4-Q3 32 3.5% - 9.1% 0.13 - 0.20

C4-Q4 39 5.7% - 14% 0.21 - 0.30

CX-Q1Q2Q3Q4 15 3.7% - 9.7% 0.19 - 0.28

H4-Q1Q2Q3 13 1.9% - 5.1% 0.14 - 0.21

IG-Q1 3 (s) 0.002

Total set 1,027 2.0% - 5.3% 0.24 - 0.32

(s) = less than 0.05% for HRI potential.

Source: U.S. Energy Information Administration/Leidos Corporation.
May 2015

U.S. Energy Information Administration | Analysis of Heat Rate Improvement Potential at Coal-Fired Power Plants 6

Appendix – Full Report
Evaluation of the Potential for Heat 

Rate Improvements at Coal-Fired

Power Plants

EIA Task 7965, Subtask 14

Prepared for:

Energy Information Administration

Office of Energy Analysis

Office of Electricity, Coal, Nuclear and Renewables Analysis

Prepared by: 

Leidos Corporation

Ken Walsh, Dave Lesneski, Carl Thomason, Jay Ratafia-Brown

FINAL REPORT

January 2015
Table of Contents

Table of Contents..............................................................................................................................i

List of Tables ..................................................................................................................................iii

List of Figures.................................................................................................................................iv

List of Abbreviations and Acronyms..............................................................................................vi

List of Energy Information Administration ECP Types................................................................vii

Executive Summary...................................................................................................................... viii

1 Introduction............................................................................................................................. 1

2 Literature Review.................................................................................................................... 3

2.1 Heat Rate Improvement Technologies............................................................................. 6

2.1.1 Fuel Supply ............................................................................................................... 6

2.1.2 Boiler Island .............................................................................................................. 6

2.1.3 Turbine Island ........................................................................................................... 8

2.1.4 Other Improvements ................................................................................................. 9

2.2 Total HRI Studies........................................................................................................... 10

2.3 Associated Costs ............................................................................................................ 11

3 Statistical Assessment of Heat Rates in the Plant Database ................................................. 12

3.1 Data Processing .............................................................................................................. 12

3.2 General Data Population Characteristics........................................................................ 12

3.3 Influence of Nameplate Capacity on Heat Rate ............................................................. 17

3.4 Slope Function Analysis................................................................................................. 19

3.5 Model Predictions of Heat Rate ..................................................................................... 23

3.6 Generator Units that Most Likely Can Improve Heat Rates.......................................... 24

4 Interpretation of Quartile Data .............................................................................................. 26

4.1 Subcritical Versus Supercritical Boilers ........................................................................ 28

4.2 States .............................................................................................................................. 28

4.3 ECP Plant Types............................................................................................................. 29

4.4 Heat Rates ...................................................................................................................... 31

4.5 Online Year .................................................................................................................... 33

4.6 Planned Retirement Year ............................................................................................... 33

4.7 Variable O&M Costs...................................................................................................... 34

4.8 Fuel Choice .................................................................................................................... 35

4.9 Total FGD Cost .............................................................................................................. 37

4.10 FGP Collector Classification and Hours in Service ....................................................... 37

4.11 Cooling System Type and In-Service Year.................................................................... 39

4.12 Number of Federal Air Market Programs Affecting Emissions .................................... 41

5 Evaluation of Potential HRIs and Associated Costs............................................................. 44

5.1 Heat Rate Improvement Options and Valuation ............................................................ 44

i
5.2 Heat Rate Improvement Cost Estimation....................................................................... 46

6 Applying Potential Heat Rate Improvements to the Entire Database ................................... 59

6.1 HRI Potentials as They Relate to Select Input Parameters ............................................ 59

6.1.1 Online Year............................................................................................................. 59

6.1.2 Nameplate Capacity ................................................................................................ 59

6.1.3 ECP Type ................................................................................................................ 61

6.2 HRI for the Total Data Set ............................................................................................. 65

6.3 Associated Costs ............................................................................................................ 67

6.4 Other Considerations...................................................................................................... 70

7 Recommendations................................................................................................................. 72

Appendix A. Heat Rate Improvements Assigned to ECP Types.................................................. 74

Appendix B. Heat Rate Improvements Assigned to Modified ECP Types.................................. 75

Appendix C. Modified Heat Rate Improvements Assigned to ECP Types.................................. 77

Appendix D. Modified Heat Rate Improvements Assigned to Modified ECP Types.................. 78

Appendix E. Midpoints between Minima and Maxima in Appendix A* ..................................... 80

Appendix F. Midpoints between Minima and Maxima in Appendix B* ..................................... 81

ii
List of Tables

Table 2-1. Existing Coal-Fired EGU Efficiency Improvements Reported for Actual 

Efficiency Improvement Projects...................................................................................3

Table 2-2. Maximum HRIs and Associated Costs Listed in the 2009 S&L Report........................4

Table 2-3. 2010 NETL Assessment of Coal-Fired Power Plant Efficiencies ...............................11

Table 3-1. Distribution of Numeric Parameters Associated with Coal-Fired 

Generators....................................................................................................................13

Table 3-2. Numeric Parameter Pairs with Correlation Coefficients with Absolute 

Values Greater than 0.60..............................................................................................15

Table 3-3. Nominal and Logical Characteristics Considered in this Study...................................16

Table 3-4. Results from the AttributeEvaluator Showing Those Variables that Most 

Influence the Slope Function Variable and Are Independent of Other 

Variables ......................................................................................................................21

Table 4-1. Distributions of Numeric Parameters among the Quartiles.........................................26

Table 4-2. States Whose Generators Mostly Fall into a Single Quartile. .....................................28

Table 4-3. Distribution of ECP Plant Types among Quartiles......................................................30

Table 4-4. Number of Generator Units in Quartiles Based on Primary Fuel Usage .....................36

Table 4-5. Number of Air Market Programs Affecting Generators by State ................................41

Table 5-1. Maximum Estimates For Heat Rate Improvements and Capital Costs........................47

Table 5-2. Minimum Estimates for Heat Rate Improvements and Capital Costs.........................52

Table 5-3. Fixed and Variable O&M Cost Estimates for Heat Rate Improvements.....................56

Table 6-1. Calculated HRI Potentials by ECP Type .....................................................................63

Table 6-2. Cumulative Percentiles for the HRI Data Sets.............................................................67

iii
List of Figures

Figure ES-1.Comparison of Reported and Predicted Inverse Heat Rates for All Coal 

Fired Generators.........................................................................................................ix

Figure ES-2. Average New Heat Rates by NEMS ECP Type .........................................................x

Figure 1-1. Average Heat Rate from Coal-Fired Units (Weighted to Generators 

Based on 2012 Electricity Production) .......................................................................1

Figure 3-1. Preliminary Decision Tree for Describing Inverse Heat Rates.................................18

Figure 3-2. Preliminary Relationship between Nameplate Capacity and ....................................19

Figure 3-3. Histogram Showing the Distribution for the Slope Function 

Transformation..........................................................................................................20

Figure 3-4. Decision Tree to Describe the Slope Function Using the .........................................23

Figure 3-5. Comparison of Reported and Predicted Inverse .......................................................24

Figure 3-6. Quartiles Comparing Reported Heat Rates to Predicted Heat Rates........................25

Figure 4-1. Distribution of Units across the Quartiles for Reported ...........................................26

Figure 4-2. Comparisons of Heat Rates for Select Data Subsets by State and Quartile..............29

Figure 4-3. Distribution of FGD Type among the Quartiles .......................................................30

Figure 4-4. Distribution of Particulate Control Types among the Quartiles ...............................31

Figure 4-5. Distribution among the Quartiles Based on..............................................................31

Figure 4-6. Distribution of CAMD 2012 Heat Rates among Quartiles.......................................32

Figure 4-7. Distribution of EIA-Reported Heat Rates among the Quartiles ...............................32

Figure 4-8. Distribution of Quartiles Based on Online Year.......................................................33

Figure 4-9. Distribution of Quartiles for Units Listing Planned Retirement Years.....................34

Figure 4-10. Distribution of Quartiles among Online Years for Units Listing..............................34

Figure 4-11. Distribution of Quartiles Based on Variable O&M Costs ........................................35

Figure 4-12. Distribution of Quartiles Based on Variable O&M Costs (Including Fuel 

Costs) for Units with Nameplate Capacities Over 100 MW.....................................35

Figure 4-13. Distribution of Total FGD Cost (Thousands of Dollars) among Quartiles ..............37

Figure 4-14. Distribution of Quartiles among FGP Collector Types ............................................38

Figure 4-15. Distribution of FGP Collector Types with Online Year ...........................................38

Figure 4-16. Fractional Distribution of FGP Service Hours among Quartiles..............................39

Figure 4-17. Fractional Distribution of the Quartiles within Cooling System Types ...................40

Figure 4-18. Distribution of Cooling System Types among In-Service Years..............................40

iv
Figure 4-19. Distribution of Quartiles Based on Number of Federal Air Market 

Programs ...................................................................................................................43

Figure 4-20. Distribution of Heat Rates Based on Number of ......................................................43

Figure 6-1. Distribution of Units with Particular HRI Potentials by Online Year (Top 

Representing Maxima and Bottom Representing Minima) ......................................60

Figure 6-2. Distribution of Units with Particular HRI Potentials by Nameplate 

Capacity (Top Representing Maxima and Bottom Representing Minima) ..............61

Figure 6-3. Distribution of Units with Particular HRI Potentials by ECP Type (Top 

Representing Maxima and Bottom Representing Minima) ......................................62

Figure 6-4. Average HRI Potentials for NEMS ECP Types (Left Side of Bar ...........................64

Figure 6-5. Average New Heat Rates by NEMS ECP Type .......................................................65

Figure 6-6. Fractions of Units with Lower Total HRI Potentials and Lower Percent 

HRIs..........................................................................................................................66

Figure 6-7. Cumulative Percentile Graphs Depicting HRI Costs at Different Units...................68

Figure 6-8. Cumulative Percentile Graphs Depicting HRI Unit Costs at Different 

Units..........................................................................................................................69

Figure 6-9. Relationship between Costs and HRI Potential for ECP Types ...............................70

v
List of Abbreviations and Acronyms

AEO Annual Energy Outlook

AMPD Air Markets Program Data

ASME American Society of Mechanical Engineers

Btu British thermal units

CAMD Clean Air Markets Division

CO Carbon monoxide

CO2 Carbon dioxide

DCS Distributed control system

ECP Electricity Capacity Planning

EFD Electricity Fuel Dispatch

EGU Electricity Generating Unit

EIA Energy Information Administration

EMM Electricity Market Module

EPA Environmental Protection Agency

EPRI Electric Power Research Institute

ESP Electrostatic precipitator

FDS Fuel delivery system

FGD Flue gas desulfurization

FGP Flue gas particulate

GMOD GHG Mitigation Options Database

GWh Gigawatt-hours

HRI Heat rate improvement

$K Thousand dollars

kWh Kilowatt-hours

LP Low pressure

M5P A numeric classifier algorithm within Weka data mining software

$M Million dollars

MWh Megawatt-hours

NEMS National Energy Modeling System

NETL National Energy Technology Laboratory

NOX Oxides of nitrogen

NPC Nameplate capacity

NSR New Source Review

O&M Operating and maintenance

R&D Research and development

S&L Sargent & Lundy

SCR Selective catalytic reduction

TC Total costs

TPFS Total potential fuel savings

U.S. United States

vi
List of Energy Information Administration ECP Types

For the database within this study, EIA assigned twelve codes to coal-fired electricity generating 

units for use in the Electricity Capacity Planning (ECP) submodule within the Electricity Market 

Module (EMM) of the National Energy Modeling System (NEMS). These codes represent the 

fuel/technology and emission control devices. Because the codes are frequently referenced in this 

report, the code definitions are included below for coal-fired units (none were listed with carbon 

capture devices):

Unit 

Code Technology

Particulate 

Control

Flue Gas 

Desulfurization Other Controls

B1

Conventional

Baghouse

None Any NOx control

B3 Wet No selective catalytic reduction

B5 Wet Selective catalytic reduction

B7 Dry Any NOx control

C1

Cold-side 

electrostatic 

precipitator

None Any NOx control

C4 Wet None

C7 Wet Selective catalytic reduction

CX Dry None

H1

Other or none

None Any NOx control

H4 Wet None

H7 Wet Selective catalytic reduction

IG

Integrated 

gasification 

combined 

cycle

-- -- --

 

vii
Executive Summary

The Energy Information Administration’s (EIA’s) National Energy Modeling System (NEMS) 

projects annual loads on electric generating units and the years that different types of coal-fired 

units will retire or implement efficiency improvements based on economic factors. This study

evaluated how NEMS might assign heat rate improvements (HRIs) to different coal-fired electric 

generating units and compute the associated costs within NEMS. Various unit-level HRIs were 

considered in an effort to match NEMS unit types to particular total improvement levels.

The net heat rates at existing generators were compared to individual numeric parameters from 

EIA and U.S. Environmental Protection Agency (EPA) records, but the only factor that had a 

linear correlation coefficient better than 0.60 was the variable operating and maintenance costs as 

expressed in dollars per megawatt-hour ($/MWh). Despite the influence of many different plant 

design aspects, the inverse net heat rates (a plant efficiency metric) were clearly dependent 

(though not linearly) on the nameplate capacities (MW) of the boilers associated with each 

generator.

Data mining algorithms produced a piecewise linear regression model to describe the behavior at 

the coal-fired units. Previous studies had yielded Pearson’s correlation coefficients (r2

) of 0.18, 

but the piecewise linear modeling approach in this study improved the r2 to 0.62 (for predicting 

inverse heat rates). Figure ES-1 compares the reported and predicted inverse heat rates, and the 

red dashed lines show slopes corresponding to a 50% confidence interval. The deviations of 

reported heat rates in 2012 from the modeled values provide benchmarks to differentiate units 

with HRI potentials from those that are likely already operating very efficiently. The units lying 

to the left of all three lines in Figure ES-1 were considered to be those that had the most room for 

improvement relative to similar units. Those to the right of the lines likely would have less HRI 

potential because they already operate better than similar units (as described by the model).

Fifty-six HRI activities were initially under consideration, but the list was reduced to 29 

measures because available HRIs should be considered non-routine activities, should not 

overlap, and should be beyond the pilot phase of development (in order to allow costing 

estimates within NEMS). No-cost and low-cost improvements could be made at the plants 

operating at the lowest efficiencies (Quartile 4) while assuming that other plants had already 

implemented these. The study also associated moderate- and high-cost HRIs as potential for units 

that were operating near the modeled heat rate values (Quartiles 2 and 3) but not near the best 

reported values for similar units (Quartile 1).

Units that went online after 1990 generally offered the smallest HRI potentials; 70% of those 

units fell into Quartiles 1 and 2, so fewer HRI measures were attached to them. Units going 

online in the 1970s and 1980s received the earliest air pollution control technologies but have not 

necessarily been upgraded in their lifetimes. The 1970s/1980s units also include the supercritical 

units, so their heat rates were competitive with other upgraded units. Because NEMS ECP types1

categorize the coal-fired units based on emission control technologies, the analyses show that the 

emission controls at the units with the highest HRI potential are likely to be characterized by a 

combination of these three factors: wet scrubbers, no use of baghouses or cold-side ESP, and 

SCR.

1 ECP types defined on page vii.

viii

 
Figure ES-1. Comparison of Reported and Predicted Inverse Heat Rates for

All Coal-Fired Generators

Figure ES-2 presents the average new heat rates that might be associated with the average units

in each ECP type. The left sides of the bars represent the average heat rates if the maximum HRI 

potentials are realized with every improvement, and the right sides of the bars represent the 

resultant heat rates when only the minimum HRIs are achieved. The plot shows that B5, C7, H7 

and some C4 units might have heat rates under 10,000 Btu/kWh if the improvements are made. 

In Figure ES-2, the H1 units would continue to average high heat rates (near 16,000 Btu/kWh) 

even if the improvements described were all undertaken because EIA’s base heat rates for these

21 units are high.

The capital costs can be approximated (r2

=0.90) by multiplying the HRI potential by $100,000-

kWh/Btu. However, the total operating and maintenance (O&M) costs are not well estimated by 

a linear correlation (r2

=0.41). The poor approximations of total O&M costs are tied to the nonlinearity associated with one particular HRI measure with high O&M costs. If this one HRI 

measure is removed from consideration, variable O&M costs drop to just 2% of the total O&M 

costs and the linearity improves (r2

=0.95 and slope=$1600-kWh/Btu-yr).

ix
Figure ES-2. Average New Heat Rates by NEMS ECP Type.

x
1 Introduction

The NEMS Electricity Market Module (EMM) dispatches generating units in economic merit 

order, subject to numerous constraints. In order for coal-fired generating units to be dispatched in 

NEMS EMM, all else equal, the associated variable costs must be lower than the variable costs 

of other generators. A competitive coal-fired plant may need to implement net heat rate 

improvements in order to remain an economical choice in the model. 

The net heat rate (Btu/kWh) represents the total heat content of the fuel consumed (based on the 

higher heating value, HHV) divided by the net electricity generation. The net electricity 

generation is represented by the gross generation minus the electricity consumed internally by 

the plant (e.g., fuel feed systems, boiler feed pumps, pollution control devices, heat recovery 

equipment, and other auxiliary loads); whereas gross generation for a unit represents the total 

amount of electric energy as measured at the generator terminal.

This study was based on the reference data in the NEMS EMM plant database that EIA provided 

for this study, as well as information collected from the 2012 EIA-860 survey. An EIA data set 

of generators that are primarily powered by coal-fired boilers had 2012 net heat rates ranging 

from 8800 Btu/kWh to 25,000 Btu/kWh. Weighting this information based on the net MWh 

electricity produced (using EPA CAMD files), the 2012 state averages ranged from 9700 

Btu/kWh (North Carolina) to 11,500 Btu/kWh (Delaware), as illustrated in Figure 1-1. These 

numbers indicate that the North Carolina coal-fired plants are on average 16% more efficient 

than the Delaware plants. Coal quality and moisture affect the potential heat rates, but this 

significant range is also influenced by plant design and operations.

Figure 1-1. Average Heat Rate from Coal-Fired Units (Weighted to Generators Based on 

2012 Electricity Production)

1
EIA and EPA regularly collect information about fuel usage, operations, and emissions at power 

plants, but modifications that are made to improve the net heat rate are not tracked on a national 

basis. Improvements for the boiler island, turbine island, flue gas system, air pollution controls, 

and water treatment system may all affect the net heat rate.

This report discusses one NEMS approach that would allow heat rate improvements (and the 

associated costs) to be incorporated expeditiously for present and future activities. Chapter 2 lists 

some resources that published observed heat rate improvements. Chapter 3 describes the 

processing of an EIA survey data set to determine which coal-fired units are likely already 

operating as efficiently as possible and which units have more potential for improvement. 

Chapter 4 shares analyses that indicate how the potential for improvement is related to other 

plant characteristics. Chapter 5 discusses the possible heat rate improvement measures, their 

effects, and their costs. Chapter 6 describes the resulting total heat rate improvements associated 

with the various ECP plant types within NEMS and the associated capital, operating, and 

maintenance costs. Chapter 7 presents some recommendations for future improvements to the 

estimates, primarily based on expected new information sources.

2
2 Literature Review 

Some differences in heat rates may be attributed to coal type, moisture content, and boiler sizes, 

but best practices and technological improvements have also been made at some plants with the 

goals of decreasing heat rates and subsequently fuel costs. Many heat rate improvements (HRIs)

have been made over the last several decades, and the National Energy Technology Laboratory 

(NETL) summarized the efficiency improvements for existing coal-fired power plants in 2008. 

In 2014, the U.S. EPA2 reported these HRIs and the associated efficiencies (reproduced in Table 

2-1).

Table 2-1. Existing Coal-Fired EGU Efficiency Improvements Reported for Actual 

Efficiency Improvement Projects 3

Efficiency 

Improvement 

Technology

Description

Reported 

Efficiency 

Increase a

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 rates, CO levels, oxygen levels, slag deposits, and burner 

metrics as well as advanced coal nozzles and plasma assisted coal combustion.

0.15 to 

0.84%

Cooling 

System Heat 

Loss Recovery

Recover a portion of the heat loss from the warm cooling water exiting the steam 

condenser prior to its circulation through a cooling tower or discharge to a water 

body. The identified technologies include replacing the cooling tower fill (heat 

transfer surface) and tuning the cooling tower and condenser.

