Estimating Labor Effects of Heat Rate Improvements

By

James E. Staudt, PhD

Andover Technology Partners

112 Tucker Farm Road

North Andover, MA  01845

(978) 683‐9599

www.AndoverTechnology.com 

March 6, 2014
Table of Contents

Chapter           Page

  Background                   1

  HR Improvement Methods               2

  HR Reduction Cost Components             4

  Estimates of HR Improvement and Cost           13

  Calculating FTEs Resulting from HR Improvement or from New Facilities    19

  Appendix A                   22
List of Acronyms

AFUDC Allowance for Funds Used During Construction

ASME American Society of Mechanical Engineers

BART Best Available Retrofit Technology

BLS Bureau of Labor Statistics

BOP Balance of Plant

CAAA Clean Air Act Amendments

CLRC Construction Labor Research Council

CSAPR Cross State Air Pollution Rule

EPA United States Environmental Protection Agency

FGD Flue gas desulfurization

FOM Fixed Operating and Maintenance cost

FTE Full Time Equivalent

GHG Greenhouse Gas

GMOD Greenhouse Gas Mitigation Options Database

GWe Gigawatt (electric)

HR Heat Rate

IAQR Interstate Air Quality Rule

IGCC Integrated Gasification Combined Cycle

IPM Integrated Planning Model

kW Kilowatt

MWe Megawatt (electric)

NAAQS National Ambient Air Quality Standards

NACBE National Association of Construction Boilermaker Employers

NEEDS National Electric Energy Data System

NGCC Natural Gas Combined Cycle

PC Pulverized Coal

SCR Selective catalytic reduction

UARG Utility Air Regulatory Group
www.AndoverTechnology.com 1

Background

Improvements in heat rate (HR) are one way to reduce greenhouse gas (GHG) emissions from coal

power plants. EPA intends to estimate what labor effects pending regulations on greenhouse gases

(GHG) may have, particularly with regard to construction labor associated with installing equipment and

with labor associated with continuing maintenance.  

Framework:

EPA has provided a framework for the capital cost and level of HR improvement to be used broadly

across the coal fleet.

• Capital cost of $100/kw, based on S&L study1

• 6% HR improvement1

ATP will use supporting engineering studies to develop labor estimates, using proxies:

• Low NOx burners

• Other pollution controls (EPA assumptions in IPM)

ATP will also develop methods to develop estimates of labor for new fossil power plants.

EPA has asked ATP and ICF to make estimates of the employment effects of HR improvements as well as

new plants.  To this end, ATP has collected information that permits estimation of the labor contribution

to the capital and operating cost of HR improvement methods and for new power plants.  Using this

information with information on the cost of improvements and information on labor charge rates, it is

possible to determine the jobs impact of NSPS for existing units measured in terms of full time

equivalents (FTEs)2 that may result from HR improvements on existing units and also from construction

of new units.

ATP prepared a memorandum regarding Labor Requirements for Various Compliance Actions for the

Proposed EGU GHG NSPS Rule on September 14, 2011.3

  This report will serve to both update that

memorandum and to provide additional analysis.

                                                            

1 None of the individual approaches discussed in the Sargent & Lundy study cost $100/kW or provide 6%

improvement in HR but several of the approaches combined might collectively cost $100/kW and provide

6% improvement in HR. 2 One FTE is equivalent to one person fully employed for one year, two people fully employed for 6 months or one

person employed half time for two years, or any other equivalent combination. 3 Memo J. Staudt to Saha, B., “Labor Requirements for Various Compliance Actions for the Proposed EGU GHG

NSPS Rule”, September 14, 2011
www.AndoverTechnology.com 2

HR Improvement Methods

Methods for heat rate (HR) improvement that are available for application to coal‐fired power plants

vary widely.  In general, they fall into one of three categories:

1. Boiler and furnace efficiency improvement – these methods improve the efficiency at which the

boiler converts the chemical energy in the fuel to energy in the form of high pressure steam.