0.2 to 1%

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 moisture. For power plants 

equipped with wet FGD systems, the flue gas is further cooled to approximately 

125°F as it is sprayed with the FGD reagent slurry. However, it may be possible to 

recover some of this lost energy in the flue gas to preheat boiler feedwater via use 

of a condensing heat exchanger.

0.3 to 1.5%

Low-rank 

Coal Drying

Subbituminous and lignite coals contain relatively large amounts of moisture (15 to 

40%) compared to bituminous coal (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 lower for plants burning low-rank coal. The technologies include using 

waste heat from the flue gas and/or cooling water systems to dry low-rank coal 

prior to combustion.

0.1 to 1.7%

2 U.S. Environmental Protection Agency,GHG Abatement Measures, Technical Support Document for Carbon 

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

Stationary Sources: Electric Utility Generating Units, Docket ID No. EPA-HQ-OAR-2013-0602, June 2014. 

Downloaded from http://www.eenews.net/assets/2014/06/02/document_gw_04.pdf on December 1, 2014.

3 Ibid.

3

 
Efficiency 

Improvement 

Technology

Description

Reported 

Efficiency 

Increase a

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 

include intelligent or neural network sootblowing (i.e., sootblowing in response to 

real-time conditions in the boiler) and detonation sootblowing.

0.1 to 

0.65%

Steam 

Turbine 

Design

There are recoverable energy losses that result from the mechanical design or 

physical condition of the steam turbine. For example, steam turbine manufacturers 

have improved the design of turbine blades and steam seals which can increase 

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

0.84 to 

2.6%

Source: U.S. Department of Energy, National Energy Technology Laboratory, Reducing CO2 Emissions by Improving the 

Efficiency of the Existing Coal-fired Power Plant Fleet, DOE/NETL-2008/1329 , Pittsburgh, PA. July 23, 2008. Available at: 

<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 efficiencies for a reference plant as follows: 87% boiler efficiency, 40% turbine efficiency, 98% generator 

efficiency, and 6% auxiliary load. Based on these assumptions, the reference 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 improvement method was reported to achieve a 1% point 

increase in boiler efficiency, it would be converted to a 0.37 % point increase in overall efficiency. Likewise, a reported 100 

Btu/kWh decrease in net heat rate would be converted to a 0.30% point increase in overall efficiency.

However, this report noted the following:

“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.” 

Despite this lack of detailed information, EPA’s method included binning plants into 168 

categories and forecasting possible HRIs based on the best 10% of the units.

The 2009 Sargent and Lundy report (S&L Report) quantifies the major retrofits that are not 

considered cost-prohibitive at existing coal-fired power plants. Activities that were considered 

cost-prohibitive included coal handling, coal ash handling, and feedwater preheating.4 This 

literature review presents findings from the S&L Report (Table 2-2), but focuses on work that 

has been published since issuance of that report.

The sections below outline additional technologies that can be used to reduce heat rates, as well 

as studies that describe total possible HRIs. For example, EPRI’s Production Cost Optimization 

project evaluated five units to find 3-5% HRIs through various means.5 In addition, an EPA 

technical support document associated with the greenhouse gas emission control measures for 

power plants discusses possible efficiency gains. For studies that estimate costs associated with 

these technologies and groups of technologies, the costs are also presented in the final section.

4 Hansel, Peter, Heat Rate Reductions and Carbon Emissions: A Policy Mechanism for Regulating Coal Plants 

under 111(d) of the Clean Air Act, April 22, 2014. Downloaded on November 25, 2014, from 

http://dukespace.lib.duke.edu/dspace/bitstream/handle/10161/8508/Heat%20Rate%20Reductions%20and%20Carb

on%20Emissions%20-%20Peter%20Hansel%20MP%20Final.pdf?sequence=1. 5 Korellis, S., Range and Applicability of Heat Rate Improvements, Technical Update, Electric Power Research 

Institute Report Number 3002003457, April 2014.

4

 
Table 2-2. Maximum HRIs and Associated Costs Listed in the 2009 S&L Report

Heat Rate 

Improvement 

(Btu/kWh)

Capital Cost

(2008 $M)

Fixed O&M

(2008 $K/yr)

Variable O&M

(2008 $K/yr)

≤200 

MW

≤500 

MW

>500 

MW

≤200 

MW

≤500 

MW

>500 

MW

≤200 

MW

≤500 

MW

>500 

MW

≤200 

MW

≤500 

MW

>500 

MW

Boiler Island Improvements

Installing 

economizer 100 100 100 3 5 8 50 100 150 0 0 0

Neural network 150 100 50 0.5 0.8 0.8 50 50 50 0 0 0

Intelligent 

sootblower 150 90 90 0.3 0.5 0.5 50 50 50 0 0 0

Limit air heater 

leakage 40 40 40 0.5 0.7 1.2 50 75 100 0 0 0

Lower air heater 

outlet 

temperature by 

controlling acid 

dew point

120 120 120 3.5 10 18 50 75 100 350 850 1500

Turbine Island Improvements

Turbine 

overhaul 300 300 300 12 20 25 0 0 0 0 0 0

Condenser 

cleaning 70 70 70 0 0 0 30 60 80 0 0 0

Boiler feed 

pumps

50 50 50 0.35 0.6 0.8 0 0 0 0 0 0

Flue Gas System Improvements

ID axial fan (and 

motor) upgrades 50 50 50 6.5 11 16 50 85 130 0 0 0

Variablefrequency drives 100 100 100 2 4 6 20 30 50 0 0 0

Variablefrequency drives 

and new 

centrifugal fans

150 150 150 6.5 11 16 25 38 60 0 0 0

Air Pollution Control Improvements

Removal of 

Venturi throat 13 13 13 2.5 2.5 2.5 0 0 0 0 0 0

Turning vanes 

and perforated 

gas distribution 

plates at the inlet

2 2 2 0.25 0.25 0.25 0 0 0 0 0 0

Shutoff spray 

level 16 16 16 -- -- -- 0 0 0 0 0 0

Variablefrequency drives 50 50 50 1 3 5 50 100 150 0 0 0

ESP modification 5 5 5 0.2 0.5 0.8 25 25 25 0 0 0

SCR 

modification 10 10 10 0.5 1 2 25 50 100 25 60 100

Water Treatment Improvements

Cooling tower 

advanced 

packing upgrade

70 70 70 1.5 3 5 75 125 175 0 0 0

5
2.1 Heat Rate Improvement Technologies

The focus of this literature review is literature published after the S&L Report. Within this 

section, the literature review divides the technologies among the fuel supply, boiler island, 

turbine island, and other systems at the plant. One difficulty assessing the efficiency of various 

HRIs is that multiple improvement measures are undertaken during outages, so individual 

efficiencies cannot be determined from overall plant measurements.

2.1.1 Fuel Supply

The National Coal Council reports three alternatives for improving thermal efficiency:6

1) Coal switching (switch from subbituminous to bituminous fuel could increase thermal 

efficiency by 1.6%)

2) Coal drying (Great River Energy increased plant net generating thermal efficiency by 4% 

through lignite drying)

3) Coal processing (adding ammonium hydroxide increased the coal heating value from 

7,859 to 11,363 Btu/lb when 24% moisture was removed).

An example comes from the Great River Energy’s Coal Creek Station that combusts lignite in a 

mine-mouth operation. Since 2009, the 1180-MW plant has employed a new technology to 

compensate for off-design fuel quality.7 The DryFining process dried and segregated lignite coal 

with waste heat energy in a low-temperature system, reducing the moisture content by 10% and 

removing up to 40% of the sulfur and mercury from the fuel. The flue gas was subsequently 

reduced by 6%, and the plant efficiency increased by 4%. The investigators recently reported that 

the average annual improvement in net heat rate for Unit 1 is 3.4% (since 2009) and for Unit 2 

the net HRI is 5.8% (Unit 2 also benefitted from a steam turbine upgrade).8

2.1.2 Boiler Island

The National Coal Council9 reported that the unit generating efficiency may be improved by 

0.160.33% (lowering heat rate by 50-100 Btu/kWh) if failed boiler surfaces are replaced for a 

cost of $4-5M in a 500 MW plant. The report also mentions that upgraded economizers might 

lower the plant heat rate by 0.5-1.0%. The report also mentions that advanced boiler materials 

(including those using “nano-coatings”) were in the experimental stage and could significantly 

increase the heat transfer because they minimize deposit accumulation.

6 National Coal Council, Reliable & Resilient: The Value of Our Existing Coal Fleet, May 2014. Downloaded from 

http://www.nationalcoalcouncil.org/NEWS/NCCValueExistingCoalFleet.pdf. The National Coal Council is a 

Federal Advisory Committee to the U.S. Secretary of Energy.

7 Great River Energy, DryFining Fuel Enhancement Process. Online fact sheet downloaded from 

http://www.greatriverenergy.com/makingelectricity/newprojects/dryfining_factsheet.pdf on November 25, 2014.

 Also Bullinger, C.W., M.A. Ness, N. Sarunac, E.K Levy, R.S. Weinstein, and D.R. James, Method of enhancing 

the quality of high-moisture materials using system heat sources, U.S. Patent 8,579,999 B2, November 12, 2013. 

Downloaded from http://www.google.com/patents/US8579999 on November 25, 2014.

8 Sarunac, N. M. Ness, and C. Bullinger, “Improve Plant Efficiency and Reduce CO2 Emissions When Firing HighMoisture Coals.” Power Magazine, November 1, 2014. Downloaded from http://www.powermag.com/improveplant-efficiency-and-reduce-co2-emissions-when-firing-high-moisture-coals/?printmode=1 on November 26, 2014.

9 National Coal Council, Reliable & Resilient: The Value of Our Existing Coal Fleet, May 2014. Downloaded from 

http://www.nationalcoalcouncil.org/NEWS/NCCValueExistingCoalFleet.pdf. The National Coal Council is a 

Federal Advisory Committee to the U.S. Secretary of Energy.

6

 
In 2010 Breeding, Tandra, and Shah10 presented case studies demonstrating how on-line cleaning 

systems could be operated automatically in order to optimize the removal of ash and slag 

deposits in boilers. One sootblowing system includes fifty retractable sootblowers, eight water 

cannons, and air heater cleaners. A second installation improved overall plant efficiency up to 

1%, resulting in a high return on the investment.

Predictive models are used in a U.S. patent for a sootblowing control system in order to 

determine optimal sequences for sootblower and boiler performance.11 The optimization 

algorithm chooses the boiler zone to be treated and the sootblower type that will achieve the best 

boiler performance based on current operating conditions.

A 2011 white paper by Labbe and Gordon12 describes four power plant upgrades that contribute 

to higher efficiencies, lower emissions, greater fuel flexibility, higher availability, lower 

operating costs, and faster dispatch rates. Three of the four optimizations directly affect boiler 

operations: control systems, overfire air, and sootblowers. The sootblower optimization mixed a 

smart logic system that evaluates performance metrics, fouling conditions, and equipment status

and programmable sequence blocks that implement the cleaning actions.

The National Coal Council report cites intelligent sootblowers as reducing gross heat rates in 

older boilers by 30-90 Btu/kWh. In cases where slagging and fouling had reduced efficiency, 

heat rate reductions were as high as 150 Btu/kWh where lignite or Powder River Basin coals 

were used, and improvements might be typically made up to 60 Btu/kWh. The cost for an 

intelligent sootblowing system is cited as $0.5M for a 500-MW plant.

Labbe and Gordon also described overfire air optimization as a process involving new damper 

drives to regulate secondary air introduction near each burner, coupled with a new distributed 

control system (DCS) for modulation. The system reduced NOx emissions by 10% and also 

decreased the heat rate by improving the balance of oxygen distribution. Labbe and Gordon also 

described how upgrading the DCS controls on two boiler units resulted in heat rate 

improvements approaching 1%.

EPRI’s Range and Applicability Report (2014) listed several additional measures for the boiler 

island not found in the S&L Report but did not report potential cost.13 Those that would not 

overlap directly with the S&L Report findings include:

1) Automating boiler drains (to route to deaerators instead of condensers at reduced loads)

2) On-site fuel drying (resulting in significant decreases in required air flow)

10 Breeding, C., D. Tandra, and S. Shah, “Boiler Cleaning Using ISB (Intelligent Soot Blowing) System Integration: 

Recent Developments and Case Study,” Proceedings of the American Society of Mechanical Engineers 2010 

Power Conference, Chicago, Illinois, 2010. 

11 James, J.R., J. McDermott, S. Piche, F. Pickard, and N.J. Parikh, Sootblowing optimization for improved boiler 

performance, U.S. Patent 8,498,746 B2, July 30, 2013. Downloaded on November 25, 2014, from 

http://www.google.com/patents/US8498746. 12 Labbe, D. and L. Gordon, Continuous Performance Improvement in Power Generation: Optimization in Action, 

Invensys Operations Management, March 2011. Downloaded on November 25, 2014, from 

http://iom.invensys.com/EN/pdfLibrary/WhitePaper_Invensys_ContinuousPerformanceImprovementInPowerGen

eration_03-11.PDF. 13 Korellis, S., Range and Applicability of Heat Rate Improvements, Technical Update, Report Number 3002003457, 

Electric Power Research Institute, April 2014. 

7

 
3) Blowdown recovery tank

4) Air heater baskets

2.1.3 Turbine Island

An EPRI technical update report14 examined how the heat rates changed at a coal-fired power 

plant when it was reduced from base-load performance to a load-following mode. The three-year 

study examined a plant that had previously operated at 650 MW (rarely below 400 MW) and 

later operated with a normal minimum operating load near 150 MW. When the heat rate curve 

from a near-continuous load-day was compared to that for a transient load-day (four different 

steady loads), the shape and magnitude matched each other. Another study15 found that adding 

one startup-shutdown cycle caused the effective weekly heat rate to rise 0.62% for small 

subcritical coal-fired boilers, 0.44% for large subcritical coal-fired boilers and for supercritical 

boilers, and 0.20% in combined cycle plants.

Korellis16 listed ten different cost-effective upgrades that might be introduced at coal-fired units 

to improve heat rate during cycling operations:

1) Sliding-pressure operation (2% decrease in heat rate during part load)

2) Variable-speed drives for main cycle and auxiliary equipment

3) Boiler draft system control schemes and operating philosophy

4) Automated pulverizer supervisory controls and variations with mill design

5) Optimum partial-load operation of air quality control systems

6) Feedwater heater drain system modifications for cycling

7) Cooling system optimization

8) Performance monitoring

9) Reducing warm-up flow for idle boiler feed pumps

10) Minimizing flow, pressure, and temperature oscillations during cycling operation

The National Coal Council report shared typical heat rate improvements and capital costs for 

steam turbine improvements:

1) 10 Btu/kWh for hydrogen purity ($0.25M)

2) 50 Btu/kWh for partial arc admission ($1M)

3) 4 Btu/kWh for control valves

4) 50 Btu/kWh for HP steam seal upgrade ($1M)

5) 95-135 Btu/kWh for HP steam path upgrade ($6M)

14 Electric Power Research Institute, Product Abstract for Cycling and Load-Following Effects on Heat Rate, 

Product ID 1022061, July 18, 2011. Downloaded on November 25, 2014, from 

http://www.epri.com/abstracts/Pages/ProductAbstract.aspx?ProductId=000000000001022061. 15 Kumar, N., P. Besuner, S. Lefton, D. Agan, and D. Hilleman, Power Plant Cycling Costs, Report Number 

NREL/SR-5500-55433, National Renewable Energy Laboratory, April 2012.

16 Korellis, S., “Coal-Fired Power Plant Heat Rate Improvement Options, Part 1.” Power Magazine, November 1, 

2014. Downloaded on November 26, 2014, from http://www.powermag.com/coal-fired-power-plant-heat-rateimprovement-options-part-1/?printmode=1.

8

 
6) 20 Btu/kWh for IP steam seal upgrade ($1M)

7) 50-100 Btu/kWh for IP steam path upgrade ($5M)

8) 120 Btu/kWh for LP steam seal upgrade ($0.75M)

9) 65-225 Btu/kWh for LP steam path upgrade ($5M)

EPRI’s Range and Applicability Report (2014) listed several additional measures for the turbine 

island not found in the S&L Report but did not report potential cost. Those that would not 

overlap directly with the S&L Report findings include:

1) Running with a single circulation pump under favorable temperatures

2) Condenser ball cleaning system

3) Re-tubing condensers

4) Water box vacuum priming system

5) Circulating water strainers

6) Circulating water turbine

7) Steam seal upgrade

8) Steam path upgrade

9) LP turbine last-stage buckets

10) Exhaust hood steam guide modification

11) Rewind generator

12) Increasing hydrogen purity

13) Partial-arc admission

14) Sliding pressure (a 2% HRI was realized at part load)

2.1.4 Other Improvements

Labbe and Gordon17 described how a cooling tower advisory system was integrated into the NOx

and heat rate optimization system at a plant in such a manner that the pumps and fans would

optimize the net electricity generation. An hourly savings of 1205 kW was reported for a single 

month.

EPRI’s Range and Applicability Report (2014) listed several additional measures outside the 

boiler and turbine islands not found in the S&L Report but did not report potential cost. Those 

that would not overlap directly with the S&L Report findings include:

1) Replacement of first point heater (150 Btu/kWh)

2) Supplemental cooling towers

3) Deep lake water intake

4) Power supply upgrade for air pollution control equipment

17 Labbe, D., and L. Gordon, Continuous Performance Improvement in Power Generation: Optimization in Action, 

Invensys Operations Management, March 2011. Downloaded on November 25, 2014, from: 

http://iom.invensys.com/EN/pdfLibrary/WhitePaper_Invensys_ContinuousPerformanceImprovementInPowerGen

eration_03-11.PDF.

9

 
5) Upgrade air compressors

6) Plant lighting upgrade

The National Coal Council report18 also cites some additional heat rate improvements:

1) Up to 150 Btu/kWh for advanced process instrumentation and controls ($0.5-0.75M)

2) Low temperature heat recovery (air heater performance, feedwater preheating, and 

supplemental low temperature gas-side heat recovery)

3) 15-150 Btu/kWh for variable frequency drives ($9-11M for a 500-MW plant)

4) Up to 70 Btu/kWh in summers for replacing or augmenting the cooling tower pack ($1.5-

5M for a 500-MW plant)

5) 600-1200 Btu/kWh through a topping cycle addition (could be developed within 10 

years)

6) 300 Btu/kWh through a bottoming cycle with an organic solvent would supplant use of 

water for cooling (currently only used in small industrial processes)

Some common recommendations among the five plants in EPRI’s Range and Applicability 

Report also held potential for HRIs. These included:

1) Heat Rate Awareness training for operations staff (50 to 100 Btu/kWh)

2) Making heat rate information readily available to more plant personnel (50 to 150 

Btu/kWh)

3) Improving utilization of Controllable Losses information by operations staff (75 to 100 

Btu/kWh)

4) Initiating routine testing programs (75 to 200 Btu/kWh)

Hansel19 wrote that most plants already have the most advanced water treatment systems, so no 

opportunities were available there for HRIs.

2.2 Total HRI Studies

In contrast to studies that examined individual measures, some studies also compared overall 

plant heat rates and efficiencies. Selected information from a 2010 NETL report20 compares the 

average fleet efficiencies for different boiler segments against the 90th percentiles based on a 

weighting by generation (Table 2-3). Those differences (ranging from 1.8 to 4.2%) might 

represent a present-day level of possible HRIs that moves existing boilers toward higher 

performance levels.

18 National Coal Council, Reliable & Resilient: The Value of Our Existing Coal Fleet, May 2014. Downloaded from 

http://www.nationalcoalcouncil.org/NEWS/NCCValueExistingCoalFleet.pdf. The National Coal Council is a 

Federal Advisory Committee to the U.S. Secretary of Energy.

19 Hansel, Peter, Heat Rate Reductions and Carbon Emissions: A Policy Mechanism for Regulating Coal Plants 

under 111(d) of the Clean Air Act, April 22, 2014. Downloaded from 

http://dukespace.lib.duke.edu/dspace/bitstream/handle/10161/8508/Heat%20Rate%20Reductions%20and%20Car

bon%20Emissions%20-%20Peter%20Hansel%20MP%20Final.pdf?sequence=1 on November 25, 2014.

20 DiPietro, P. and K. Krulla, Improving the Efficiency of Coal-Fired Power Plants for Near Term Greenhouse Gas 

Emissions Reductions, DOE/NETL-2010/1411, National Energy Technology Laboratory, 2010. Downloaded on 

December 1, 2014, from http://netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/DOENETL-2010-1411-ImpEfficCFPPGHGRdctns-0410.pdf.

10

 
Table 2-3. 2010 NETL Assessment of Coal-Fired Power Plant Efficiencies

Segment Criteria Sub-population Characteristics Efficiency

Unit Type

Coal 

Type

Size 

(MW)

Capacity 

(GW) # Units

Generation 

(BkWh) Average

90th

Percentile Difference

Low 

Pressure 

Subcritical 

(600-1600 

psig)

Bit

0-200

10.3 127 44 29.6% 33.0% 3.4%

Sub-bit 4.6 59 26 27.5% 29.8% 2.3%

Other 0.6 7 2 27.4% 30.5% 3.1%

High 

Pressure 

Subcritical 

(1800-2600 

psig)

Bit

0-200 21.6 134 112 32.1% 34.8% 2.7%

200-500 33.4 103 189 32.8% 35.6% 2.8%

500+ 29.7 48 176 32.7% 35.0% 2.3%

Sub-bit

0-200 7.2 47 42 30.7% 32.5% 1.8%

200-500 31.2 97 191 31.4% 35.6% 4.2%

500+ 64.4 98 401 31.6% 33.8% 2.2%

Other 11.1 28 72 31.7% 35.1% 3.4%

Supercritical 

(3334+ psig)

Bit 60.7 79 372 35.1% 37.3% 2.2%

Sub-bit 15.0 20 90 35.2% 37.2% 2.0%

Other 8.1 13 55 31.8% 34.9% 3.1%

2.3 Associated Costs

Although most NETL publications since 2009 deal with newer technologies that affect plantwide heat rates (e.g., gasification and carbon capture), one subcontract report from NETL lists 

some costing estimates.21 Cases 9 and 11 list a breakdown of many costs associated with 

subcritical and supercritical coal-fired plants without carbon capture.

21 National Energy Technology Laboratory, Cost and Performance Baseline for Fossil Energy Plants Volume 1: 

Bituminous Coal and Natural Gas to Electricity, DOE/NETL-2010/1397, last updated in 2013. Downloaded on 

November 17, 2014 from 

http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/OE/BitBase_FinRep_Rev2a3_20130919_1.pdf.

11

 
3 Statistical Assessment of Heat Rates in the Plant Database

The EIA-860 and EIA-923 surveys reveal a great deal about plant operations, as well as some 

specific information about generators and boilers. These surveys may also be supplemented by 

annual information collected by the U.S. Environmental Protection Agency (EPA). EIA uses the 

net generation data (gross generation minus parasitic load) and heat input information for fossilfuel boilers to compute net annual heat rates for each generator over a five-year period. For the 

coal-fired units, the 2012 heat rates varied from 8759 to 25,000 Btu/kWh at 1027 generators for 

which a single boiler could be matched.22

This chapter describes an analysis of the heat rates for coal-fired boilers as part of an effort to 

understand how the EIA data might be used to identify units that could implement improvements 

in future years. This work may support EIA modeling efforts that aim to choose between 

installing unit improvements and retiring existing units. Other chapters consider the costs, but 

this chapter focuses on projecting the deviation of existing heat rates from heat rates at units of 

similar design.

3.1 Data Processing

The basis for this work is the AEO2014 Plant File Inputs (AEO2014 plant listing inputs.xls) that 

share data records from plants online in 2012 (15,993 records). Of these data, 1084 records 

applied to the coal-fired EFD plant types (CAV, CSC, and CSU)23, and each record is associated 

with a particular generator. According to Assumptions and Updates to the AEO 2014 Plant File, 

the heat rates represent the net generation divided by the heat input to the associated boiler (over 

a five-year period). EIA uses a heat rate ceiling of 25,000 Btu/kWh in its calculations.

An EIA-860 file (EnviroAssocY2012.xlsx) provides crosswalks to match the generator IDs to 

individual boiler IDs. The file also provides crosswalks to tie boiler IDs to the cooling system 

IDs, FGD system IDs, and FGP collection system IDs.

The data were provided from multiple sources and matched based on plant and boiler ID codes:

• EIA-923 schedules (2012 data)

• EIA-860 surveys

• EPA eGRID 9th edition (2010 data)

• EPA Clean Air Markets Database (2012 data from ampd.epa.gov/ampd/)

Data were generally provided as plant level, boiler level, or generator level records, but some 

information was listed in multiple records for the plants (e.g., monthly mine fuel receipts). The 

composite database held more than 200 fields, but many of the parameters were not expected to 

correlate at all with heat rates (e.g., cooling water outlet distance from the shore) and were 

excluded from further consideration.

3.2 General Data Population Characteristics

Table 3-1 describes the numeric variables that were included in the study.

22 As per EIA direction, 57 combined heat and power units were excluded from the analysis.

23 These plant types represent three existing coal-fired technologies: CAV = New Advanced Coal; CSC = Coal 

Steam with Scrubber; and CSU = Coal Steam post-1965.

12

 
Table 3-1. Distribution of Numeric Parameters Associated with Coal-Fired Generators

Variable Number of 

data points

Percentage 

of missing 

points

Average Standard 

Deviation Minimum 25th percentile

50th 

percentile

75th 

percentile Maximum

Heatrate (Btu/kWh) 1027 0% 11,300 2,400 8,759 10,247 10,644 11,287 25,000

CAMD2012 heatrate (Btu/kWh) 858 16% 10,200 1,100 7,311 9,473 10,008 10,660 18,474

SummerCapacity (MW as listed 

in EPA CAMD2012)

1027 0% 294 250 1 100 200 476 1,300

Online Year 1027 0% 1970 14 1944 1958 1969 1979 2012

Variable O&M ($/MWh) 1027 0% 2.60 1.50 0.58 1.46 2.23 3.33 11

Annual Fixed O&M ($/KW) 1027 0% 47 18 7 33 44 60 98

Annual Capital Additions 

($/KW)

1027 0% 18 31 0 4 11 21 330

Heat Input (MMBtu) 869 15% 19,000,000 18,000,000 1,251 4,525,293 12,519,851 32,227,304 95,309,144

Gross Load (MWh) 860 16% 2,000,000 1,900,000 0 444,604 1,229,583 3,357,001 10,039,827

Nameplate Capacity (MW) 1027 0% 350 290 4 114 253 578 1,426

Generator Summer Capacity 

(MW)

1027 0% 330 270 0 103 232 531 1,300

Generator Winter Capacity 

(MW)

1027 0% 330 270 0 103 235 543 1,300

Planned Retirement Year 203 80% 2015 2 2012 2014 2015 2015 2021

FGD In-service Year 491 52% 1999 13 1971 1985 2007 2010 2019

Pond Landfill Requirements

(Acre-Foot per Year)

339 67% 160 270 0 19 77 200 2,714

Specs of Coal Ash 463 55% 12% 5% 0% 10% 10% 10% 40%

Specs of Coal Sulfur 463 55% 0% 1% 0% 0% 0% 0% 10%

FGD Trains Total 467 55% 2 2 1 1 1 3 12

FGD Trains 100% 454 56% 2 1 1 1 1 3 10

FGD Sulfur Removal Efficiency 475 54% 93% 10% 50% 90% 100% 100% 100%

Sulfur Emission Rate (lbs per hr) 473 54% 1500 1800 0 352 743 1,858 9,999

FGD Cost Structure ($K) 410 60% 130,000 200,000 21 27,982 62,224 177,084 1,445,626

FGD Disposal Cost ($K) 276 73% 14,000 26,000 1 1,776 5,663 14,475 223,438

FGD Other Cost ($K) 196 81% 45,000 152,000 10 470 13,700 34,500 1,938,000

FGD Cost Total ($) 460 55% 159,000 203,000 21 37,738 92,481 236,861 1,503,972

Quantity of FGD Sorbent 390 62% 64 68 0 13 39 98 353

13
Variable Number of 

data points

Percentage 

of missing 

points

Average Standard 

Deviation Minimum 25th percentile

50th 

percentile

75th 

percentile Maximum

FGD Electrical Consumption 389 62% 56,000 64,000 0 12,667 37,120 70,680 408,706

FGD Efficiency at Annual 

Operating Factor

409 60% 90 13 0 89 95 97 100

FGD Efficiency at 100% 337 67% 92 11 0 90 95 98 100

FGD Chem Cost 368 64% 2,400 3,600 0 448 1,303 2,842 27,633

FGD Labor Cost 368 64% 1,100 1,400 0 261 652 1,298 10,370

FGD Waste Cost 344 67% 680 1,100 0 23 289 786 8,327

FGD Maintenance Material 

Other

362 65% 1,200 1,600 0 350 751 1,594 17,880

Total O and M 375 63% 5,200 5,700 0 1,748 3,760 6,835 36,644

No FGD Control 73 93% 0 0 0 0 0 0 1

FGP Inservice Year 883 14% 1981 11 1949 1975 1979 1985 2012

FGP InstalledCost ($K) 873 15% 16.000 26,000 1 2,630 8,390 19,900 267,000

FGP Collection Efficiency 883 14% 99% 1% 80% 99% 100% 100% 100%

Emission Rate (lbs per hr) 883 14% 190 230 0 45 108 250 2,120

FGP Hours In Service 864 16% 5,700 2,600 0 3,998 6,793 7,757 8,760

Cooling System In-service Year 848 17% 1970 14 1924 1958 1970 1979 2012

Intake Rate at 100% (Cubic Feet 

per Second)

844 18% 450 670 1 27 212 535 4,711

Number of Federal Air Pollution 

Programs 24

886 14% 6 2 1 5 6 7 8

24 This variable is a straight count of the number of programs identified by the nominal parameter programs listed in Table 3-3.

14

 
Some additional numeric fields describing cooling systems were not included in the 

computations in order to reduce the analysis burden: Chlorine Inservice Year, Pond Inservice 

Year, Pond Volume (Acre Feet), Tower Inservice Year, Tower Water Rate (Cubic Feet per 

Second), Cooling System Power Requirement (MW), Cost Ponds (Thousand Dollars), Cost 

Towers (Thousand Dollars), and Cost Chlorine Equipment (Thousand Dollars). 

The correlations among the numeric values were compared, and those with correlation 

coefficients greater than 0.6 are presented in Table 3-2. Table 3-2 clearly points to redundancies 

when the heat inputs, gross loads, and capacities are used.

Table 3-2. Numeric Parameter Pairs with Correlation Coefficients with Absolute Values 

Greater than 0.60

Parameter 1 Parameter 2 Correlation 

Coefficient

Heat Rate (Btu/kWh) Variable O&M ($/MWh) 0.63

Summer Capacity (MW from the EPA 

CAMD2012 database)

Variable O&M ($/MWh) -0.61

Heat Input (MMBtu) 0.77

Gross Load (MWh) 0.77

Nameplate Capacity (MW) 0.89

Generator Summer Capacity (MW) 0.90

Generator Winter Capacity (MW) 0.90

Online Year

Heat Input (MMBtu) 0.62

Gross Load (MWh) 0.61

Cooling System Inservice Year 0.95

Variable O&M ($/MWh)

Annual Fixed O&M ($/kW) 0.67

Heat Input (MMBtu) -0.66

Gross Load (MWh) -0.66

Nameplate Capacity (MW) -0.68

Generator Summer Capacity (MW) -0.67

Generator Winter Capacity (MW) -0.67

Heat Input (MMBtu)

Gross Load (MWh)

Nameplate Capacity (MW)

Generator Summer Capacity (MW)

Generator Winter Capacity (MW)

1.00

0.89

0.90

0.90

Gross Load (MWh)

Nameplate Capacity (MW) 0.90

Generator Summer Capacity (MW) 0.90

Generator Winter Capacity (MW) 0.90

Nameplate Capacity (MW) Generator Summer Capacity (MW) 1.00

Generator Winter Capacity (MW) 1.00

Generator Summer Capacity (MW) Generator Winter Capacity (MW) 1.00

Planned Retirement Year FGD Cost Structure ($K) -0.66

FGD Disposal Cost ($K) -0.64

FGD Trains Total FGD Trains at 100% 0.97

FGD Cost Structure ($K) FGD Cost Total ($) 0.96

FGD Efficiency at Annual Operating 

Factor FGD Efficiency at 100% 0.68

FGD Chemical Cost FGD Total O&M 0.87

FGD Waste Cost FGD Total O&M 0.61

FGD Maintenance Material Other FGD Total O&M 0.63

15
In addition to the numeric parameters, Table 3-3 lists the nominal and logical parameters that 

were considered as generator/boiler/plant characteristics that might affect heat rate. Table 3-3

also shows some consolidated variables that were evaluated in cases where entries could be 

grouped.

Table 3-3. Nominal and Logical Characteristics Considered in this Study

Variable Number of 

Blanks Populated Entries

NEMS EFD Plant Type 0 CAV, CSC, CSU

NEMS ECP Plant Type 25 0 B1, B3, B5, B7, C1, C4, C7, CX, H1, H4, H7, IG

Programs 141 Combination of the entries CAIRNOX, CAIROS, CAIRSO2, 

RGGI, TRNOX, TRNOXOS, TRSO2G1, and ARP

Fuel Type (Primary) 141 Coal, Coal, Pipeline Natural Gas

Operating Status 141 Operating, Operating (Started 01/24/2012)

NOx Control Status 66 CN, CO, NA, OP, OS, OZ, RE, SB, SC, TS

Low NOx Process 1 66 AA, CF, FU, H20, LA, LN, NA, OT, OV, SN, SR

Low NOx Process 2 390 AA, BF, CF, FU, LA, LN, OT, OV, SN, SR

Low NOx Process 3 785 AA, FU, LA, LN, NH3, OT, OV, SN, SR

Mercury Emission Control 66 Y, N

Prime Mover 0 CA, CT, ST

GenStatus 0 OA, OP, OS, RE, SB

Multiple Fuels 0 Y, N

Turbines 1,016 1

Cogenerator 0 Y, N

Sector Name 0 Electric Utility, IPP Non-CHP

Topping or Bottoming 991 B, T

Duct Burners 304 N

Planned Modifications 33 Y, N

Planned Uprate Year 1,019 2013, 2014, 2016, 2017

Planned Derates Year 1,014 2013, 2014, 2015, 2016, 2017

Planned New Prime Mover 1,026 ST

Planned Repower Year 1,018 2013, 2014, 2015, 2016, 2017

Other Modifications Year 1,004 2013, 2014, 2015, 2018

Solid Fuel Gasification System 89 Y, N

Pulverized Coal Technology 112 Y, N

Fluidized Bed Technology 974 Y, N

Subcritical Technology 348 Y, N

Supercritical Technology 876 Y, N

Ultrasupercritical Technology 1,023 Y, N

Carbon Capture Technology 1,024 Y, N

FGD Status 536 CN, CO, OP, OS, PL, RE, SB, SC

FGD Type 1 541 BR, CD, DP, OT, PA, SD, SP, TR, VE

FGD Type 2 986 PA, SP, TR, VE

FGD Type 3 1,026 VE 

FGD Type 4 1,027 none 

Sorbent Type 1 554 AF, DB, DL, LA, LF, LI, LS, OT, SA, SB, SC, SL

Sorbent Type 2 987 DB, DL, LI, MO, SC, SF

Sorbent Type 3 1,026 DB 

25 ECP types defined on page vii.

16

 
Variable Number of 

Blanks Populated Entries

Sorbent Type 4 1,027 none 

FGDByproductRecovery 554 Y, N

Sludge Pond Lined 555 Y, N, NA 

Flue Gas Bypass FGD 554 Y, N

FGP Status 144 OP, OS, SB, SC 

FGPCollectorType1 144 BP, BR, BS, EC, EH, EK, EW, MC, OT, WS

FGPCollectorType2 889 BP, BR, EC, EK, EW, MC, OT, WS

FGPCollectorType3 1,011 EK, MC, SC, WS

No FGP Control 972 ., 0, 1

Cooling Status 179 OP, OS, SC

Cooling Type 1 179 DC, HRF, OC, ON, OT, RC, RF, RI, RN

Cooling Type 2 972 HT, OC, ON, OT, RC, RF, RI, RN 

Cooling Type 3 1,022 RI 

Cooling Type 4 1,027 none

Tower Type 1 658 MD, MW, NW, WD 

Percent Dry Cooling 998 0%, 100% 

Unit Type 141

Bubbling fluidized bed boiler, Cell burner boiler, Circulating 

fluidized bed boiler, Cyclone boiler, Dry bottom turbo-fired 

boiler, Dry bottom vertically-fired boiler, Dry bottom wallfired boiler, Dry bottom wall-fired boiler (Started Jan 24, 

2012), Tangentially-fired, Wet bottom turbo-fired boiler, 

Wet bottom wall-fired boiler

Firing Type 136

CELL, CYCLONE, DRY FRONT/WALL, DRY 

OPPOS/WALL, DRY STOKER, DRY TANGENTIAL, 

DRY TURBO, DRY VERTICAL, DRY WALL, 

FLUIDIZED, TANGENTIAL, WET TURBO, WET WALL

Fuel Type 103 BIT, LIG, SUB, WC 

Firing Class (consolidation of 

Firing Type variable) 136 Bottom-fired, Dry Wall-fired, Tangential-fired, Wet-bottom 

Low NOx Summary 1 and 

Low NOx Summary2 

(consolidation of Low NOx 

Process variables)

66

390

Combustor, Injection, Recirculation, Reduction, Other

FGP Collector Summary1 

(consolidation of 

FGPCollectorType1)

144

Baghouse, Cyclone, ESP, WetScrubber, Other 

3.3 Influence of Nameplate Capacity on Heat Rate

Leidos conducted a preliminary investigation of plotted heat rates versus some of the parameters 

listed in Table 3-1 and Table 3-3; the selected parameters were chosen primarily with regard to 

the distributions found in the data set and the fractions of missing data. Relationships were

easier to identify and more linear when the variables were compared to the inverse heat rate, a 

measure of unit efficiency. However, the influences of most individual variables still appeared 

small against the inverse heat rates that varied from 40 to 114 kWh/MMBtu.

17
Therefore, the preliminary investigation included application of the M5P algorithm26 to develop 

a piecewise linear regression model. A piecewise approach would allow subsets of the inverse 

heat rates to be evaluated separately against the various parameters, and the algorithm would 

identify those parameters with the most influence on the inverse heat rates. Using a leave-oneout approach for evaluating the model performance, the Weka Explorer software executed the 

M5P algorithm to predict inverse heat rate with a correlation coefficient of 0.83 and a relative 

absolute error of just 54%. Roughly thirty parameters were used in the four piecewise linear 

models that were divided as shown in Figure 3-1. The numbers in parentheses represent the 

number of records followed by the relative absolute errors for the data subset. Those in the 

largest group (627 records) had nameplate capacities greater than 181 MW and a relative 

absolute error of only 32%; the predictive ability was much lower for those with nameplate 

capacities less than 106 MW.

Figure 3-1. Preliminary Decision Tree for Describing Inverse Heat Rates

of Coal-Fired Generators

The decision tree suggested that different linear dependences would be evident if the predicted 

inverse heat rates were plotted relative to the nameplate capacity (Figure 3-2). Figure 3-2

illustrates that the inverse heat rates were highly dependent on nameplate capacity at low 

nameplate capacities and less so as the nameplate capacity increased.27 Figure 3-2 also illustrates 

the best linear fits for the data.

More efficient plants are found for the generators with higher nameplate capacities, but this 

finding is not very useful for studies into finding ways to increase plant efficiencies. A 

transformation to mask the dependence of inverse heat rates on nameplate capacity might reveal 

the influences of various equipment types on the plant efficiencies.

26 The M5P (or M5’) algorithm represents a 1997 improvement of Quinlan’s original M5 algorithm (1992). It builds 

piecewise linear regression models of numeric data, but may use nominal, ordinal, and logical parameters within 

the model tree and within the regression equations.

27 Such behavior may have indicated a logarithmic dependence on nameplate capacity, but logarithmic evaluations 

did not fit the data well.