2. Steam plant improvement – these methods improve the efficiency at which the steam plant

(steam turbine and associated equipment) convert the energy in the high pressure steam into

power being produced by the turbine that drives an electrical generator.  

3. Reduction of parasitic loads – these methods entail ways to reduce the power consumed by

auxiliary equipment that supports the boiler and the steam plant.

As a result, there is a wide range of methods available to provide incremental HR improvement to coal‐

fired power plants; however, it is important to note that the methods available for any particular plant

and the improvement that is possible will vary by facility.  This is discussed in some more detail later.

In 2009, Sargent & Lundy published a paper for EPA that discussed a number of methods for improving

heat rate.4

   The study had a compilation of information gathered in case studies.  Each of the methods

discussed in the study fall into one of the above categories.  The study provided estimates of cost and

heat rate improvement for each of the methods discussed.  Some key points regarding this report.

• It does not provide an exhaustive list of methods to reduce heat rate, as it is limited to the

methods where Sargent & Lundy had information.  As a result there are other methods available

that may not be listed in the Sargent & Lundy study.

• As cautioned by Sargent & Lundy in the report, for any given facility, methods listed in the

Sargent & Lundy study may or may not be applicable or may achieve somewhat different results

or have a different cost because each facility has its own unique set of circumstances.  For

example, if air preheater seals are already operating well, there will be no benefit to

replacement of air preheater seals.

• The Sargent & Lundy study, while providing information on total capital cost and total fixed and

variable operating cost, does not show the components of these costs in terms of labor versus

material or other information that can be used to determine the labor demands of the

documented methods.

• The Sargent & Lundy study does not state the time needed to perform each of the HR reduction

methods.  Because most of these are individually modest projects, they individually will

probably take less than a year.  On the other hand, it may be possible that several methods

                                                            

4 Sargent & Lundy, “Coal‐Fired Power Plant Heat Rate Reductions”, SL‐009597, Final Report, January 22, 2009
www.AndoverTechnology.com 3

could be used in combination, and it may be necessary to take a longer period of time to

collectively put them in place.

Appendix A has tables that summarize some of the results of this study and were developed for use in

EPA’s Greenhouse Gas Mitigation Options Database.  The capital costs of these individual retrofit

projects generally are low, with the capital costs for individual methods being up to around $40/kW

(turbine upgrade on 250 MW unit with estimated 2.57% HR improvement).  Per the report, the costs

stated in the report are in 2008 dollars.  Using the Chemical Engineering Plant Cost Index (CEPCI) to

escalate the cost to 2012 dollars will raise the cost only about 1.5%.5

A more recent study by the American Society of Mechanical Engineers’ (ASME) Research Committee on

Energy, Environment, and Waste documents an evaluation of improvements possible for coal utility

boiler fuel delivery systems. 6

  In this study the authors found significant savings, in large part as a result

of HR reductions resulting from improvements to the fuel handling and delivery systems, such as new

feeders, coal pipe modifications, burner modernization and burner controls.  The capital costs ranged

from $11.20/kW to $27.25/kW.  In this effort the authors estimated that engineering and project

management comprised 20% of the total project value (or 25% of the total of all other costs).  The

estimates did not show the breakdown for construction labor costs within each of the other cost

components.

So, based upon these studies, EPA’s assumption of $100/kW capital cost to achieve a 6% HR

improvement would potentially be achieved through a combination of methods that collectively would

result in a 6% improvement and a cost of about $100/kW.  This assumption will be examined further

later in this report.

                                                            

5 CEPCI for 2008 is 575.4 and the CEPCI for 2012 is 584.6 6 Sommerlad, R., et. al., “The Case for Utility Boiler Fuel Delivery System Upgrades”, Power Magazine, July 1, 2013
www.AndoverTechnology.com 4

HR Reduction Cost Components

The cost of improving heat rate, or any utility project for that matter, will be composed of the following

components:

• Material – the steel, concrete, wires, piping, etc. that are necessary for the project

• Labor – the skilled labor necessary to modify the equipment

• Equipment – major pieces of equipment, such as motors, pumps, fans, heat exchangers, etc.