18

 
Figure 3-2. Preliminary Relationship between Nameplate Capacity and

Predicted Inverse Heat Rates

3.4 Slope Function Analysis

The three linear fits shown in Figure 3-2 suggest that the inverse heat rate data may be 

transformed to a variable referred to as the dimensionless slope function:

Slope function =

⎩

⎪

⎪

⎨

⎪

⎪

⎧ inverse heat rate

0.262 × NPC + 61.4

where NPC ≤ 106 MW

inverse heat rate

0.045 × NPC + 90.5 where NPC ≥ 106 MW

inverse heat rate

0.0071 × NPC + 93.1

where NPC > 181 MW

and NPC < 181 MW

Where, NPC represents the nameplate capacity. The numerators are surrogates for actual 

efficiencies, and the denominators represent the average efficiency for generators of similar 

sizes. The Slope Function is a dimensionless parameter. Records with slope functions greater 

than one represent generators that perform better than units of similar size, and those with slope 

19
functions less than one underperform. Figure 3-3 illustrates the distribution of the Slope Function 

parameter.

Figure 3-3. Histogram Showing the Distribution for the Slope Function Transformation

The M5P algorithm could generate models for Slope Function that had correlation coefficients as 

high as 0.5, but no single parameter strongly influenced the Slope Function parameter. Some 

further data cleaning was deemed necessary to be sure that variables were being treated properly.

An attribute evaluation determines the parameters that the target parameter is most heavily 

dependent on but are independent of one another. Four runs were made using the Weka 

AttributeEvaluator on the preliminary data sets to determine which variables most influence the 

Slope Function variable and are independent of other variables. The CfsSubsetEval algorithm 

selectively chooses the parameter sets that are highly correlated with the various classifications 

but have low intercorrelation, but the Wrapper[M5Rules] algorithm also uses cross validation to 

estimate the accuracy of the M5Rules algorithm with each subset of parameters.28 The results 

yielded the following list of variables with at least an occurrence in one run (Table 3-4):

28 The CfsSubsetEval and Wrapper[M5Rules] evaluators were paired with two different methods to search for a 

good subset of the data attributes: BestFirst and GreedyStepwise. The BestFirst method allows backtracking in the 

search when the subsetting stops improving, but the GreedyStepwise method stops the search when inclusion of 

the next attribute would decrease the evaluation matrix.

0

50

100

150

200

250

300

350

Number of Records

Slope Function

20

 
Table 3-4. Results from the AttributeEvaluator Showing Those Variables That Most 

Influence the Slope Function Variable and Are Independent of Other Variables

Parameter CfSSubsetEval Wrapper[M5Rules]

NEMS EFD Plant Type ● ●

Primary fuel classification (Bituminous, subbituminous, lignite, or waste coal) ●

Annual Capital Additions ($/kW) ●

Variable O&M ($/MWh) ●

Nameplate Capacity (MW) ●

Low NOx Process 2 ●

Mercury Emission Control (Y or N) ● ●

Generator status (operating, out of service, retired, 

etc.) ●

Planned Retirement Year (2012 through 2021) ● ●

Solid Fuel Gasification System (Y or N) ●

Subcritical Technology (Y or N) ●

FGD Type 1 ●

FGP Status ●

FGPCollectorType1 ●

Cooling Status ●

Number of Federal Air Pollution Programs (0 to 8 

and may act as a geographic surrogate) ●

Some of these parameters that were deemed significant by the AttributeEvaluator did not seem to 

have enough records to be considered influential in the model development. For example, the 

Planned Retirement Year parameter is missing in 80% of the records, but the model had been 

replacing that missing data by the mode value of 2015. Therefore, the missing data were recoded 

for Planned Retirement Year to reflect a condition that no retirement date was yet planned.

The AttributeEvaluator was again run to determine the dependences of Slope Function on the 

revised variables with three trials (BestFirst+CfsSubsetEval, GreedyStepwise+CfsSubsetEval, 

and GreedyStepwise+ Wrapper[M5Rules]); the fourth case did not converge. The results yielded 

the following list with at least an occurrence in one run:

• NEMS EFD Plant Type

• Primary fuel classification (Bituminous, sub-bituminous, lignite, or waste coal)

• Annual Capital Additions ($/KW)

• Variable O&M ($/MWh)

• Nameplate Capacity (MW)

• Low NOx Process Summary 2

• Mercury Emission Control (Y or N)

• Generator status (operating, out of service, retired, etc.)

• Solid Fuel Gasification System (Y or N)

• Pulverized Coal Technology (Y or N)

• Subcritical Technology (Y or N)

21
• FGD Status

• FGD Type 1

• FGP Status

• FGPCollectorType Summary 1

• Cooling Status

• Number of Federal Air Pollution Programs (0 to 8 and may act as a geographic 

surrogate)

Using only these variables, a “leave-one-out-approach” was again used with the M5P algorithm 

to predict Slope Function, and the minimum number of records for a decision tree leaf was 

varied from 4 to 40. The error summaries were similar with correlation coefficients ranging from 

0.50 to 0.53. 

However, there was still a question about reported data that may be influenced by neighboring 

equipment. For example, two generators at the PPL Montour plant use Boiler 1 with nameplate 

capacities of 17.2 and 805.5 MW. The Slope Function value for the smaller generator is 1.6 (not 

shown in Figure 3-3) because it operates 60% more effectively than similarly sized generators. 

All data with slope functions more than 3 standard deviations from the average (less than 0.70 or 

greater than 1.26) were filtered and the model rerun. The data fits did not improve, illustrating 

that removal of outliers did not improve the model performance.

In the Attribute Selector, the one scheme that operated with the M5P subsetting approach 

(GreedyStepwise+ Wrapper[M5Rules]) had yielded the following selection of variables to 

describe the Slope Function:

• NEMS EFD Plant Type

• Primary fuel classification (Bituminous, sub-bituminous, lignite, or waste coal)

• Nameplate Capacity (MW)

• Pulverized Coal Technology (Y or N)

• Subcritical Technology (Y or N)

• FGD Status (Cancelled, New under construction, Operating, Out of service, 

Planned, Retired, Standby, or Cold Standby)

• FGPCollectorType Summary 1 (Baghouse, Cyclone, ESP, WetScrubber, or 

Other)

These seven variables were used with the M5P classifier algorithm to yield a seven-rule model 

that is dependent on this smaller number of parameters and yields a correlation coefficient of 

0.49. This is only a mild improvement to the model that had been based only on nameplate 

capacity, but the model points to physical plant data that might influence heat rates. 

Figure 3-4 illustrates the decision tree and the seven linear regression models that can be used to 

fit the Slope Function. For example, the two rules in the lower left of the figure show that the 

slope function increases by 0.07 or 0.09 if bituminous fuel is used (instead of lignite). The full 

models included additional parameters, but only those shown in the figure altered the tenths or 

hundredths place on the calculated Slope Function. 

22
Figure 3-4. Decision Tree to Describe the Slope Function Using the

M5P Piecewise Linear Regression Model

3.5 Model Predictions of Heat Rate

In the previous sections, the Slope Function was defined as a ratio of the inverse heat rate 

(kWh/mmBtu) to a linear function of the nameplate capacity. Therefore, the predicted heat rates

may be computed by the expression:

Heat rate � Btu

kWh� =

⎩

⎪

⎪

⎪

⎨

⎪

⎪

⎪

⎧ 106

(0.262 × NPC + 61.4)(Slope function) where NPC ≤ 106 MW

106

(0.045 × NPC + 90.5)(Slope function) where NPC ≥ 106 MW

106

(0.0071 × NPC + 93.1)(Slope function) where NPC > 181 MW

and NPC < 181 MW

Where, the Slope Function is found in Figure 3-4 on each of the seven leaves of the decision tree. 

To ensure that the spectrum of data points is still easily visible, Figure 3-5 presents the inverse of 

the reported heat rates versus the predicted data points. The best linear fit has an r2 correlation 

coefficient of 0.624 with a slope of 0.987, and the red dashed lines show slopes corresponding to 

a 50% confidence interval. Generators to the left of the lines have lower efficiencies than similar 

units and represent the generators with the greatest likelihood that the operations can be 

improved.

23
Figure 3-5. Comparison of Reported and Predicted Inverse

Heat Rates for All Generators

3.6 Generator Units that Most Likely Can Improve Heat Rates

The generator units in Figure 3-5 can be categorized as follows: Q4) fall to the left of the three 

lines (least efficient compared to predicted values); Q3) fall to the right of the first red line and to 

the left of the blue line (third quartile); Q2) fall to the right of the blue line and to the left of the 

second red line (second quartile); and Q1) fall to the right of all three lines (most efficient 

compared to the predicted values). The predicted values are already dependent on the unit sizes, 

fuel types, and installed control devices.

Figure 3-6 presents the fractions of occurrences in each of these quartiles for the different leaves 

in the decision tree. The figure illustrates that Quartile 1 (those generators with the lowest

reported heat rates (highest efficiencies) compared to the predicted heat rates) represents the 

majority of the generators with nameplate capacities under 181 MW. Generators with nameplate 

capacities under 181 MW also represent 86% of the Quartile 1 generators, suggesting that the 

smallest generators have the least room for improvements.

24
Figure 3-6. Quartiles Comparing Reported Heat Rates to Predicted Heat Rates

The worst data (Quartile 4) shows reported heat rates that are higher than the predicted heat 

rates. The majority of the Quartile 4 data is represented by the decision tree leaf in Figure 3-6 for 

generators with nameplate capacities between 181 and 607 MW that are associated with 

bituminous coal or lignite firing. This statistical observation suggests that finding further heat

rate improvements at those plants (with nameplate capacities between 181 and 607 MW that are 

associated with bituminous coal or lignite firing) would be easiest.

In this statistical manner, with the assumption that the least costly measures have already been 

implemented, Figure 3-6 suggests that the most costly HRIs (on a per-MWh basis) in future 

years would be expected at the plants with nameplate capacities less than 181 MW. The least 

costly heat rate improvements that could be made in future years would be at generators with 

nameplate capacities between 181 and 607 MW that are associated with bituminous coal or 

lignite firing. The two leaves in the lower right corner (sub-bituminous coal with nameplate 

capacities over 181 MW) would offer interim costs in future years because their data lie 

primarily in Quartiles 2 and 3.

25
4 Interpretation of Quartile Data

The previous chapter describes how the quartile information was generated, and this chapter 

compares the measurements and configurations associated with the quartiles. The quartile 

designations were based on how well the reported heat rates aligned with the predicted heat rates 

from similar units. When the reported heat rate/predicted heat rate was less than 0.94, the data 

appear in Quartile 1 (best performance relative to similar units). When the reported heat 

rate/predicted heat rate was greater than 1.04, the data appear in Quartile 4 (worst performance 

relative to similar units). Figure 4-1 shows the counts across the quartiles for the different ratios. 

The full data set can be fit by a normal distribution curve, but the data from the individual 

quartiles cannot.

Figure 4-1. Distribution of Units across the Quartiles for Reported

Heat Rate/Predicted Heat Rate Ratio

The means and standard deviations for the numeric parameters are shown in Table 4-1 for the 

four quartiles. Note that the standard deviations only give a sense of the data variability, but do 

not imply a normal distribution of the data within any of these quartile subsets. In particular, 

Quartiles 1 and 4 often represent a single tail of a data set.

Of particular note in Table 4-1 is that the average EIA-reported heat rates are higher than those 

reported in the EPA CAMD data set for all four quartiles. The EIA-reported heat rates are a 

composite from five years of data,29 but the EPA CAMD data set represents just 2012. 

Nationally the year 2012 had more cooling degree days than any other year from 2006 through 

29 Email correspondence from Eric Krall of EIA on November 7, 2014.

26

 
Table 4-1. Distributions of Numeric Parameters among the Quartiles

Quartile 1 (best) Quartile 2 Quartile 3 Quartile 4

Measured Parameters

Heat Rate (Btu/kWh) 11,200 ±1,400 10,700±1,100 10,800±1,400 12,600±3,800

CAMD 2012 Heat Rate 

(Btu/kWh)

10,400±1,200 9,900±900 10,000±1,100 10,300±1,200

Online Year 1964±16 1972±15 1974±12 1970±12

Variable O&M Cost ($/MWh) 3.5±1.5 2.0±1.0 2.0±1.2 2.8±1.6

Annual Fixed O&M Cost 

($/kW)

55 ±19 42±16 43±17 48±18

Annual Capital Additions 

($/kW)

16±31 19±37 17±20 20±34

Heat Input (billion Btu) 5,500 ±7,400 24,000± 18,000 28,000± 19,000 17,000±14,000

Gross Load (GW-h) 550±790 2,500± 2,000 2,900± 2,000 1,700±1,500

Nameplate Capacity (MW) 150 ±170 430±290 510±290 330 ±250

FGD In Service Year 1981±12 1983±12 1982±11 1980±10

FGD Cost Total ($K) 130,000±140,000 160,000±130,000 170,000±250,000 160,000±220,000

FGD Total O&M Cost ($K) 4,100±3,700 4,200±3,300 5,700±7,400 5,800±5,400

FGP In Service Year 1981±12 1983±12 1982±10 1980±10

FGP Installed Cost ($K) 8,200 ±15,600 18,000 ±21,000 26,000±39,000 13,000±15,000

FGP Emission Rate (pounds 

per hour)

99 ±180 180±200 250±240 210±260

FGP Hours In Service 4,100 ±3,000 6,600±2,100 6,400±2,300 5,400±2,500

Cooling System In 

ServiceYear

1963±16 1973±15 1974 ±12 1970 ±11

Intake Rate at 100% (cubic 

feet per second)

520±720 480±610 370±700 440±660

Number of Federal Air Quality 

Programs

4.5±3.0 4.9±2.6 4.8±2.6 4.9±2.8

Computational Parameters

NPC term in “Slope Function 

Analysis”

88±12 95±6 95±8 91±11

Slope Function (reported) 1.04±0.10 0.99±0.05 0.98±0.04 0.92±0.11

Slope Function (predicted) 0.93±0.07 0.97±0.05 1.00±0.05 1.01±0.07

Predicted Heat Rate 

(Btu/kWh)

12,600±1,800 11,000±1,200 10,700±1,400 11,000±2,500

Number of Missing Data 

Reports Used for Predictions

1.2±0.8 0.7±0.7 0.5±0.7 0.7±0.8

Reported Heat Rate/Predicted 

Heat Rate

0.89±0.04 0.97±0.01 1.01±0.01 1.11±0.11

Inverse Heat Rate Reported 

(kWh/MMBtu)

91±10 95±8 94±9 84±16

Inverse Heat Rate Predicted 

(kWh/MMBtu)

81±10 92±8 95±9 92±14

2013,30 so the EPA CAMD rates may reflect that units were operated closer to capacity in 2012 

than in some other years.

30 National Weather Service Climate Prediction Center, Degree Days Statistics. Downloaded on November 11,

2014, from http://www.cpc.ncep.noaa.gov/products/analysis_monitoring/cdus/degree_days/.

27

 
Among the measured numeric parameters in Table 4-1, the four quartile means only show a 

consistent trend for a single parameter, FGD [flue gas desulfurization] Total O&M Cost. The 

means show a significant step (from $4.2M to $5.7M) when moving from Quartile 2 to 3, but the 

standard deviations are on the same order of magnitude as the means (indicating significant 

uncertainty). When the FGD Total O&M Cost was normalized for nameplate capacity or for heat 

input, the same trend toward rising costs with increasing quartiles was not observed. Only 367 

records were populated and are reflected in this comparison (36 from Quartile 1, 92 from 

Quartile 2, 135 from Quartile 3, and 104 from Quartile 4), so more information about the other 

plants could help investigators understand the importance that this parameter might have on plant 

efficiency.

The subsections below discuss some observations about the distribution of parameters among the 

quartiles, including cases where the single parameters did not place the data in alternate quartiles 

(i.e., affect relative performance). A previous study31 found that relationships between single 

parameters (e.g., subcritical versus supercritical boilers) were often confounded by other 

competing factors. For example, almost all the highly efficient supercritical boilers were built 

between 1967 and 1980, affecting the heat rates for units built around that time but with high 

operational costs.

4.1 Subcritical Versus Supercritical Boilers

Only 17 records were labeled as “N” for subcritical, and 560 others were labeled as “Y.” This 

wide disparity in record numbers gives at least one explanation why the models did not use this 

parameter in developing their descriptions. 

Staudt and Macedonia cite subcritical boilers as having higher heat rates than supercritical ones, 

but the examination of reported net heat rates showed no difference between supercritical and 

subcritical boilers. Staudt and Macedonia speculate that the older age of operating supercritical 

boilers might mean that more up-to-date technologies could replace the older ones at these 

plants. However, they did not investigate which equipment had been updated. This speculated 

opportunity was not evident in the Leidos data analysis: eleven of the seventeen supercritical 

units fell into Quartiles 1 and 2.

4.2 States

Of the states with at least ten generator records in the database, Table 4-2 shows which had a 

majority of records in any given quartile. These state rankings are deceptive in that one might 

think that the heat rates for New York are better than those in Maryland. However, Figure 4-2

shows that the mean of the New York heat rates for the seven Quartile 1 generators are actually 

higher than those for the means for Quartile 4 generators in Maryland. 

Table 4-2. States Whose Generators Mostly Fall into a Single Quartile

Quartile 1 (best) Quartile 2 Quartile 3 Quartile 4 (worst)

New York (7/13) Wyoming (13/24) Arkansas (8/13)

Oklahoma (5/10)

West Virginia (14/28)

Maryland (10/13)

31 Staudt, J.E. and J. Macedonia, “Evaluation of Heat Rates of Coal Fired Electric Power Boilers,” Power Plant 

Pollutant Control “Mega” Symposium, Baltimore, Maryland, August 2014.

28

 
Figure 4-2. Comparisons of Heat Rates for Select Data Subsets by State and Quartile

Maryland’s generators may have had higher 2012 heat rates calculated by EIA during the 

implementation of Maryland’s Healthy Air Act when new control devices began operation at 

these particular plants (2009-2013).32 The CAMD rates, based on just 2012, align more closely 

with the predicted rates in Maryland. 

4.3 ECP Plant Types

With regard to plant types,33 Table 4-3 describes the disposition of the different classifications 

among the quartiles. Figure 4-3, Figure 4-4, and Figure 4-5 show how the various controls 

appear in the four quartiles. More than 70% of the units in Quartile 1 did not have FGD controls 

(Figure 4-3), more than 60% of the units in Quartile 1 did not have SCR controls (Figure 4-5), 

but particulate controls were included on almost every Quartile 1 unit (Figure 4-4).

32 The Maryland Healthy Air Act, Maryland Department of the Environment. Downloaded from 

http://www.mde.md.gov/programs/Air/ProgramsHome/Pages/air/md_haa.aspx on November 11, 2014.

33 ECP types defined on page vii.

29

 
Table 4-3. Distribution of ECP Plant Types among Quartiles

Particulate 

Control Baghouse Cold-Side ESP Other/None

Integrated 

Other Gasification

Controls

No 

FGD

Wet 

FGD, no 

SCR

Wet 

FGD, 

SCR

Dry 

FGD

No 

FGD

Wet 

FGD, no 

SCR

Wet 

FGD, 

SCR

Dry 

FGD

No 

FGD

Wet 

FGD, no 

SCR

Wet 

FGD, 

SCR

Quartile 1 (best

efficiency 

relative to 

prediction)

32 13 5 27 148 15 11 1 1 1 -- 3

Quartile 2 15 24 6 25 110 27 36 1 6 6 -- --

Quartile 3 18 16 11 21 69 32 71 6 4 6 3 --

Quartile 4 

(worst

efficiency 

relative to 

prediction)

20 15 6 9 99 39 51 7 10 -- 1 --

Grand Total 85 68 28 82 426 113 169 15 21 13 4 3

Figure 4-3. Distribution of FGD Type among the Quartiles

30
Figure 4-4. Distribution of Particulate Control Types among the Quartiles

Figure 4-5. Distribution among the Quartiles Based on

Selective Catalytic Reduction (SCR) Usage

4.4 Heat Rates

Staudt and Macedonia reported that low-capacity boilers had much higher heat rates. They 

explained that this would be partly due to the fact that low pressure steam cycles are likely more 

common in smaller boilers. Figure 4-6 shows the distribution of CAMD 2012 heat rates among 

the generator units, but no obvious differences are noted in the distribution for the four quartiles.

31
Figure 4-6. Distribution of CAMD 2012 Heat Rates among Quartiles

The distribution of EIA-reported heat rates are shown in Figure 4-7, but they show somewhat 

different trends. Only Quartiles 1 and 2 have heat rates less than 10,000 Btu/kWh. Quartile 4 

generally is highly represented at the higher heat rates. Because the quartile distinctions are 

based on heat rates, these trends were not unexpected.

Figure 4-7. Distribution of EIA-Reported Heat Rates among the Quartiles

32
4.5 Online Year

Figure 4-8 shows the number of units in each quartile based on the online year. The most 

efficient units (Quartile 1 in blue) generally fall into the older units built before 1970, but this 

finding may not be intuitive. However, the older units are generally the smaller units and will be 

compared to other smaller units with the ones that are still operating representing only those with 

economical designs. The older units may also have fallen into environmental programs that 

grandfathered their high pollutant emission rates until after more efficient control technologies 

were developed.

Units going online between 1970 and 1985 do not generally fall into the most efficient quartile, 

indicating that they may currently be the units best suited to HRIs. The history associated with 

these units (e.g., replacements and upgrades) might provide reasons why units of this vintage do 

not perform as well as units going online in other years. Staudt and Macedonia reported little 

effect from the online year.

Figure 4-8. Distribution of Quartiles Based on Online Year

4.6 Planned Retirement Year

Only 203 records listed planned retirement years, and the years ranged from 2012 to 2021. 

Figure 4-9 displays the number of units from each quartile against the planned retirement years. 

A considerable number of the planned retirements fell into Quartile 1, and this is likely because 

they represent the earliest online years. Figure 4-10 supports this supposition with its display of 

the online years for only the units with planned retirement years. Note in Figure 4-10 that the 

majority of retiring units going online after 1965 fall into Quartile 4 (the worst performing units).

33
Figure 4-9. Distribution of Quartiles for Units Listing Planned Retirement Years

Figure 4-10. Distribution of Quartiles among Online Years for Units Listing

Planned Retirement Years

4.7 Variable O&M Costs

The AEO 2014 includes the Variable O&M costs that range from $0.57/MWh to $6.54/MWh for 

coal-fired units. Variable O&M costs are a key input for calculation of levelized costs, and the 

reported AEO 2014 values include fuel costs. Figure 4-11 shows the distribution of Variable 

O&M costs among the quartiles, and Figure 4-12 shows the distribution only for the larger units 

(over 100 MW). The differences between Figure 4-11 and Figure 4-12 appear in the bars to the 

right of $2.5/MWh because smaller units do not have the lower operational unit costs. The 

Variable O&M costs tend to be highest for the best performing units (Quartile 1), and this likely 

reflects the fact that the best performing units will be economical even when the fuel costs are 

high. 

34
Figure 4-11. Distribution of Quartiles Based on Variable O&M Costs

(Including Fuel Costs)

Figure 4-12. Distribution of Quartiles Based on Variable O&M Costs (Including Fuel 

Costs) for Units with Nameplate Capacities Over 100 MW

The Variable O&M cost distributions for Quartile 4 (worst performing units) are higher than 

those for Quartiles 2 and 3. This tendency toward higher Variable O&M costs may reflect that 

more fuel (and thus more fuel cost) is incurred in Quartile 4 units to generate the same amount of 

energy.

4.8 Fuel Choice

Ninety percent of the records had primary fuels listed as bituminous, sub-bituminous, lignite, or 

waste coal. Table 4-4 presents the numbers of units as they were distributed among the quartiles 

based on the primary fuel usage. Upon examination of the first five rows of this table, the 

35
bituminous coal units appear more frequently in Quartiles 1 and 4, but the sub-bituminous units 

dominate Quartiles 2 and 3. 

Table 4-4. Number of Generator Units in Quartiles Based on Primary Fuel Usage

Quartile 1 (best) Quartile 2 Quartile 3 Quartile 4

All Units

Bituminous 146 70 124 167

Sub-bituminous 55 160 108 60

Lignite 1 8 11 8

Waste Coal 4 -- 1 1

Not reported 51 18 13 21

Units with Nameplate Capacities Less than or Equal to 100 MW

Bituminous 54 7 11 23

Sub-bituminous 24 8 12 20

Lignite 1 2 -- --

Waste Coal 4 -- 1 1

Not reported 23 6 6 19

Units with Nameplate Capacities Greater than 100 MW but Less than 181 MW

Bituminous 81 20 -- 26

Sub-bituminous 26 26 -- 4

Lignite -- 2 -- --

Waste Coal -- -- -- --

Not reported 8 3 2 2

Units with Nameplate Capacities Greater than 181 MW

Bituminous 11 43 111 142

Sub-bituminous 5 126 96 36

Lignite -- 4 11 8

Waste Coal -- -- -- --

Not reported 20 9 5 --

Data are also presented in Table 4-4 used different cut points based on nameplate capacities. 

These cut points represent the decision nodes in the piecewise linear regression models described 

in the last chapter. In the group of units with nameplate capacities less than or equal to 100 MW, 

all fuel types are more likely to appear in Quartiles 1 and 4 than in the center quartiles. This 

finding is a reflection of the high variability in EIA heat rates for the smaller units.

The piecewise model for the units with nameplate capacities greater than 100 MW but less than 

181 MW shows a bias toward Quartiles 1 and 2, but all fuels are biased toward these quartiles. 

This result was anticipated because the model for this node has the same correction for both 

bituminous and sub-bituminous fuel.

For units with nameplate capacities greater than 181 MW, two rules apply for bituminous and 

lignite fuels and two other rules for sub-bituminous fuel. The rules for sub-bituminous coal again 

favor Quartiles 2 and 3, but the rules for bituminous and lignite fuels tend to put more units in 

Quartiles 3 and 4. The computed Slope Function is greater than 1.00 at 81% of the 

bituminous/lignite units in the largest size category, so the bias toward low performance might 

be explained by the model bias rather than actual plant performance.

36
4.9 Total FGD Cost

Staudt and Macedonia reported that the FGD-controlled units generally were more efficient than 

unscrubbed units, but not by much. When a dry scrubber was added to the unit (comparing 

against historical data), the heat rates did increase. However, Staudt and Macedonia did not 

determine a directional correlation for the addition of wet scrubbers.

The data in this study represent only single snapshots in time of a unit’s heat rates and not the 

effect of adding new units. The parameter called FGD Cost Total ranged from $21,000 to $1.5 

billion in the EIA-923 forms for 2012. Fifty-six records showed a total FGD cost exceeding 

$325M (81% to structure, 4% to disposal, and 15% to other costs). 

Figure 4-13 depicts how the Total FGD Cost parameter is distributed among the quartiles for the 

460 units. The total FGD cost for the majority of the units is less than $100M, and all four 

quartiles have their largest counts in the first two bins. Therefore, the total FGD cost did not 

appear correlated to the unit performance. 

Figure 4-13. Distribution of Total FGD Cost (Thousands of Dollars) among Quartiles

4.10 FGP Collector Classification and Hours in Service

FGP collectors were reported for 883 units in ten different categories (3 baghouse types, 4 ESP 

types, 2 cyclones, wet scrubber, and other type), but the FGP categories were compiled into five 

types in Figure 4-14. Figure 4-14 shows that most FGP collectors fall into the ESP categories 

and that ESP systems are more often associated with Quartile 4 than the other quartiles. Eightyeight percent of the Quartile 4 records with FGP collectors use ESPs, but the percentages are 

only near 70% (± 3%) for the other three quartiles.

37
Figure 4-14. Distribution of Quartiles among FGP Collector Types

This finding indicates that the FGP collector type might be associated with the unit performance 

(this parameter does appear in five of the seven slope function models) or at least correlate with 

another parameter that shows similar patterns. Figure 4-15 shows the distribution of FGP 

collector types based on the online year for the generator unit. The figure clearly indicates that 

the ESP technology was installed on a majority of the units that went online before 1990, but 

baghouse technologies are more common in newer units. Figure 4-8 showed few Quartile 4 units 

that went online after 1990, so the lack of ESPs in newer units may indicate why Figure 4-14

indicated a tendency of ESPs toward Quartile 4.

Figure 4-15. Distribution of FGP Collector Types with Online Year

Table 4-1 showed that the average numbers of FGP service hours in 2012 were lower for 

Quartile 1 and Quartile 4 than the other two quartiles, indicating that these units are less likely to 

produce base load electricity. Figure 4-16 shows that the distribution of FGP service hours for 

38
the four quartiles as fractional counts. This display clearly shows that Quartile 1 units are more 

likely to operate FGP controls less than 4000 hours a year than greater that, but the shorter 

operational hours appear less frequently in the other three quartiles.

Figure 4-16. Fractional Distribution of FGP Service Hours among Quartiles

4.11 Cooling System Type and In-Service Year

The primary cooling system types were grouped for this analysis:

• Once through systems without pond or canal (427 units with code=ON)

• Cooling ponds or canals (81 units with code=OC or RC)34

• Cooling towers (329 units with code=HRF, RF, RI, or RN)35

• Other/unknown (3 DC units, 2 OT units, and 185 blank)36

Figure 4-17 shows the fractional distributions of the quartiles within each cooling system type. 

The unknown units are more often represented by Quartiles 1 and 4 because reported rates vary 

more significantly from predicted rates when information is missing. Quartile 1 represents the 

largest fraction for the “Once Through without Pond” type, and Quartile 3 is the largest fraction 

for the units with cooling towers. The reason for these observations is likely connected to the inservice years.

34 OC = Once through with cooling pond(s) or canal(s); RC = Recirculating with cooling pond(s) or canal(s).

35 HRF = Hybrid: recirculating with forced draft cooling tower(s) with dry cooling; RF = Recirculating with forced 

draft cooling tower(s); RI = Recirculating with induced draft cooling tower(s); RF = Recirculating with natural 

draft cooling tower(s).

36 DC = Dry (air) cooling system; OT = Other.

39

 
Figure 4-17. Fractional Distribution of the Quartiles within Cooling System Types

Figure 4-18 shows the distribution of the three major cooling system types based on the inservice year. It clearly indicates that the oldest units were predominantly once through systems 

without ponds, and the newest units are predominantly those with cooling towers. As mentioned 

in previous subsections, Quartile 1 units are generally more common in older systems, and the 

largest fraction of Quartile 3 units appear around 1980 in Figure 4-18. These observations tend to 

explain the frequencies observed in Figure 4-17.

Figure 4-18. Distribution of Cooling System Types among In-Service Years

for Cooling Systems

40
4.12 Number of Federal Air Market Programs Affecting Emissions

The EPA CAMD data set also covers statutory or regulatory based options for tracking and 

reducing air pollution emissions. Annual information for environmental controls at the generator 

level is available from the EPA Air Markets Program Data (AMPD) database for facility 

attributes. The AMPD data contain also information on annual and ozone (May-September) 

season programs at the generating unit level. The market-based regulatory programs aim to 

improve air quality through coordinated emission reductions.

The annual programs include:

• Acid Rain Program (ARP), 

• Clean Air Interstate Rule (CAIR) NOx Program, 

• Cross-State Air Pollution Rule (CSAPR) annual NOx (TRNOx), Phase I (TRSO2G1) and 

phase II (TRSO2G2) SO2 Programs, and

• Regional Greenhouse Gas Initiative (RGGI)

The ozone season programs include:

• CSAPR ozone season NOx Program (TRNOxOS), 

• CAIR ozone season NOx Program (CAIROS), 

• NOx SIP Call Program (SIP NOx), and 

• NOx Budget Program (NBP). 

Finally, the database indicates when a unit is subject to New Hampshire's NOx program 

(NHNOx). None of these eleven program phases began implementation before 1995, and more 

than 90% of the generator units in the database pre-date the announcements of these programs. 

Therefore, comparing the heat rate predictions against each of these programs would not be 

expected to yield significant results. However, some of these programs are implemented at the 

statewide level (based on unit size), so an accounting of the programs may serve as a surrogate 

for describing regional behavior. Table 4-5 shows the state names based on the number of market 

programs coal-fired units there are subject to. In rows with multiple bullets, the table shows that 

24 states have some units that are subject to no air market programs and other units subject to 1 

to 8 programs.

Table 4-5. Number of Air Market Programs Affecting Generators by State

State Number of Programs

0 1 3 5 6 7 8

Alabama ●

Arkansas ● ●

Arizona ● ●

Colorado ● ●

Connecticut ●

Delaware ● ●

Florida ● ●

Georgia ● ●

Iowa ● ●

41
State Number of Programs

0 1 3 5 6 7 8

Illinois ● ●

Indiana ● ●

Kansas ●

Kentucky ●

Louisiana ●

Massachusetts ●

Maryland ●

Michigan ● ●

Minnesota ● ●

Missouri ● ●

Mississippi ● ●

Montana ● ●

North Carolina ● ●

North Dakota ● ●

Nebraska ● ●

New Hampshire ●

New Jersey ●

New Mexico ●

Nevada ● ●

New York ● ●

Ohio ● ●

Oklahoma ●

Oregon ●

Pennsylvania ● ●

South Carolina ● ●

South Dakota ● ●

Tennessee ●

Texas ● ●

Utah ● ●

Virginia ● ●

Washington ●

Wisconsin ● ●

West Virginia ● ●

Wyoming ● ●

Figure 4-19 shows the quartile distributions based on the number of Federal air market programs. 

It does not indicate that fewer or more Federal air market programs lean toward particular 

quartiles. However, Figure 4-20 does show that the generators associated with the highest heat 

rates are generally affected by no programs, and those with the lowest heat rates (less than 

10,500 Btu/kWh) are more likely to be affected by 6 or 7 programs.

42
Figure 4-19. Distribution of Quartiles Based on Number of Federal Air Market Programs

Figure 4-20. Distribution of Heat Rates Based on Number of

Federal Air Market Programs

43
5 Evaluation of Potential HRIs and Associated Costs

5.1 Heat Rate Improvement Options and Valuation

Chapter 2 described a variety of the available published reports discussing heat rate 

improvements at coal-fired power plants and their associated costs. It illustrated that a wide 

range of improvements was possible at a wide range of capital and operating costs. This chapter 

presents the Leidos analysis of what fraction of the units could have the measures applied, the 

anticipated HRIs, and the anticipated costs (in 2014 dollars). 

The improvements are considered in five different plant areas: boiler island, turbine island, flue 

gas system, air pollution controls, and water treatment system. Some previous reports considered 

regular outage maintenance activities (e.g., replacement of first point heater) as HRIs, but this 

chapter focuses on non-routine retrofit measures that reflect a change in design or operations.

Considerable overlap exists between the different HRI activities, and many activities cited in the 

literature might be considered subsets of other activities. To avoid double-counting future 

potential HRIs in the coal-fired fleet, some subcategories were eliminated. Also eliminated were 

those measures typically performed as maintenance activities during scheduled outages; these 

activities restore heat rate but are not considered to actually improve plant performance.

The existing literature also stresses that the HRIs should not be considered additive. The 

potential efficiency gained by one boiler island HRI should not necessarily be added to another 

boiler island HRI or HRIs elsewhere at the plant without a full heat rate evaluation. Such an 

evaluation should also include consideration of the expected unit capacity factor and the 

expected load changes.

In addition, some activities require significant capital investment and are likely to trigger the 

New Source Review (NSR) provisions of the Clean Air Act. Installation of additional control 

systems under the NSR would often negate the HRIs, so special conditions were assigned such 

that previously uncontrolled systems could not gain HRIs from certain measures that involved 

high capital cost investments.

Some technologies were also identified as existing only in the R&D or pilot phase at this point. 

Literature works and patents indicate that some degree of success is being made in these areas, 

but often readers would find it difficult to classify the HRIs in these pilot studies as maxima or 

minima. The public literature on these studies generally does not cite costs, so full cost 

evaluations would be necessary for EIA to establish ranges on the capital, operating, and 

maintenance costs across all potential plants. The recommendations for these cost evaluations are 

listed in Chapter 7.

As discussed in Chapter 3, many HRI activities are already underway at coal-fired plants because 

improved heat rates are associated with fuel cost savings. Therefore, it is assumed that units 

falling into Quartile 1 had most likely already made improvements and that Quartile 4 units were 

the least likely to have made improvements. Expert Leidos-based experience was used to judge 

how commonly practiced the various HRI activities had been deployed through 2014:

• Novel – still available for Quartiles 1, 2, 3, and 4

• Uncommon today – available for Quartiles 2, 3, and 4

• 50/50 today – available for Quartiles 3 and 4

44
• In most units today – available for Quartile 4

• Maybe in 10 years – available for Quartiles 1, 2, and 3 (assuming that Quartile 4 units 

would make other improvements before investing in the newer technologies)

Initially 56 HRI activities were under consideration, but the criteria listed in the preceding 

paragraphs reduced the list to just the 29 measures shown in Table 5-1. Table 5-1 presents the 

highest HRIs and maximum capital costs, and Table 5-2 presents the minima. Both of these 

tables include special conditions and notes columns that identify the source and/or assumptions 

associated with the HRI valuations and capital costs. 

The approach used to generally assess the range of HRI potential for the large numbers of coalfired units of varied types and existing condition is as follows:

• Detailed assessment of individual units or sample cases was not possible within the scope 

of this project, requiring a much more general approach based on literature data and 

engineering experience and judgment associated with decades of coal-fired plant upgrade 

projects. Note that site-specific equipment review and related cost appraisals are the 

most appropriate methods for assessing all required equipment, material, and 

installation and operating labor for unique projects. 

• The 2009 S&L Report results were used as the reference values for those HRI options 

covered in this report. Leidos engineering staff considered the maximum and minimum 

HRI values established in the report and used engineering experience and judgment and 

other available internal and literature data (as discussed in Section 2 of this report) to 

determine if updates were deemed appropriate. For all HRIs, Leidos staff either decided 

on more conservative HRI values or accepted the S&L Report values.

• Other HRI options not included in the S&L Report were assessed based on Leidos 

experience, engineering judgment, and internal and literature data sources as available.

• Literature sources reviewed are presented in Section 2. Key sources used were:

o Coal-Fired Power Plant Heat Rate Reductions, Prepared by Sargent & Lundy for 

Perrin Quarles Associates, Inc., under U.S.EPA Contract No. EP-W-07-064, January 

22, 2009.

 Study of various methods to reduce the heat rate of existing U.S. coal-fired power 

plants in a range of sizes − 200 MW, 500 MW, and 900 MW (see Section 2.1)

 Cost basis – Vendor quotes

 Cost Year basis – 2008 (mid-year assumed)

o Reliable & Resilient / The Value of Our Existing Coal Fleet - An Assessment of 

Measures to Improve Reliability & Efficiency While Reducing Emissions, National 

Coal Council study at the request of the U.S. Department of Energy, May 2014.

 Study identifies various methods to reduce the heat rate of existing U.S. coal-fired 

power plants for plants of various sizes (see Section 2.1)

 Cost basis – Various literature and regulatory sources

 Cost Year basis – various

45
o ASME Energy Forum, Power Plant Efficiency: Saving Fuel, Officiated by Licata 

Energy and Environmental Consulting, September 25, 2014.

 Presenting organizations were: Anthony Licata (Cycling Ops./Air Heaters 

/Emissions Controls); Burns & McDonnell (Impact of New Source Review);

Siemens Energy (Turbine Island); Robert Sommerlad (Combustion/ Boiler Island 

/ Neural Networks & Intelligent Sootblowing)

o EPRI Range and Applicability of Heat Rate Improvements Technical Update. April 

2014. Electric Power Research Institute Report Number 3002003457.

 Summarizes methodologies and tools for assessing and implementing measures 

for improving heat rate in coal-fired power plants. In addition, the report attempts 

to better bracket the range of achievable improvements possible for an existing 

coal-fired power plant.

 No cost data included

5.2 Heat Rate Improvement Cost Estimation

Tables 5-1 and 5-2, respectively, present the maximum and minimum estimates for the total 

capital investment (order of magnitude) associated with HRI equipment modifications. Table 

5-3 presents a comparable list of the associated fixed and variable O&M costs associated with 

each HRI.

Costs for the HRI options included in the S&L report (vendor quotes) were accepted for use in 

this study, but were escalated to November 2014 dollars (from mid-year 2008) using the RS

Means Construction Facilities Cost Data - 28th annual edition Historical Cost Indexes.