• Engineering and project management – the cost of engineering to design the project and the

management necessary to oversee it

• Overhead and other owner’s costs – other costs incurred by the owner, such as purchasing,

administration, etc.

In the memo prepared in 20113 the one‐time capital costs were allocated four ways:

• cost of equipment (large motors, fans, heat exchangers, etc.)

• materials (structural steel, etc.)

• the construction labor to install the equipment (hourly, skilled, “blue collar” labor) and,

• associated engineering and management labor (salaried, “white collar” labor).  

The “Overhead and other owner’s costs” and the “Engineering and project management”  in the first

group would contribute to the “white collar” labor portion of the second.

To determine the labor associated with a particular project, it is necessary to have an understanding of

how much of the total cost of a project is associated with the labor and engineering components as

opposed to materials and equipment.  With knowledge of the contribution of these components and

information on typical fully‐loaded charge rates (inclusive of benefits, etc.), it is possible to estimate the

employment impact (in terms of man‐hours or full‐time equivalents) that would result from a project of

a given total contract value.  Unfortunately, the studies available on heat rate improvement cost by

Sargent & Lundy did not provide a breakdown in the share of the various cost components – simply

providing a total.  

Because of the range of possible projects that might be pursued to improve heat rate, there is no single

breakdown between the various component costs for a given HR reduction project that can be used.  

Moreover, since these are generally smaller projects, detailed cost estimates are not published.  As a

result, to make an estimate of the range in potential breakdown in these cost components, it is

necessary to use surrogate projects, or “proxies”, that may be similar in scope and where there are

published breakdowns in cost.
www.AndoverTechnology.com 5

Proxies from 2011 effort

In 2011 ATP used as one proxy, specific cost elements from the estimated cost of construction of a new

power plant.  In this proxy, Case 9 (Subbituminous PC Unit without CO2 Capture) of a baseline NETL

study7 was used.  Excluding those portions of the cost estimate that entail purchase and installation of

very large pieces of equipment (i.e., boiler, turbine‐generator, scrubber, coal and reagent prep

equipment, etc. where the cost is mostly from large pieces of equipment that would not be replaced but

perhaps modified somewhat in a heat rate improvement program), or portions of the estimate that are

otherwise unrepresentative of the type of work performed for heat rate improvements (buildings,

improvements to site), leaves the two items in Table 1 that provide a breakdown of costs between the

four cost components.

Table 1.  Cost Items for Proxy #1: Construction of Power Plant

(from NETL 2010, Case 9)

Cost, thousand dollars

Item # Item Description Eqmt Mat’l Labor Engineering

10 Ash/Spent Sorbent Handling Sys $4.573 $145 $6.114 $3.030

12 Instrumentation and Control $8.665 $0 $8.786 $3.765

Total $13.2 $145 $14.9 $6.8

Percent of total 37.7% 0.4% 42.5% 19.4%

Another proxy of a dry scrubber retrofit was also examined in the 2011 effort, although it is a less useful

proxy because dry scrubbers are much more expensive capital improvements than HR improvements

that require purchase of much more costly equipment.  These results are shown in Table 2.

Table 2.  Breakdown of Proxy #2, Dry Scrubber Retrofit Costs

Cost Item Cost Percent of Total

Equipment $113,950,200 31.9% 31.9%

Material $47,657,800 13.3% 13.3%

Labor $163,694,500 45.8% 45.8%

Engineering $21,144,700 5.9%

8.9%

Construction Management $6,506,100 1.8%

Start up and Commissioning $3,273,900 0.9%

Training $900,300 0.3%

Total $357,127,500 100%    100%

                                                            

7 Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity

Revision 2, November 2010, DOE/NETL‐2010/1397
www.AndoverTechnology.com 6

Other proxies

In this recent effort, ATP attempted to find more representative proxies than those used in the 2011

effort.  In finding more representative proxies, ATP considered the capital cost as well as the portion of

the facility that is modified for the HR improvement.  ATP considered a range of possible retrofit

projects that have similar capital costs as heat rate improvement projects and where the work may be in

the same parts of the power plant, and determined that combustion control retrofits have similar costs

(when measured in $/kW) and also involve modifications to the boiler (which is one of the three

principal areas for improving heat rates).

ATP has identified numerous   combustion retrofit projects where detailed cost estimate data is

available.  These were in Best Available Retrofit Technology (BART) submittals from coal‐fired power

plants located in the states of Wyoming or Arizona.  These estimates of combustion control cost were

accepted by the EPA regions.8 The costs for these retrofits were roughly consistent with the capital cost

range expected for these projects in general and are therefore not considered atypical.9

In addition, EPA’s Control Cost Manual provides guidance on breakdown of cost for specific project

types, including maintenance (some of the heat rate reduction methods would fall into the category of

maintenance activities), as well as installation of specific equipment, such as fans,, that might be similar

to some of the heat rate reduction methods.

Using these sources, it is possible to estimate ranges of the cost components (percent of total capital

cost) and identify how much will directly contribute to construction, engineering or project management

employment.

Review of Regions 8 and 9 BART Submittal Information

ATP reviewed the cost estimates for BART submittals for Cholla units 3 & 4, Dave Johnston Units 3 & 4,

Jim Bridger Units 1‐4, Naughton Units 1‐3 and for Wyodak.10

                                                            

8 ATP assisted Regions 8 and 9 on review of these BART submittals and generally accepted these combustion

control cost estimates with the exception of those portions of the costs, such as financing costs, that are not

included in the overnight cost methodology used in BART analyses.  In many cases costs of other forms of control,

such as SCR, were not accepted, although the estimates of combustion controls were largely accepted. 9 IPM Documentation, Chapter 5, Section 5.2.1 Combustion Controls 10 CH2M Hill, “BART Analysis for Cholla Unit 3”, January 2008

CH2M Hill, “BART Analysis for Cholla Unit 4”, January 2008

CH2M Hill, “BART Analysis for Dave Johnston Unit 3”, December 2007

CH2M Hill, “BART Analysis for Dave Johnston Unit 4”, December 2007

CH2M Hill, “BART Analysis for Jim Bridger Unit 1”, December 2007

CH2M Hill, “BART Analysis for Jim Bridger Unit 2”, December 2007

CH2M Hill, “BART Analysis for Jim Bridger Unit 3”, December 2007

CH2M Hill, “BART Analysis for Jim Bridger Unit 4”, December 2007

CH2M Hill, “BART Analysis for Naughton Unit 1”, December 2007

CH2M Hill, “BART Analysis for Naughton Unit 2”, December 2007

CH2M Hill, “BART Analysis for Naughton Unit 3”, December 2007

CH2M Hill, “BART Analysis for Wyodak”, December 2007
www.AndoverTechnology.com 7

In these estimates, costs were broken down into the following cost components:

• Major Materials Design and Supply – this includes all major process equipment, materials,

design engineering by the equipment supplier, fabrication, and delivery to site

• Construction – this is the construction effort to install the equipment and is comprised almost

entirely of labor

• Balance of Plant – this is labor and material associated with the balance of plant equipment

• Electrical ‐ this is labor and materials associated with the electrical modifications

• Owner’s Costs – this includes owner’s project management, engineering, procurement, etc.

• Surcharge – this includes charges by the EPC contractor and associated engineering, project

management costs, etc.

• Allowance for Funds Used During Construction (AFUDC) – these are financing costs

• Contingency – this is for scope items not otherwise included in the cost

In order to be consistent with the approach already used in the 2011 NSPS jobs analysis, we determined

that these 8 cost elements should be converted into the four cost elements of the 2011 memorandum.