• Historical Cost Index for 2008 = 180.4

• Historical Cost Index Estimated for November 2014 = 198.2

• Calculated escalation from 2008 to November 2014 = 10%

The same composite construction cost escalation index has been used for both capital costs and

fixed and variable O&M because the S&L Report did not break out the cost split between 

materials, labor, and equipment.

Readers should think of these numbers and the upgrade choice in NEMS as the heat rate 

evaluation findings that are conducted at a plant prior to a planned outage. A utility may 

conduct/contract a heat rate evaluation prior to an outage, and the results will tell them the 

expected HRI and potential cost. Sometimes no cost-prohibitive solutions will be identified, so 

the HRI and cost would both be zero.

If many of these evaluations are done across a broad selection within one ECP type, the average 

HRI times the total number of generators will represent the total potential fuel savings (TPFS), 

and the average cost times the total number of generators will represent the total costs (TC). The 

same TPFS and TC will result if the average non-zero HRI is multiplied by the total number of 

generators (with non-zero HRIs) and the average non-zero cost is multiplied by the total number 

of generators (with non-zero HRIs). The ratio of TC to TPFS will also be the same and 

represents a national average improvement. Therefore, no distortion is observed in the data as 

long as the TPFS and TC are both divided by the same number of generators (equal 

denominators for TPFS/units and TC/units).

46
Table 5-1. Maximum Estimates For Heat Rate Improvements and Capital Costs

Affected Quartiles Special 

Condition

Heat Rate Improvement 

(Btu/kWh)

Capital Cost (2014 millions 

of dollars) Notes

Q1 Q2 Q3 Q4 <=200 

MW

<=500 

MW

>500 

MW

<=200 

MW

<=500 

MW

>500 

MW

Boiler Island

Redesign and 

replace 

economizer

●

limited 

applicability, very 

site-specific

60 40 20 3.3 5.5 8.8

HRI Reference: ASME Energy 

Forum Sept 2014. Larger 

opportunity for economizer based 

efficiency improvement on smaller, 

older units which demonstrated 

higher heat rate. HRI based on 

engineering judgment for reasonable 

gains based on 24°F reduction in exit 

gas temperature for <200 MW; 

16°F <500 MW; 10°F >500 MW.

Cost Reference: S&L Report

Fuel Delivery 

System (FDS) 

Upgrades

● ● 84 84 84 7 12 15

HRI Reference: ASME Energy 

Forum Sept 2014. HRI from boiler 

efficiency gain from reduced excess 

air, plus auxiliary power reduction.

Cost Reference: Leidos Estimate

Neural 

network ● ● ● 50 30 30 0.55 0.83 0.83

HRI Reference: Engineering 

judgment based on project 

experience, information in S&L 

Report

Cost Reference: S&L Report

Intelligent 

sootblower ● ● 70 70 70 0.33 0.55 0.55

HRI Reference: EPRI Report April 

2014

Cost Reference: S&L Report

Digital 

controls ● 0 0 0 2.2 3.80 4.40

For FDS, neural network, intelligent 

sootblower, performance monitoring 

(including feedwater heater 

monitoring), routine testing

Cost Reference: S&L Report

Limit air 

heater 

leakage

● 8 5 5 0.55 0.77 1.32

HRI Reference: Engineering 

judgment based on fan power usage 

reduction.

Cost Reference: S&L Report

Nanocoatings in 

boilers

future only

47
Affected Quartiles Special 

Condition

Heat Rate Improvement 

(Btu/kWh)

Capital Cost (2014 millions 

of dollars) Notes

Q1 Q2 Q3 Q4 <=200 

MW

<=500 

MW

>500 

MW

<=200 

MW

<=500 

MW

>500 

MW

Blowdown 

recovery tank ● 1 1 1 0.1 0.1 0.1

HRI Reference: Engineering 

judgment based on project 

experience

Cost Reference: Leidos Estimate

Coal 

switching ●

future only; 

switching from 

low sulfur to 

higher sulfur coal 

unlikely/problem

atic

Coal drying ● ● ● ●

future only; 

currently limited 

to mine mouth 

application

Coal 

processing 

(additives)

future only

Air heater 

baskets ● ● 5 5 5 0.23 0.39 0.45

HRI Reference: Engineering 

judgment based on project 

experience

Cost Reference: Leidos Estimate

Lower air 

heater outlet 

temperature 

by controlling 

acid dew 

point

● ● ●

No FGD. This is 

a very sitespecific issue, 

difficult to 

estimate across a 

wide range. 

5 5 5 3.85 11 19.8

HRI Reference: Engineering 

judgment based on project 

experience; see special condition 

note.

Cost Reference: S&L Report

Turbine Island

Blade path 

upgrade ● ● No NSR triggered 200 300 300 13.2 22 27.5

HRI Reference: values based on 

S&L report. Blade path upgrade for 

<200MW steam turbine units 

discounted because these units are in 

a population class with lower 

pressure cycles and have smaller 

opportunity for heat rate 

improvement.

Cost Reference: S&L Report

48
Affected Quartiles Special 

Condition

Heat Rate Improvement 

(Btu/kWh)

Capital Cost (2014 millions 

of dollars) Notes

Q1 Q2 Q3 Q4 <=200 

MW

<=500 

MW

>500 

MW

<=200 

MW

<=500 

MW

>500 

MW

Turbine 

overhaul (not 

including 

blade path 

upgrade)

● part of normal 

maintenance 0 0 0 0 0 0

Steam turbine performance degrades 

over time, increasing heat rate. 

Maintenance is done on 7 to 10 year 

cycles to regain lost heat rate, but 

does not provide a net gain.

Condenser 

cleaning ● Part of normal maintenance 0 0 0 0 0 0 Part of normal maintenance – does not result in net HRI

Boiler feed 

pumps ● 50 50 50 0.39 0.66 0.88 HRI Reference: S&L ReportCost Reference: S&L Report

Variablespeed drives 

for main 

cycle and 

auxiliary 

equipment

● ● 50 50 50 4 6 8

HRI Reference: Engineering 

judgment based on project 

experience

Cost Reference: Leidos Estimate

Cooling 

system 

optimization

● ● 50 50 50 0.2 0.35 0.5

HRI Reference: Engineering 

judgment based on review of various 

sources (S&L, EPRI)

Cost Reference: Leidos Estimate

Exhaust hood 

steam guide 

modification

● ● ● ● 2 2 2 0.3 0.3 0.3

HRI Reference: Engineering 

judgment based on project 

experience

Cost Reference: Leidos Estimate

Rewind 

generator ● 30 40 40 4 5.5 7

HRI Reference: Engineering 

judgment based on project 

experience

Cost Reference: Leidos Estimate

Topping cycle 

addition ● ● ● future only

Bottoming 

cycle with 

organic 

solvent

● ● ● future only

Flue Gas System

ID Axial Fan 

(and motor) 

upgrades

● ● ● 80 80 80 7.7 12.1 17.6

HRI Reference: Engineering 

judgment based on project 

experience and information in S&L 

report

Cost Reference: S&L Report

49
Affected Quartiles Special 

Condition

Heat Rate Improvement 

(Btu/kWh)

Capital Cost (2014 millions 

of dollars) Notes

Q1 Q2 Q3 Q4 <=200 

MW

<=500 

MW

>500 

MW

<=200 

MW

<=500 

MW

>500 

MW

VariableFrequency 

Drives

● ● 70 70 70 2.2 4.4 6.6

HRI Reference: Engineering 

judgment based on project 

experience and information in S&L 

report

Cost Reference: S&L Report

VariableFrequency 

Drives and 

new 

centrifugal 

fans

● ● 150 150 150 7.15 12.1 17.6 HRI Reference: S&L Report

Cost Reference: S&L Report

Air Pollution Control

Removal of 

Venturi 

throat

● 13 13 13 2.75 2.75 2.75 HRI Reference: S&L Report

Cost Reference: S&L Report

Turning 

vanes and 

perforated 

gas 

distribution 

plates at the 

inlet

● 2 2 2 0.275 0.275 0.275 HRI Reference: S&L Report

Cost Reference: S&L Report

Shutoff spray 

level ● 16 16 16 0 0 0 HRI Reference: S&L ReportCost Reference: S&L Report

VariableFrequency 

Drives

● 50 50 50 1.1 3.3 5.5 HRI Reference: S&L Report

Cost Reference: S&L Report

ESP 

Modification ● ● 5 5 5 0.22 0.55 0.88 HRI Reference: S&L ReportCost Reference: S&L Report

SCR 

Modification ● 10 10 10 0.55 1.1 2.2 HRI Reference: S&L ReportCost Reference: S&L Report

Water Treatment

Cooling 

Tower 

Advanced 

Packing 

Upgrade

● ● 70 70 70 1.65 3.3 5.5 HRI Reference: S&L Report

Cost Reference: S&L Report

50
Affected Quartiles Special 

Condition

Heat Rate Improvement 

(Btu/kWh)

Capital Cost (2014 millions 

of dollars) Notes

Q1 Q2 Q3 Q4 <=200 

MW

<=500 

MW

>500 

MW

<=200 

MW

<=500 

MW

>500 

MW

Supplemental 

cooling tower ● ● ●

This is a very 

site-specific 

issue, difficult to 

estimate across a 

wide range.

10 10 10 2 3 4

HRI Reference: Engineering 

judgment based on project 

experience

Cost Reference: Leidos Estimate

Other

HR 

awareness 

training, 

make HR 

information 

available

●

Requires 

upgraded control 

system

150 150 150

HRI Reference: EPRI Report April 

2014

Cost Reference: Leidos Estimate

Initiating 

routine 

testing 

programs

● 200 200 200 0.1 0.1 0.1

HRI Reference: EPRI Report April 

2014

Cost Reference: Leidos Estimate

Feedwater 

Heater 

Monitoring

●

Requires 

upgraded control 

system

60 60 60

HRI Reference: EPRI Report April 

2014

Cost Reference: Leidos Estimate

51
Table 5-2. Minimum Estimates for Heat Rate Improvements and Capital Costs

Affected Quartiles Special 

Condition

Heat Rate Improvement 

(Btu/kWh) Capital Cost (2014 $M)

Notes

Q1 Q2 Q3 Q4 <=200 

MW

<=500 

MW

>500 

MW

<=200 

MW

<=500 

MW

>500 

MW

Boiler Island

Redesign and 

replace economizer ●

limited 

applicability, 

very sitespecific

20 20 10 2.5 3.5 5

HRI Reference: ASME Energy Forum 

Sept 2014. Larger opportunity for 

economizer based efficiency 

improvement on smaller, older units 

which demonstrated higher heat rate. 

HRI based on engineering judgment for 

reasonable gains based on 24°F 

reduction in exit gas temperature for 

<200 MW; 16°F <500 MW; 10°F >500 

MW.

Cost Reference: Leidos Estimate

Fuel Delivery 

System (FDS) 

Upgrades

● ● 30 30 30 3.5 6 7.5

HRI Reference: ASME Energy Forum 

Sept 2014. HRI from boiler efficiency 

gain from reduced excess air, plus 

auxiliary power reduction.

Cost Reference: Leidos Estimate

Neural network ● ● ● 10 10 10 0.55 0.83 0.83

HRI Reference: Engineering judgment 

based on project experience, information 

in S&L Report

Cost Reference: S&L Report

Intelligent 

sootblower ● ● 20 20 20 0.33 0.55 0.55

HRI Reference: EPRI Report April 

2014

Cost Reference: S&L Report

Digital controls ● 0 0 0 2.2 3.80 4.40

For FDS, neural network, intelligent 

sootblower, performance monitoring 

(including feedwater heater monitoring), 

routine testing

Cost Reference: Leidos Estimate

Limit air heater 

leakage ● 8 5 5 0.55 0.77 1.32

HRI Reference: Engineering judgment 

based on fan power usage reduction.

Cost Reference: S&L Report

Nano-coatings in 

boilers future only

Blowdown 

recovery tank ● 1 1 1 0.1 0.1 0.1

HRI Reference: Engineering judgment 

based on project experience

Cost Reference: Leidos Estimate

52
Affected Quartiles Special 

Condition

Heat Rate Improvement 

(Btu/kWh) Capital Cost (2014 $M)

Notes

Q1 Q2 Q3 Q4 <=200 

MW

<=500 

MW

>500 

MW

<=200 

MW

<=500 

MW

>500 

MW

Coal switching ●

future only; 

switching 

from low 

sulfur to 

higher sulfur 

coal 

unlikely/probl

ematic

Coal drying ● ● ● ●

future only; 

currently 

limited to 

mine mouth 

application

Coal processing 

(additives) future only

Air heater baskets ● ● 5 5 5 0.23 0.39 0.45

HRI Reference: Engineering judgment 

based on project experience

Cost Reference: Leidos Estimate

Lower air heater 

outlet temperature 

by controlling acid 

dew point

● ● ●

No FGD. 

This is a very 

site specific 

issue, difficult 

to estimate 

across a wide 

range. 

5 5 5 3.85 11 19.8

HRI Reference: Engineering judgment 

based on project experience; see special 

condition note.

Cost Reference: S&L Report

Turbine Island

Blade path 

upgrade ● ● No NSR 

triggered 100 150 150 6 11 14

HRI Reference: values based on S&L 

report. Blade path upgrade for 

<200MW steam turbine units discounted 

because these units are in a population 

class with lower pressure cycles and 

have smaller opportunity for heat rate 

improvement.

Cost Reference: S&L Report

Turbine overhaul 

(not including 

blade path 

upgrade)

● part of normal 

maintenance 0 0 0 0 0 0

Steam turbine performance degrades 

over time, increasing heat rate. 

Maintenance is done on 7 to 10 year 

cycles to regain lost heat rate, but does 

not provide a net gain.

53
Affected Quartiles Special 

Condition

Heat Rate Improvement 

(Btu/kWh) Capital Cost (2014 $M)

Notes

Q1 Q2 Q3 Q4 <=200 

MW

<=500 

MW

>500 

MW

<=200 

MW

<=500 

MW

>500 

MW

Condenser 

cleaning ● 0 0 0 0 0 0 Part of normal maintenance – does not result in net HRI

Boiler feed pumps ● 20 20 20 0.3 0.5 0.8

HRI Reference: Engineering judgment, 

S&L Report

Cost Reference: S&L Report

Variable-speed 

drives for main 

cycle and auxiliary 

equipment

● ● 20 20 20 2 3 4

HRI Reference: Engineering judgment 

based on project experience

Cost Reference: Leidos Estimate

Cooling system 

optimization ● ● 25 25 25 0.15 0.3 0.4

HRI Reference: Engineering judgment 

based on review of various sources 

(S&L, EPRI)

Cost Reference: Leidos Estimate

Exhaust hood 

steam guide 

modification

● ● ● ● 2 2 2 0.3 0.3 0.3

HRI Reference: Engineering judgment 

based on project experience

Cost Reference: Leidos Estimate

Rewind generator ● 30 40 40 4 5.5 7

HRI Reference: Engineering judgment 

based on project experience

Cost Reference: Leidos Estimate

Topping cycle 

addition ● ● ● future only

Bottoming cycle 

with organic 

solvent

● ● ● future only

Flue Gas System

ID Axial Fan (and 

motor) upgrades ● ● ● 10 10 10 5 10 12 HRI Reference: S&L ReportCost Reference: S&L Report

VariableFrequency Drives ● ● 30 30 30 2 4 6

HRI Reference: Engineering judgment 

based on project experience and 

information in S&L report

Cost Reference: S&L Report

VariableFrequency Drives 

and new 

centrifugal fans

● ● 60 60 60 5 8 14

HRI Reference: Engineering judgment 

based on project experience and 

information in S&L report

Cost Reference: Leidos Estimate

Air Pollution Control

Removal of 

Venturi throat ● 7 7 7 1.4 1.4 1.4 HRI Reference: S&L ReportCost Reference: S&L Report

54
Affected Quartiles Special 

Condition

Heat Rate Improvement 

(Btu/kWh) Capital Cost (2014 $M)

Notes

Q1 Q2 Q3 Q4 <=200 

MW

<=500 

MW

>500 

MW

<=200 

MW

<=500 

MW

>500 

MW

Turning vanes and 

perforated gas 

distribution plates 

at the inlet

● 1 1 1 0.275 0.275 0.275 HRI Reference: S&L Report

Cost Reference: S&L Report

Shutoff spray level ● 0 0 0 0 0 0 HRI Reference: S&L Report

Cost Reference: S&L Report

VariableFrequency Drives ● 20 20 20 1.1 3.3 5.5 HRI Reference: S&L Report

Cost Reference: S&L Report

ESP Modification ● ● 2 2 2 0.22 0.55 0.88 HRI Reference: S&L Report

Cost Reference: S&L Report

SCR Modification ● 5 5 5 0.55 1.1 2.2 HRI Reference: S&L Report

Cost Reference: S&L Report

Water Treatment

Cooling Tower 

Advanced Packing 

Upgrade

● ● 0 0 0 1.65 3.3 5.5 HRI Reference: S&L Report

Cost Reference: S&L Report

Supplemental 

cooling tower ● ● ●

This is a very 

site specific 

issue, difficult 

to estimate 

across a wide 

range.

10 10 10 2 3 4

HRI Reference: Engineering judgment 

based on project experience

Cost Reference: Leidos Estimate

Other

HR awareness 

training, make HR 

information 

available

●

requires 

upgraded 

control 

system

50 50 50

HRI Reference: EPRI Report April 

2014

Cost Reference: Leidos Estimate

Initiating routine 

testing programs ● 75 75 75 0.1 0.1 0.1

HRI Reference: EPRI Report April 

2014

Cost Reference: Leidos Estimate

Feedwater Heater 

Monitoring ●

requires 

upgraded 

control 

system

30 30 30

HRI Reference: EPRI Report April 

2014

Cost Reference: Leidos Estimate

55
Table 5-3. Fixed and Variable O&M Cost Estimates for Heat Rate Improvements

Affected Quartiles Special 

Condition

Fixed O&M Costs (2014 $/yr) Variable O&M Costs (2014 $M)

Notes

Q1 Q2 Q3 Q4 <=200 

MW

<=500 

MW

>500 

MW

<=200 

MW

<=500 

MW

>500 

MW

Boiler Island

Redesign and 

replace 

economizer

●

limited 

applicability, 

very sitespecific

55,000 110,000 165,000 0 0 0 Cost Reference: S&L Report

Fuel Delivery 

System (FDS) 

Upgrades

● ● Cost Reference: ASME 

Energy Forum Sept 2014. 

Neural network ● ● ● 55,000 55,000 55,000 0 0 0 Cost Reference: S&L Report

Intelligent 

sootblower ● ● 55,000 55,000 55,000 0 0 0 Cost Reference: S&L Report

Digital controls ● 100,000 100,000 100,000 0 0 0 Cost Reference: Leidos 

Estimate

Limit air heater 

leakage ● 55,000 82,500 110,000 0 0 0 Cost Reference: S&L Report

Nano-coatings in 

boilers future only

Blowdown 

recovery tank ● 0 0 0 0 0 0 Cost Reference: Leidos Estimate

Coal switching ●

future only; 

switching from 

low sulfur to 

higher sulfur 

coal 

unlikely/proble

matic

Coal drying ● ● ● ●

future only; 

currently 

limited to mine 

mouth 

application

Coal processing 

(additives) future only

Air heater 

baskets ● ● 20,000 30,000 40,000 0 0 0 Cost Reference: Leidos Estimate

56
Affected Quartiles Special 

Condition

Fixed O&M Costs (2014 $/yr) Variable O&M Costs (2014 $M)

Notes

Q1 Q2 Q3 Q4 <=200 

MW

<=500 

MW

>500 

MW

<=200 

MW

<=500 

MW

>500 

MW

Lower air heater 

outlet 

temperature by 

controlling acid 

dew point

● ● ●

No FGD. This 

is a very site 

specific issue, 

difficult to 

estimate across 

a wide range. 