In the cost breakdown here the Major Materials Design and Supply are the purchased equipment

(burners, fans, etc.) and associated materials as well as the engineering and fabrication labor.  Balance

of Plant includes the material and labor associated with other equipment that needed to be added or

modified (auxiliaries such as compressed air systems, ductwork modifications, etc.) as a result of the

combustion retrofit.

Focusing on the costs of Low NOx Burners and Overfire Air (including normal Overfire Air,   Separated

Overfire Air and  Rotating Overfire Air (ROFA)) from these studies, the total costs (including AFUDC)

ranged from about $16/kW to $72/kW in total capital cost ($18/kW to $80/kW adjusted to 2012

dollars), and about $16/kW to $70/kW excluding AFUDC and ($17/kW to $77/kW adjusted to 2012

dollars).  In 2012 dollars, the median cost was $26.30/kW ($25.20/kW excluding AFUDC).  Recalling that

the individual methods covered in the 2009 Sargent & Lundy study had a maximum capital cost of up to

around $40/kW, the capital costs of the combustion retrofits are in the same range as the HR reduction

methods in the Sargent & Lundy study and the fuel system improvement study by ASME.

The estimates from the BART analyses are “factored up” estimates, in that they assumed factors for

each element of cost relative to the cost of the Major Materials Design and Supply.  For the purpose of

this study, AFUDC will be ignored because most heat rate improvement projects are small enough

projects that they can be completed in a short enough time that AFUDC can be ignored. 11  For the

purpose of estimating the percent of material versus labor for the whole project, contingency will be

                                                            

11 Even though several individual heat rate improvement projects may be combined to result in a larger program

that might take somewhat longer, this is still a reasonable assumption because even if several heat rate

improvement projects are combined to collectively cost $100/kW, this is still a small enough project that it might

be completed within a year.  Even if spread over a period of several years AFUDC is a financing cost and is not

important from the perspective of estimating construction labor.
www.AndoverTechnology.com 8

ignored since it will be assumed that the percent of labor versus material for contingency is similar to

the rest of the project.

The average percent breakdown between cost components is shown in Table 3.  Assuming that the

Balance of Plant (BOP) and Electrical are combined into one Balance of Plant and also have the same

split between labor and materials as the other portions and that the Surcharge and Owner’s costs are

primarily engineering and project management, these costs can be further reduced to: Materials; BOP

Material, Construction Labor; Engineering and Project Management Labor,

Table 3.  Breakdown between cost components for combustion retrofit projects

Materials, design, supply 37.7% Materials, design, supply 38%

Construction 29.6% Construction labor 39%

BOP 19.4% BOP Material 12%

Elect 2.3% Engineering/Proj. Mgt 11%

Owners cost 4.8%

Surcharge 6.2%

The values for Engineering/Project Management in Table 3 do not include project management,

engineering and technician labor by the equipment or material suppliers who provide the hardware and

material that is delivered to the site.  This labor component is included in the Materials, design, supply

component.  If the engineering and other labor were to be removed from this portion and moved to the

Engineering/Project Management component, the total labor component would be higher and the

Materials, design, supply component lower.

The study by ASME of fuel system improvements indicated a cost for engineering and project

management of 20% of total cost, which also suggests that the breakdown shown in Table 3

underestimates the contribution of engineering and project management to total cost.

Therefore, an alternative to the breakdown shown in Table 1 would move 9% of the cost from Materials

and BOP Materials component to the Engineering/Project Management component. Moving that 9%, in

proportion to each materials component, to Engineering/Project Management and rounding to the

nearest 5% results in a breakdown of what is shown in Table 4 under the Comb. Retrofits/ASME Proxies

and this is compared to what was determined in the 2011 Memorandum.  It should be noted that since

there is no “one size fits all” proxy for HR improvement, either one of these breakdowns may provide

reasonable results.

Table 4.  Estimated breakdown of component costs for HR improvement

Comb. Retrofits/ASME Proxies 2011 Memorandum

Major Eqmt. & Materials 30% 30%

BOP Materials 10% 10%

Construction Labor 40% 50%

Engineering/Proj. Mgt. 20% 10%
www.AndoverTechnology.com 9

The  Comb. Retrofits/ASME Proxies values are roughly consistent with the breakdown shown in Table 1

from the 2011 memorandum.

Regarding the nature of the equipment and materials used in a HR improvement program, the types of

equipment and materials used in a HR improvement project will vary widely from one project to

another, and it is not possible to establish any one specific list.  For example, if a HR improvement

project is a conversion of a large motor to a variable speed drive, the equipment and materials will be

very different from that of a turbine overhaul, or the modification of an air preheater.

Labor component of Annual or Maintenance costs resulting from HR Improvement Projects

Fixed operating and maintenance (FOM) costs are incurred annually and may result from some HR

improvement projects.  They are primarily the maintenance labor and materials that are necessary to

ensure that the HR improvement is maintained in the years after the HR improvement modification is

made.  According to the US EPA Cost Control Manual, maintenance materials are assumed to be roughly

equal to 100% of the labor.12  Or, in other words, the fixed operating and maintenance costs are

comprised of roughly equal portions of labor and materials.  FOM is then comprised of:   

 50% labor

 50% materials

Hence, increases in FOM that result from HR improvement projects will contribute to an increase in

maintenance labor that is related to 50% of the increase in the FOM cost that is estimated to result from

the HR improvement.  Values for increases in FOM that result from HR improvement projects are

discussed later in this report.

New Coal and Natural Gas Plant Cost – Portion of Cost that is Labor

As a result of CO2 regulations, new, more efficient power plants might be constructed.  Costs and labor

breakdown for these new power plants are available from the NETL Bituminous Coal Baseline Report.13,

14 Table 5 shows the results of estimates of the split between equipment, material, labor and

engineering labor for six cases shown in that report using the updated costs.  These cases include six

coal cases that include Integrated Gasification Combined Cycle (IGCC), Pulverized Coal (PC), and natural

gas combined cycle (NGCC), and for each power cycle a case with and another without Carbon Capture

and Sequestration (CCS).

                                                            

12 United States Environmental Protection Agency, EPA AIR POLLUTION CONTROL COST MANUAL, Sixth Edition,

EPA/452/B‐02‐001, January 2002, Office of Air Quality Planning and Standards, Section 1, Chapter 2, 2.5.5.3, page

2‐32

13 US Department of Energy, National Energy Technology Laboratory, “Updated Costs (June 2011 Basis) for

Selected Bituminous Baseline Cases”, DOE/NETL‐341/082312 , Final Report, August 2012   14   US Department of Energy, National Energy Technology Laboratory, “Updated Costs (June 2011 Basis) for

Selected Bituminous Baseline Cases”, DOE/NETL‐341/08231, August 2012  
www.AndoverTechnology.com 10

These projects, which entail a great deal more equipment than the retrofit projects, have a much higher

portion of the total in the form of equipment and materials versus labor.  

Table 5.  Cost component ratios for new coal and natural gas power plants

Case Equipment Material Labor Engineering

Case 1 (IGCC, no CCS) 59.5% 7.1% 25.0% 8.3%

Case 2 (IGCC, CCS) 60.2% 6.3% 25.1% 8.4%

Case 11 (supercrit PC, no CCS) 55.3% 5.5% 30.9% 8.4%

Case12 (supercrit PC, CCS) 58.8% 4.1% 28.7% 8.4%

Case 13, (NGCC no CCS) 67.3% 6.9% 18.3% 7.5%

Case 14, (NGCC, CCS) 67.0% 5.1% 20.4% 7.5%

Labor Rates‐ 

Other data that is necessary to estimate employment from the cost information is labor rates.  To

estimate the number of full‐time equivalents (FTEs), one would take the total cost expended for a labor

component and divide by the annual average wages and benefits for that labor.