55,000 82,500 110,000 385,000 935,000 1,650,000 Cost Reference: S&L Report

Turbine Island

Blade path 

upgrade ● ● No NSR triggered 0 0 0 0 0 0 Cost Reference: S&L Report

Turbine overhaul 

(not including 

blade path 

upgrade)

● part of normal 

maintenance 0 0 0 0 0 0 Cost Reference: S&L Report

Condenser 

cleaning ● 0 0 0 0 0 0 Part of normal maintenance –does not result in net HRI

Boiler feed 

pumps ● 0 0 0 0 0 0 Cost Reference: S&L Report

Variable-speed 

drives for main 

cycle and 

auxiliary 

equipment

● ● 55,000 110,000 165,000 0 0 0 Cost Reference: Leidos 

Estimate

Cooling system 

optimization ● ● 55,000 110,000 165,000 0 0 0 Cost Reference: Leidos Estimate

Exhaust hood 

steam guide 

modification

● ● ● ● 10000 10000 10000 0 0 0 Cost Reference: Leidos 

Estimate

Rewind generator ● 10000 10000 10000 0 0 0 Cost Reference: Leidos 

Estimate

Topping cycle 

addition ● ● ● future only

Bottoming cycle 

with organic 

solvent

● ● ● future only

Flue Gas System

ID Axial Fan (and 

motor) upgrades ● ● ● 55,000 93,500 143,000 0 0 0 Cost Reference: S&L Report

VariableFrequency Drives ● ● 22,000 33,000 55,000 0 0 0 Cost Reference: S&L Report

57
Affected Quartiles Special 

Condition

Fixed O&M Costs (2014 $/yr) Variable O&M Costs (2014 $M)

Notes

Q1 Q2 Q3 Q4 <=200 

MW

<=500 

MW

>500 

MW

<=200 

MW

<=500 

MW

>500 

MW

VariableFrequency Drives 

and new 

centrifugal fans

● ● 27,500 41,800 66,000 0 0 0 Cost Reference: S&L Report

Air Pollution Control

Removal of 

Venturi throat ● 0 0 0 0 0 0 Cost Reference: S&L Report

Turning vanes 

and perforated 

gas distribution 

plates at the inlet

● 0 0 0 0 0 0 Cost Reference: S&L Report

Shutoff spray 

level ● 0 0 0 0 0 0 Cost Reference: S&L Report

VariableFrequency Drives ● 55,000 110,000 165,000 0 0 0 Cost Reference: S&L Report

ESP Modification ● ● 27,500 27,500 27,500 0 0 0 Cost Reference: S&L Report

SCR Modification ● 27,500 55,000 110,000 27,500 66,000 110,000 Cost Reference: S&L Report

Water Treatment

Cooling Tower 

Advanced 

Packing Upgrade

● ● 82,500 137,500 192,500 0 0 0 Cost Reference: S&L Report

Supplemental 

cooling tower ● ● ●

This is a very 

site specific 

issue, difficult 

to estimate 

across a wide 

range.

82,500 137,500 192,500 0 0 0 Cost Reference: S&L Report

Other

HR awareness 

training, make 

HR information 

available

●

requires 

upgraded 

control system

100,000 100,000 100,000 Cost Reference: Leidos 

Estimate

Initiating routine 

testing programs ● 100,000 100,000 100,000 - - - Cost Reference: Leidos Estimate

Feedwater Heater 

Monitoring ●

requires 

upgraded 

control system

Cost Reference: Leidos 

Estimate

58
6 Applying Potential Heat Rate Improvements to the Entire Database

This chapter presents the results from applying the HRIs to the population of generators in the 

data set. The first section shares the HRIs associated with generators of different vintages, 

nameplate capacity, and ECP type. The second section describes the range of HRIs across the 

entire data set, and the third section describes the associated range in costs. The final section 

details some additional considerations that are warranted when working with this data set.

6.1 HRI Potentials as They Relate to Select Input Parameters

Although the data set contains many parameters, this analysis focused on differentiating the HRI 

potentials associated with major design considerations: online year, nameplate capacity, and ECP 

type.37

6.1.1 Online Year

Initially the online year parameter was a likely candidate for assessing potential HRIs, but 

operations that were later upgraded and regulatory concerns significantly affect the potential 

HRIs. Figure 6-1 shows the HRI potentials assigned to different units based on the online years.

Units going online after 1990 generally offered the smallest HRI potentials in Figure 6-1; 70% of 

those units fell into Quartiles 1 and 2, so fewer HRI measures were attached to them.

Those going online in the 1970s and 1980s received earliest air pollution control technologies 

and have not necessarily been upgraded in their lifetimes. They also include the supercritical 

units, so their heat rates were competitive with other upgraded units for forty years which could 

explain why those units have not been retired.

6.1.2 Nameplate Capacity

A second likely candidate parameter for describing HRI potentials was the nameplate capacity. 

Figure 6-2 presents histograms showing how the number of potential HRIs is influenced by the 

nameplate capacity. The lowest bars on each graph show that some units of every size category 

have limited potential for HRI, but the highest two bars on each graph indicate that every 

generator size category has some units with high potential for HRI.

If the composition of the first bar in the graphs is compared to the joint composition in the last 

two bars, units with nameplate capacities under 100 MW or over 500 MW are represented 

similarly. However, a higher fraction of units with nameplate capacities between 200 and 500 

MW have significant HRI potentials, and a lower fraction of units with nameplate capacities 

between 100 and 200 MW have significant HRI potentials.

37 ECP types defined on page vii.

59

 
Figure 6-1. Distribution of Units with Particular HRI Potentials by Online Year (Top 

Representing Maxima and Bottom Representing Minima)

60
Figure 6-2. Distribution of Units with Particular HRI Potentials by Nameplate Capacity 

(Top Representing Maxima and Bottom Representing Minima)

6.1.3 ECP Type

Figure 6-3 illustrates how the distributions are affected by ECP type, but no trends are directly 

obvious from this pair of graphs. Half of the B- and C-type units (baghouse and cold-side ESP)

had the maximum HRI potentials below 150 Btu/kWh, but only one third of the H-type units 

(Figure 6-3). Nearly 60% of the unscrubbed units (B1, C1, and H1) and dry scrubbed units (B7 

and CX) had only maximum HRI potentials below 150 Btu/kWh, but only 36% of wet scrubbed 

units (B3, B5, C4, C7, H4, and H7) had maximum HRI potentials below 150 Btu/kWh. Only 

29% of the units with SCR (B5, C7, and H7) had maximum HRI potentials below 150 Btu/kWh.

From these analyses, the controls at the units with the most HRI potential are likely to be

characterized by a combination of these three factors:

• wet scrubbers

• no baghouses or cold-side ESP 

• SCR 

61
Figure 6-3. Distribution of Units with Particular HRI Potentials by ECP Type (Top 

Representing Maxima and Bottom Representing Minima)

Although they do not affect the statistics above significantly, the four H7 units meet this 

description and all had HRI potentials of 976 or 1590 Btu/kWh. The online years for the H7 units 

ranged from 1965 to 1977. Table 6-1 shows the ranges in HRI potentials, the average new heat 

rates if those were applied, and the percentage that may be gained from the HRI potential. Aside 

from the three IG units, the average HRI potentials range from 160-460 Btu/kWh for C1 units to 

440-1130 for H7 units. The average new heat rates for the H7 units even approach those for the 

IG units if all of the HRIs are employed.

62
Table 6-1. Calculated HRI Potentials by ECP Type

ECP 

Code 38

Count 

of 

Total 

Units

Average 

HRI

Potential

(Btu/kWh)

Average New 

Heat Rate 

(Btu/kWh)

Percent 

HRI

Potential

Average 

Capital 

Cost 

($M)

Average 

Fixed 

O&M 

Cost 

($K/yr)

Average 

Variable 

O&M Cost 

($K/yr)

B1 85 170 - 480 11,400 - 11,700 1.4% - 4.0% 32 – 40 630 640

B3 68 230 - 610 10,700 - 11,100 2.0% - 5.4% 30 – 42 590 -

B5 28 290 - 750 9,600 - 10,000 2.8% - 7.3% 45 - 64 830 19

B7 82 170 - 460 10,400 - 10,700 1.6% - 4.2% 24 – 34 450 5

C1 426 160 - 460 11,200 - 11,500 1.4% - 3.9% 29 - 35 590 58

C4 113 330 - 850 9,900 - 10,400 3.1% - 7.9% 46 – 66 900 -

C7 169 360 - 920 9,400 - 9,900 3.5% - 9.0% 56 - 79 1,100 26

CX 15 440 - 1100 10,500 - 11,200 3.7% - 9.7% 60 – 86 1,200 -

H1 21 290 - 810 15,900 - 16,400 1.7% - 4.9% 35 - 44 800 650

H4 13 210 - 560 10,500 - 10,900 1.9% - 5.1% 33 – 48 590 -

H7 4 440 - 1100 9,200 - 9,900 4.2% -11% 77 - 110 1,400 28

IG 3 2 - 2 9,200 - 9,200

0.02% -

0.02% 0.30 - 0.30 10 -

Total Set 1027 230 - 620 10,700 - 11,100 2.1% - 5.5% 36 - 49 710 320

Table 6-1 shows that the minimal percentage in HRI potential is 1.4% (ignoring the three IG 

units). Overall the percentage improvements for the units in the data set average 2.1% using the 

minimum HRI values and 5.5% using the maximum HRIs. The cost data from Table 6-1 will be 

discussed in Section 6.3.

Figure 6-4 also illustrates the range in HRI potentials for the various ECP types within NEMS. 

Aside from the IG units, the B1, B7, and C1 units have the least average HRI potential and the 

smallest range. The CX and H7 units have the highest HRI potentials but have a much greater 

range (indicating the associated uncertainty).

38 ECP types defined on page vii.

63

 
Figure 6-4. Average HRI Potentials for NEMS ECP Types (Left Side of Bar

Represents Minimum HRIs and Right Side Maximum HRIs)

Figure 6-5 presents the average new heat rate that might be associated with the average unit in 

each ECP type. The left sides of the bars represent the average heat rates if the maximum HRI 

potentials are realized with every improvement, and the right sides of the bars represent the 

resultant heat rates when only the minimum HRIs are achieved. The plot shows that B5, C7, H7 

and some C4 units might have heat rates under 10,000 Btu/kWh if the improvements are made. 

64
Figure 6-5. Average New Heat Rates by NEMS ECP Type

In Figure 6-5, the H1 units would continue to average high heat rates (near 16,000 Btu/kWh) 

even if the improvements described in Chapter 5 were all undertaken because EIA’s base heat 

rate median and average for these 21 units are 16,000 and 16,700 Btu/kWh.

6.2 HRI for the Total Data Set

The upper graph in Figure 6-6 shows the range of total HRI potentials for all units in the data set. 

The blue curve represents the fraction of units that have minimum HRI potentials less than the 

indicated value and the red curve those with maximum HRI potentials. For example, 75% of the 

units have minimum HRI potentials less than 490 Btu/kWh and maximum HRI potentials under 

1290 Btu/kWh with all measures employed.

65
Figure 6-6. Fractions of Units with Lower Total HRI Potentials and Lower Percent HRIs

The lower graph in Figure 6-6 presents information in terms of the percent HRI potentials. The 

percentages above 15% in this graph represent mostly C7 units that went online between 1970 

and 1982. The lower graph has a similar shape to the upper one but is smoothed out because each 

computed HRI potential is divided by the reported heat rate for individual units. 

66
Table 6-2 also presents the HRI potentials in tabular form for selected benchmarks 

corresponding to the horizontal lines in Figure 6-6.

Table 6-2. Cumulative Percentiles for the HRI Data Sets

HRI Potential 

(Btu/kWh)

Percent HRI

Potential

Capital Costs

($ million)

O&M Costs

($ million per year)

25th percentile 32 - 120 0.22 - 0.87% 7.9 - 9.9 0.2

50th percentile 230 - 680 1.3 - 3.8% 29 - 41 0.5

75th percentile 490 – 1,300 3.7 - 9.7% 70 - 95 1.6

Maximum 650 – 1,600 6.4 - 16% 100 - 140 2.1

Average 230 - 620 2.0 - 5.5% 36 - 49 1.0

6.3 Associated Costs

Table 6-1 and Table 6-2 also included total cost information about the HRIs, listed by ECP type 

and by percentile, respectively. Aside from the IG units, Table 6-1 shows that capital costs were 

smallest for the 87 B7 units ($24-34 million) and highest for the four H7 units ($77-112 million). 

The total O&M costs were highest for the 21 H1 units ($1.45 million/year) and lowest for the B7 

units ($0.46 million/year). Overall, the average capital costs were estimated between $36 and 

$49 million, the fixed O&M costs at $0.7 million per year and the variable O&M costs at $0.3 

million per year.

Table 6-2 lists the capital and total O&M costs based on percentiles. Those values are displayed 

graphically in Figure 6-7. If the costs were similar between the 25th and 75th percentiles, then one 

might conclude that a reasonable approximation for the costs would be a median value. 

However, the capital costs vary from $7.9 to $95 million between the 25th and 75th percentiles 

and the O&M costs vary from $0.2 and $1.6 million per year. Therefore, the median values ($35 

million and $0.5 million per year) are not good representations of the middle 50% of the data.

67
Figure 6-7. Cumulative Percentile Graphs Depicting HRI Costs at Different Units

In contrast, the first cumulative percentile graph shown in Figure 6-8 has a much tighter 

distribution between the 25th and 75th percentiles. The median value of $130,000-kWh/Btu is not 

far from the 25th percentile value ($110,000-kWh/Btu) or the 75th percentile value ($230,000-

kWh/Btu). However, the range for the total O&M costs divided by the HRI was still between 

$3,500-kWh/Btu-yr and $67,000-kWh/Btu-yr for the middle 50% of the data.

68
Figure 6-8. Cumulative Percentile Graphs Depicting HRI Unit Costs at Different Units

Figure 6-9 shows how the average HRI potentials for the twelve ECP types relate to the capital 

and total O&M costs. The capital costs can be well approximated (r2=0.90) by multiplying the 

HRI potential by $100,000-kWh/Btu, and that agrees well with the median value of $130,000-

kWh/Btu when all of the units were considered in Figure 6-8. 

69
Figure 6-9. Relationship between Costs and HRI Potential for ECP Types

However, the total O&M costs are not well estimated (r2=0.41). The poor approximations of total 

O&M costs are tied to the non-linearity of the variable O&M costs and one HRI measure in 

particular. The HRI described as “Lower air heater outlet temperature by controlling acid dew 

point” may be applied to units without FGD (B1, C1, and H1) but only improves the heat rate by 

5 Btu/kWh at a high variable O&M cost ($390,000 to $1,700,000 per year). Variable O&M costs 

drop to just 2% of the total O&M costs if this one HRI measure is removed from consideration

(r2

=0.95 and slope=$1600-kWh/Btu-yr).

6.4 Other Considerations

No intent to describe these improvements at site level was attempted because every plant is 

unique in design, load demands, coal type, and water availability, among others. Such efforts 

should likely examine more O&M cost variations with plant size and capacity factors. 

Some additional measures could have been included in Chapter 5 but could not be assessed on a 

fleet-wide level. These include:

• Sliding pressure operation

• Boiler draft system control schemes and operating philosophy

• Automated pulverizer supervisory controls and variations with mill design

• Optimum partial load operation of air quality control systems

• Increasing hydrogen purity

• Power supply upgrade for air pollution controls

Some additional measures were not costed in this effort because they are still in the development 

phase. It may be appropriate for the NEMS EMM module to apply a generic technologyimprovement factor to the HRIs for the entire fleet after a decade or two. However, the NSR 

triggering concerns may limit the market penetration.

Figure 6-1, Figure 6-2 and Figure 6-3 also illustrate that the distribution of HRI potentials among 

the units does not form a normal distribution. Half of the units have maximum HRI potentials 

70
less than 150 Btu/kWh, but the remaining half average 1160 Btu/kWh for the maximum HRI

potentials. The nearest unit to the average has a maximum HRI potential of 1290 Btu/kWh. The 

quartile approach to fleet characterization and application of specific controls is likely 

responsible for some of the behavior. These data distributions suggest that users should be 

cautious about applying assumptions about averages to these data types. The cumulative 

percentile approach (Section 6.2) may yield better ranges than the use of averages as 

substitutions for individual units.

The S&L report was working from a fleet average heat rate of 10,400 Btu/kWh, but the EIA 

2012 data had an average heat rate of 11,300 Btu/kWh. A speaker39 at the Annual EPAA&WMA Information Exchange suggested that the heat rates may have risen between 2008 and 

2012 because more coal-fired units were now operating in cycling modes rather than using a 

base load. Another study mentioned that the change in heat rates was due to a change in the 

calculation methodology. The percent HRIs shared in Table 6-1 and Table 6-2 are based on the 

2012 numbers but would have been higher in many cases if 2008 heat rates had been used. For 

example, if the total HRI at a typical plant was 400 Btu/kWh, this would have represented a 

3.8% improvement in 2008 but only 3.5% in 2012.

39 Licata, Anthony, “ASME Heat Rate Improvement,” 39th Annual EPA-A&WMA Information Exchange, Research 

Triangle Park, North Carolina, December 3, 2014.

71

 
7 Recommendations

Several possible directions for future data acquisition or ground truthing are recommended:

1. A utility industry survey could be conducted to assess those heat rate improvement 

measures that have already been deployed at each plant in order to populate future 

databases.

2. Gurbakhash Bhander at U.S. EPA has been developing the GHG Mitigation Options 

Database (GMOD) and Analysis Tool to show the costs associated with various 

operations (including power sector measures such as leakage repair, boiler condenser 

cleaning, and intelligent sootblowers).40 Bhander will notify Leidos when EPA 

management has approved the tool for release, and its numbers would need to be 

converted from lbs CO2/Btu to kWh/Btu before comparing to those values represented in 

this report.

3. Public comments about EPA’s proposed power plant rules and the Clean Power Plan 

likely contain a significant amount of technical data from the utility companies and the 

states about the HRI potential at each of their power plants. These data sources represent 

direct assessments by some rule stakeholders and likely will represent at least minimum 

HRIs and maximum estimated costs. When available, review of this information is 

recommended.

4. Review of the literature for this project has identified the subject of increased coal-fired 

plant cycling operation as an important impact on future performance. While most of the 

U.S. coal-fired plants were generally designed for base-load operation, the increased use 

of intermittent electricity generation, and gas-fired units fed by relatively inexpensive 

natural gas, has altered actual generation conditions such that many of these units now 

operate in a continuous load-following mode to match the generation demand. Therefore, 

these units frequently operate with large load changes throughout the day and week. This 

newer mode of cycling operation for the aging inventory of coal-fired units will result in 

increased plant heat rate (decreased efficiency), even though the actual average capacity 

factor of these units may not change appreciably. This was out of scope for this study, but 

we recommend that EIA further investigate this phenomenon to account for the future 

modeled heat rate performance of the coal-fired plants.

5. Preliminary costing could be sought for the technologies that are still considered in the 

R&D or pilot phase (e.g., nano-coatings on boiler walls that prevent heat degradation). 

Such options would only be available within NEMS in later years. Literature works and 

patents indicate that some degree of success is being made in these areas, but often 

readers would find it difficult to classify the HRIs in these pilot studies as maxima or 

minima. The public literature on these studies generally does not cite costs, so full cost 

evaluations would be necessary for EIA to establish ranges on the capital, operating, and 

maintenance costs across all potential plants.

40 Bhander, G., N. Hutson, J. Rosati, F. Princiotta, K. Pelt, J. Staudt, and J. Petrusa, “GHG Mitigation Options 

Database (GMOD) and Analysis Tool,” International Journal of Greenhouse Gas Control, 26, 2014, 1-8.

72

 
6. Minima and maxima were used to bound the resultant HRI potentials and costs shared in 

this report. However, those values could be viewed as 95th percentile limits two standard 

deviations from an average. A Monte Carlo simulation that allows random selection of 

individual HRI potentials and costs from among each range would likely result in 

smoother distribution curves than those shown in Chapter 6 and would result in best 

guesses for many HRI measures, not just the minimum and maximum values.

The NEMS modeling of HRI changes may also look toward new possibilities:

1. Upgrade the ECP type if a plant triggers NSR, and consider adding these costs as a 

condition associated with the HRI.

2. Allow an assortment of HRI packages to be applied at a unit instead of just a single total 

HRI and associated total cost. These might be scoped out as boiler island, turbine island, 

flue gas, air pollution control, and water treatment improvement packages. However, this 

approach might require five flags associated with units to indicate where HRIs had 

already been made. A second approach would be to have HRI packages assembled for 

different geographic areas based on local climates (e.g., water cooling issues) and/or 

regulations (e.g., acid rain programs).