Industrial Economics took mean annual wage data from the Bureau of Labor Statistic (BLS) and adjusted

it to account for benefits to result in estimated wages for three occupations associated with scrubbers,

and this is shown in Table 6.

For skilled craft labor this may also be determined by using published power plant construction labor

rates from the Construction Labor Research Council (CLRC), which publishes union craft labor rates to

include fully burdened rates.

Table 6.  Estimated costs of labor associated with scrubbers by Industrial Economics15

According to CLRC data, for union boilermakers, the average wage and benefits in the United States was

$55.88/hr as of July 2013, as shown in Table 7 .

16

                                                            

15 Jason Price, Nadav Tanners, and Jim Neumann (IEc) and Roy Oommen (ERG) to Ellen Kurlansky (US EPA),

SUBJECT: Employment Impacts Associated with the Manufacture, Installation, and Operation of Scrubbers,  March

31, 2011
www.AndoverTechnology.com 11

Table 7.  Construction Labor Rates (fully burdened).16

Boilermakers tend to work intermittently and travel between projects. In its analysis for the Interstate

Air Quality Rule (IAQR), EPA had previously estimated that boilermakers would work roughly 1,685

hours per year if fully employed and factoring in travel between sites, vacation, etc. 17  Utility Air

Regulatory Group (UARG) comments suggested an amount closer to 1,500 hours per year as the actual

historical value.18  A 2011 email cited in the 2011 memorandum gave a number of 1,450 hours.19  Using

the most recent estimate this suggests a total compensation package of $81,026 (using 1,450 hrs/yr)

which is well above what was estimated in the Industrial Economics report and is more consistent with

the compensation for iron and steel workers determined by Industrial Economics. Assuming the rate of

compensation increase was steady over the 2008‐2013 period shown in Table 6, 2012 total

compensation would be about $78,500.  The large difference between the estimate from Industrial

Economics and what is estimated here may be explained by the fact that the year for the BLS statistic

that was used by Industrial Economics was a year where demand for boilermakers was low, and

therefore annual compensation was low as well.    The Industrial Economics memorandum was dated

March 2011 and this was at a time when construction boilermaker manhours were well off their peak,

as shown in Figure 1.

Recent (May 2012) BLS data shows annual wages for chemical engineers to be $102,270 and for

mechanical engineers $84,770, for an average of $93,520.20  Using the same ratio of total compensation

to wages as used in the Industrial Economics report, this results in a total compensation of $141,205.

                                                                                                                                                                                                16 CONSTRUCTION LABOR RESEARCH COUNCIL UNION WAGES AND SUPPLEMENTS FOR THE PERIOD 07/01/2008‐

07/01/2013 17 USEPA, “An Analysis of the Impact of Boilermaker Labor Availability on the Installation of Pollution Control

Equipment,” http://www.epa.gov/interstateairquality/tm0008.pdf, January 28, 2004.

18 Cichanowicz, J., Hein, M., Marchetti., J., “ANALYSIS OF CAIR COMPLIANCE SCHEDULE: A RESPONSE TO ICAC

ESTIMATES Analysis Conducted for the Utility Air Regulatory Group”, July 26, 2004 19 Email from Wendell Bell, Chairman of Enerfab, and Board of Directors National Association of Construction

Boilermaker Employers, to James Staudt, July 21, 2011 20 http://www.bls.gov/oes/current/oes_nat.htm#11‐0000, viewed 1/27/14
www.AndoverTechnology.com 12

Figure 1.  Trends in construction boilermaker manhours and start up of SCRs and scrubbers.21

                                                            

21 Staudt, J., E., “ENGINEERING AND ECONOMIC FACTORS AFFECTING THE INSTALLATION OF CONTROL

TECHNOLOGIES ‐ An update”,  December 15, 2011
www.AndoverTechnology.com 13

Estimates of HR Improvement and Cost

ATP has compiled the Sargent & Lundy cost and heat rate improvement data as part of other work for

EPA (EPA’s Greenhouse Gas Mitigation Options Database, or GMOD).  As noted earlier, a HR

improvement program would likely entail combination of several methods to improve HR, and a rational

way for selecting which approach is picked first should be considered.