73
Appendix A. Heat Rate Improvements Assigned to ECP Types41

ECP 

Code

Count 

of Total 

Units

Average 

HRI 

Potential 

(Btu/kWh)

Average New 

Heat Rate 

(Btu/kWh)

Percent 

HRI 

Potential

Average 

Capital 

Cost ($M)

Average 

Fixed 

O&M Cost 

($K/yr)

Average

Variable O&M 

Cost ($K/yr)

Average 

Capital 

Cost 

($M/MW 

NPC)

Average 

Fixed 

O&M 

Cost 

($/yrMW 

NPC)

Average 

Variable 

O&M 

Cost 

($/yr-MW 

NPC)

B1 85 170 - 480 11,000 - 12,000 1.4% - 4.0% 32 - 40 630 330 - 640 0.24 - 0.31 6,000 1,700 -

3,300

B3 68 230 - 610 11,000 2.0% - 5.4% 30 - 42 590 0 0.17 - 0.25 3,800 0

B5 28 290 - 750 10,000 2.8% - 7.3% 45 - 64 830 19 0.087 - 0.13 1,600 36

B7 82 170 - 460 10,000 - 11,000 1.6% - 4.2% 23 - 34 450 5 0.11 - 0.16 2,200 36

C1 426 160 - 460 11,000 - 12,000 1.4% - 3.9% 29 - 35 590 300 - 590 0.27 - 0.35 6,900 2,000 -

4,000

C4 113 330 - 850 10,000 3.1% - 7.9% 46 - 66 900 0 0.12 - 0.17 2,500 0

C7 169 360 - 920 9,400 - 10,000 3.5% - 9.0% 56 - 79 1,100 26 0.11 - 0.15 2,100 55

CX 15 440 - 1,100 10,000 - 11,000 3.7% - 9.7% 60 - 86 1,200 0 0.19 - 0.28 3,900 0

H1 21 290 - 810 16,000 1.7% - 4.9% 35 - 44 800 330 - 650 2.3 - 3.0 63,000 14,000 -

26,000

H4 13 210 - 560 11,000 1.9% - 5.1% 33 - 48 590 0 0.14 - 0.21 2,600 0

H7 4 440 - 1,100 9,200 - 10,000 4.2% - 11% 77 - 110 1,400 28 0.12 - 0.17 2,100 50

IG 3 2 9,200 0.02% 0.3 10 0 0.002 64 0

Total 

Set 1027 230 - 620 11,000 2.1% - 5.5% 36 - 49 710 160 - 320 0.24 - 0.32 5,800 1,300 -2,500

41 ECP types defined on page vii.

74

 
Appendix B. Heat Rate Improvements Assigned to Modified ECP Types (Allowing ECP Types to be 

Categorized by Quartile and Assuring at Least 10 Records in Each Non-IG Group)

ECP Code

Count of 

Total 

Units

Average 

HRI 

Potential 

(Btu/kWh)

Average New 

Heat Rate 

(Btu/kWh)

Percent 

HRI 

Potential

Average 

Capital 

Cost ($M)

Average 

Fixed 

O&M 

Cost 

($K/yr)

Average 

Variable 

O&M 

Cost 

($K/yr)

Average 

Capital 

Cost 

($M/MW 

NPC)

Average 

Fixed 

O&M 

Cost 

($/yrMW 

NPC)

Average 

Variable 

O&M 

Cost 

($/yrMW 

NPC)

B1-Q1 32 2 12,000 0.0% 0.3 10 0 0.007 250 0

B1-Q2 15 40 - 140 11,000 0.3% - 1.2% 22 - 24 360 430 - 870 0.096 - 0.11 1,800 1,700 -

3,400

B1-Q3 18 230 - 680 10,000 2.1% - 6.4% 66 - 84 1,100 690 - 1,400 0.20 - 0.26 3,700 1,800 -

3,500

B1-Q4 20 500 - 1,300 13,000 - 14,000 3.5% - 9.4% 60 - 76 1,400 440 - 830 0.76 - 0.99 20,000 4,500 -

8,400

B3-Q1 13 2 12,000 0.0% 0.3 10 0 0.010 330 0

B3-Q2 24 30 - 130 11,000 0.3% - 1.2% 13 - 15 290 0 0.047 - 0.056 1,100 0

B3-Q3 16 350 - 930 10,000 - 11,000 3.1% - 8.2% 44 - 68 750 0 0.19 - 0.30 3,300 0

B3-Q4 15 620 - 1,600 11,000 5.1% - 13% 65 - 93 1,400 0 0.50 - 0.72 12,000 0

B5C7-Q1 16 2 10,000 0.0% 0.3 10 0 0.003 84 0

B5C7-Q2 42 30 - 120 10,000 0.3% - 1.2% 16 - 20 380 0 0.031 - 0.036 700 0

B5C7H7-Q3 84 370 - 970 9,200 - 10,000 3.6% - 9.5% 64 - 94 1,100 0 0.11 - 0.16 1,800 0

B5C7H7-Q4 59 640 - 1,600 9,100 - 10,000 6.0% - 15% 84 - 120 1,700 86 0.18 - 0.25 3,800 180

B7-Q1 27 2 11,000 0.0% 0.3 10 0 0.002 68 0

B7-Q2 25 30 - 130 10,000 0.3% - 1.2% 15 - 17 340 0 0.035 - 0.042 820 0

B7-Q3Q4 30 440 - 1,100 10,000 - 11,000 3.8% - 9.8% 52 - 77 950 15 0.27 - 0.40 5,400 99

C1H1-Q1 148 2 11,000 0.0% 0.3 10 0 0.006 190 0

C1H1-Q2 117 40 - 140 11,000 0.3% - 1.2% 22 - 25 360 440 - 880 0.12 - 0.13 2,300 2,100 -

4,100

C1H1-Q3 72 230 - 690 11,000 2.0% - 6.0% 53 - 68 1,000 520 - 1,000 0.36 - 0.49 7,700 2,900 -

5,800

C1H1-Q4 110 500 - 1,300 13,000 3.6% - 9.6% 59 - 75 1,400 420 - 790 1.1 - 1.5 31,000 6,500 -

12,000

75
ECP Code

Count of 

Total 

Units

Average 

HRI 

Potential 

(Btu/kWh)

Average New 

Heat Rate 

(Btu/kWh)

Percent 

HRI 

Potential

Average 

Capital 

Cost ($M)

Average 

Fixed 

O&M 

Cost 

($K/yr)

Average 

Variable 

O&M 

Cost 

($K/yr)

Average 

Capital 

Cost 

($M/MW 

NPC)

Average 

Fixed 

O&M 

Cost 

($/yrMW 

NPC)

Average 

Variable 

O&M 

Cost 

($/yrMW 

NPC)

C4-Q1 15 2 11,000 0.0% 0.3 10 0 0.002 80 0

C4-Q2 27 30 - 120 10,000 0.3% - 1.2% 15 - 17 330 0 0.041 - 0.048 940 0

C4-Q3 32 370 - 970 10,000 3.5% - 9.1% 62 - 92 1,000 0 0.13 - 0.20 2,300 0

C4-Q4 39 630 - 1,600 9,500 - 10,000 5.7% - 14% 73 - 100 1,500 0 0.21 - 0.30 4,600 0

CX-Q1Q2Q3Q4 15 440 - 1,100 10,000 - 11,000 3.7% - 9.7% 60 - 86 1,200 0 0.19 - 0.28 3,900 0

H4-Q1Q2Q3 13 210 - 560 11,000 1.9% - 5.1% 33 - 48 590 0 0.14 - 0.21 2,600 0

IG-Q1 3 2 9,200 0.0% 0.3 10 0 0.002 64 0

Total Set 1027 230 - 620 11,000 2.0% - 5.3% 36 - 49 710 160 - 320 0.24 - 0.32 5,800 1,300 -

2,500

76
Appendix C. Modified Heat Rate Improvements Assigned to ECP Types (If Lowering Air Heater Outlet 

Temperature Is Not Considered a Cost-Effective Measure)

ECP 

Code

Count 

of Total 

Units

Average 

HRI 

Potential 

(Btu/kWh)

Average New 

Heat Rate 

(Btu/kWh)

Percent 

HRI 

Potential

Average 

Capital 

Cost ($M)

Average 

Fixed 

O&M Cost 

($K/yr)

Average 

Variable O&M 

Cost ($K/yr)

Average 

Capital 

Cost 

($M/MW 

NPC)

Average 

Fixed 

O&M 

Cost 

($/yrMW 

NPC)

Average 

Variable 

O&M 

Cost 

($/yrMW 

NPC)

B1 85 170 - 480 11,000 - 12,000 1.4% - 4.0% 25 - 33 580 13 0.21 - 0.28 5,600 130

B3 68 230 - 610 11,000 2.0% - 5.4% 30 - 42 590 0 0.17 - 0.25 3,800 0

B5 28 290 - 750 10,000 2.8% - 7.3% 45 - 64 830 19 0.087 - 0.13 1,600 36

B7 82 170 - 460 10,000 - 11,000 1.6% - 4.2% 23 - 34 450 5 0.11 - 0.16 2,200 36

C1 426 160 - 460 11,000 - 12,000 1.4% - 3.9% 22 - 29 540 13 0.23 - 0.31 6,400 140

C4 113 330 - 850 10,000 3.1% - 7.9% 46 - 66 900 0 0.12 - 0.17 2,500 0

C7 169 360 - 920 9,400 - 10,000 3.5% - 9.0% 56 - 79 1,100 26 0.11 - 0.15 2,100 55

CX 15 440 - 1,100 10,000 - 11,000 3.7% - 9.7% 60 - 86 1,200 0 0.19 - 0.28 3,900 0

H1 21 290 - 810 16,000 1.7% - 4.9% 28 - 37 730 13 2.1 - 2.8 59,000 1,400

H4 13 210 - 560 11,000 1.9% - 5.1% 33 - 48 590 0 0.14 - 0.21 2,600 0

H7 4 440 - 1,100 9,200 - 10,000 4.2% - 11% 77 - 110 1,400 28 0.12 - 0.17 2,100 50

IG 3 2 - 2 9,200 0.02% 0.3 10 0 0.002 64 0

Total 

Set 1027 230 - 620 11,000 2.1% - 5.5% 33 - 45 690 12 0.22 - 0.29 5,500 110

77
Appendix D. Modified Heat Rate Improvements Assigned to Modified ECP Types (If Lowering Air 

Heater Outlet Temperature Is Not Considered a Cost-Effective Measure)

ECP Code

Count 

of Total 

Units

Average 

HRI 

Potential 

(Btu/kWh)

Average New 

Heat Rate 

(Btu/kWh)

Percent 

HRI 

Potential

Average 

Capital Cost 

($M)

Average 

Fixed 

O&M 

Cost 

($K/yr)

Average 

Variable 

O&M 

Cost 

($K/yr)

Average 

Capital 

Cost 

($M/MW 

NPC)

Average 

Fixed 

O&M Cost 

($/yr-MW 

NPC)

Average 

Variable 

O&M 

Cost 

($/yr-MW 

NPC)

B1-Q1 32 2 12,000 0.02% 0.3 10 0 0.007 250 0

B1-Q2 15 30 - 130 11,000 0.3% - 1.2% 12 - 14 280 0 0.059 -

0.071 1,400 0

B1-Q3 18 220 - 670 10,000 2.1% - 6.3% 49 - 67 1,000 0 0.16 - 0.22 3,400 0

B1-Q4 20 490 - 1,300 13,000 - 14,000 3.5% - 9.3% 51 - 68 1,300 54 0.68 - 0.91 19,000 560

B3-Q1 13 2 12,000 0.02% 0.3 10 0 0.010 330 0

B3-Q2 24 30 - 130 11,000 0.3% - 1.2% 13 - 15 290 0 0.047 -

0.056 1,100 0

B3-Q3 16 350 - 930 10,000 - 11,000 3.1% - 8.2% 44 - 68 750 0 0.19 - 0.30 3,300 0

B3-Q4 15 620 - 1,600 11,000 5.1% - 13% 65 - 93 1,400 0 0.50 - 0.72 12,000 0

B5C7-Q1 16 2 10,000 0.02% 0.3 10 0 0.003 84 0

B5C7-Q2 42 32 - 120 10,000 0.3% - 1.2% 16 - 20 380 0 0.031 -

0.036 700 0

B5C7H7-Q3 84 370 - 970 9,200 - 10,000 3.6% - 9.5% 64 - 94 1,100 0 0.11 - 0.16 1,800 0

B5C7H7-Q4 59 640 - 1,600 9,100 - 10,000 6.0% - 15% 84 - 120 1,700 86 0.18 - 0.25 3,800 180

B7-Q1 27 2 11,000 0.02% 0.3 10 0 0.002 68 0

B7-Q2 25 32 - 130 10,000 0.3% - 1.2% 15 - 17 340 0 0.035 -

0.042 820 0

B7-Q3Q4 30 440 - 1,100 10,000 - 11,000 3.8% - 9.8% 52 - 77 950 15 0.27 - 0.40 5,400 99

C1H1-Q1 148 2 11,000 0.02% 0.3 10 0 0.006 190 0

C1H1-Q2 117 32 - 130 11,000 0.3% - 1.2% 12 - 14 280 0 0.073 -

0.090 1,800 0

C1H1-Q3 72 220 - 680 11,000 1.9% - 5.9% 41 - 56 870 0 0.30 - 0.43 7,000 0

C1H1-Q4 110 490 - 1,300 13,000 3.5% - 9.6% 50 - 66 1,300 51 1.0 - 1.4 29,000 810

C4-Q1 15 2 11,000 0.02% 0.3 10 0 0.002 80 0

78
ECP Code

Count 

of Total 

Units

Average 

HRI 

Potential 

(Btu/kWh)

Average New 

Heat Rate 

(Btu/kWh)

Percent 

HRI 

Potential

Average 

Capital Cost 

($M)

Average 

Fixed 

O&M 

Cost 

($K/yr)

Average 

Variable 

O&M 

Cost 

($K/yr)

Average 

Capital 

Cost 

($M/MW 

NPC)

Average 

Fixed 

O&M Cost 

($/yr-MW 

NPC)

Average 

Variable 

O&M 

Cost 

($/yr-MW 

NPC)

C4-Q2 27 32 - 120 10,000 0.3% - 1.2% 15 - 17 330 0 0.041 -

0.048 940 0

C4-Q3 32 370 - 970 10,000 3.5% - 9.1% 62 - 92 1,000 0 0.13 - 0.20 2,300 0

C4-Q4 39 630 - 1,600 9,500 - 10,000 5.7% - 14% 73 - 100 1,500 0 0.21 - 0.30 4,600 0

CX-Q1Q2Q3Q4 15 440 - 1,100 10,000 - 11,000 3.7% - 9.7% 60 - 86 1,200 0 0.19 - 0.28 3,900 0

H4-Q1Q2Q3 13 210 - 560 11,000 1.9% - 5.1% 33 - 48 590 0 0.14 - 0.21 2,600 0

IG-Q1 3 2 9,200 0.02% 0.3 10 0 0.002 64 0

Total Set 1027 230 - 620 11,000 2.0% - 5.3% 33 - 45 690 12 0.22 - 0.29 5,500 110

79
Appendix E. Midpoints between Minima and Maxima in Appendix A*

ECP 

Code

Count 

of 

Total 

Units

HRI 

Potential 

(Btu/kWh)

New Heat Rate 

(Btu/kWh)

Percent 

HRI 

Potential

Capital 

Cost ($M)

Fixed 

O&M Cost 

($K/yr)

Variable 

O&M Cost 

($K/yr)

Capital 

Cost 

($M/MW 

NPC)

Average 

Fixed 

O&M 

Cost 

($/yrMW 

NPC)

Average 

Variable 

O&M 

Cost 

($/yr-MW 

NPC)

B1 85 300 12,000 3% 40 600 500 0.30 6000 3000

B3 68 400 11,000 4% 40 600 0 0.20 4000 0

B5 28 500 9,800 5% 50 800 20 0.10 2000 40

B7 82 300 11,000 3% 30 500 5 0.10 2000 40

C1 426 300 11,000 3% 30 600 400 0.30 7000 3000

C4 113 600 10,000 5% 60 900 0 0.10 2000 0

C7 169 600 9,600 6% 70 1,000 30 0.10 2000 60

CX 15 800 11,000 7% 70 1,000 0 0.20 4000 0

H1 21 600 16,000 3% 40 800 500 3.00 60000 20000

H4 13 400 11,000 3% 40 600 0 0.20 3000 0

H7 4 800 9,600 8% 90 1,000 30 0.10 2000 50

IG 3 2 9,200 0.0% 0 10 0 0.00 60 0

TOTAL 

SET 1027 400 11,000 4% 40 700 200 0.30 6000 2000

* This table presents the midpoints between the minima and maxima. Determination of actual averages would require enough full-scale plant evaluations to 

determine the appropriate distributions of data between the minima and maxima.

80
Appendix F. Midpoints between Minima and Maxima in Appendix B*

ECP Code

Count of 

Total 

Units

HRI Potential 

(Btu/kWh)

New Heat Rate 

(Btu/kWh)

Percent HRI 

Potential

Capital 

Cost ($M)

Fixed O&M 

Cost 

($K/yr)

Variable O&M 

Cost ($K/yr)

Capital Cost 

($M/MW 

NPC)

Average 

Fixed 

O&M Cost 

($/yr-MW 

NPC)

Average 

Variable 

O&M Cost 

($/yr-MW 

NPC)

B1-Q1 32 2 12,000 0.0% 0 10 0 0.01 200 0

B1-Q2 15 90 11,000 0.8% 20 400 700 0.10 2000 3000

B1-Q3 18 500 10,000 4% 70 1000 1000 0.20 4000 3000

B1-Q4 20 900 13,000 6% 70 1000 600 0.90 20000 6000

B3-Q1 13 2 12,000 0.0% 0 10 0 0.01 300 0

B3-Q2 24 80 11,000 0.7% 10 300 0 0.05 1000 0

B3-Q3 16 600 11,000 6% 60 700 0 0.20 3000 0

B3-Q4 15 1000 11,000 9% 80 1000 0 0.60 10000 0

B5C7-Q1 16 2 10,000 0.0% 0 10 0 0.00 80 0

B5C7-Q2 42 80 9,900 0.8% 20 400 0 0.03 700 0

B5C7H7-Q3 84 700 9,500 7% 80 1000 0 0.10 2000 0

B5C7H7-Q4 59 1000 9,500 10% 100 2000 90 0.20 4000 200

B7-Q1 27 2 11,000 0.0% 0 10 0 0.00 70 0

B7-Q2 25 80 10,000 0.8% 20 300 0 0.04 800 0

B7-Q3Q4 30 800 11,000 7% 60 900 10 0.30 5000 100

C1H1-Q1 148 2 11,000 0.0% 0 10 0 0.01 200 0

C1H1-Q2 117 90 11,000 0.8% 20 400 700 0.10 2000 3000

C1H1-Q3 72 500 11,000 4% 60 1000 800 0.40 8000 4000

C1H1-Q4 110 900 13,000 7% 70 1000 600 1.00 30000 9000

C4-Q1 15 2 11,000 0.0% 0 10 0 0.00 80 0

C4-Q2 27 80 10,000 0.8% 20 300 0 0.04 900 0

C4-Q3 32 700 10,000 6% 80 1000 0 0.20 2000 0

C4-Q4 39 1000 10,000 10% 90 2000 0 0.30 5000 0

CX-Q1Q2Q3Q4 15 800 11,000 7% 70 1000 0 0.20 4000 0

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ECP Code

Count of 

Total 

Units

HRI Potential 

(Btu/kWh)

New Heat Rate 

(Btu/kWh)

Percent HRI 

Potential

Capital 

Cost ($M)

Fixed O&M 

Cost 

($K/yr)

Variable O&M 

Cost ($K/yr)

Capital Cost 

($M/MW 

NPC)

Average 

Fixed 

O&M Cost 

($/yr-MW 

NPC)

Average 

Variable 

O&M Cost 

($/yr-MW 

NPC)

H4-Q1Q2Q3 13 400 11,000 3% 40 600 0 0.20 3000 0

IG-Q1 3 2 9,200 0.0% 0 10 0 0.00 60 0

TOTAL SET 1027 400 11,000 4% 40 700 200 0.30 6000 2000

* This table presents the midpoints between the minima and maxima. Determination of actual averages would require enough full-scale plant evaluations to 

determine the appropriate distributions of data between the minima and maxima.

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