It is likely that a company would first use methods that provided the largest HR improvement at the

lowest cost and would only use those methods available with higher cost per HR improvement after the

less expensive options had been exhausted.  To this end, the Sargent & Lundy information can be sorted

from lowest capital cost per percent heat rate improvement to highest capital cost per percent of heat

rate improvement, to determine which methods a company might select first (“lowest hanging fruit”).  

In this way, it is possible to construct curves showing the cumulative capital cost versus the cumulative

HR improvement as individual methods are combined from the lowest cost to the highest cost.

When developing the cumulative capital cost versus cumulative HR improvement curves, it is important

to avoid listing methods identified in the Sargent & Lundy report that could not be performed together.   

For example, one would not replace air preheater seals and also replace the air preheater.  Alternatively,

one would not do a turbine upgrade and also a turbine overhaul.  From the Sargent & Lundy report, ATP

assembled select options shown in Tables 7a and 7b, which are for smaller boilers and for roughly 500

MW boilers, respectively.  it should be noted that Tables 8a and 8b are not exhaustive lists, as there are

more items listed in the tables in the Appendices, which are not themselves exhaustive lists.

Having ordered each of the methods from largest HR improvement per dollar of capital cost to lowest in

Tables 7a and 7b, it was possible to develop a cumulative cost curve that shows the total capital cost

expended versus the cumulative HR improvement made.   

HR improvements are often justified without the additional requirement to reduce CO2 emissions

because there is the economic incentive of reducing fuel cost and improving the economic dispatch of

the unit.  For some units, for example, “flagship” units that have a high operating capacity factor, it is

much easier to justify expenditures on HR improvement than for units that have lower operating

capacity factors.  These units may have already employed many cost‐effective methods for improving

HR.  As a result, in practice there will be a wide range of cost versus HR improvement curves across the

fleet of coal fired utility boilers.  Recognizing that for some units, the lowest cost options may not be

available because they have already been applied (less “low hanging fruit”), four cases were examined:

A, B, C, and D.  Tables 7a and 7b show what options are included for each case.  

Cumulative Capital Cost versus HR Curves

Figures 2a and b show curves for cumulative capital cost versus cumulative heat rate reduction as

methods are combined for cases A, B, C and D and for a smaller unit size and a larger (roughly 500 MW

unit size).  As shown by these curves, 6% HR improvement at $100/kW capital cost assumed by CAMD

appears to fall within the range of possibilities.  As shown in Figures 2a and b, for some units that

already have made significant efforts improving their heat rate and don’t have as many HR improvement
www.AndoverTechnology.com 14

opportunities (case D for example), the 6% HR improvement for $100/kW assumption may not be

achievable, while for units that have more opportunities for HR improvement, this assumption may be

easily achievable.  On the other hand, those units that have received less attention in the past on

improving HR and therefore have more opportunities for improving HR may have been ignored for

economic reasons and may be at risk of retirement.

Increases in FOM

HR improvement methods entail some capital improvements and also entail increases in regular

maintenance in order to assure that the HR improvements continue in the future.  This will result in

increased fixed operating and maintenance costs (FOM).   Figures 3a and 3b show the corresponding

cumulative FOM cost versus percent cumulative HR improvement for the same methods used to

develop Figures 2a and 2b.  As shown in Figures 3a and 3b, fixed operating cost rises as HR improvement

increases.  Using the slope of the trend lines to help estimate the change in FOM as a function of HR

improvement, a reasonable estimate of the increase in fixed operating cost may be on the order of

$0.20/kW‐yr per percent improvement in HR.22  Or, a 6% HR improvement would result in an increased

FOM cost of about $1.20/kW‐yr.  So, a 200 MW unit that had a heat rate improvement of 6% would

result in increased FOM costs of 200,000 kW x $1.20/kW‐yr = $240,000/year.  A portion of this FOM

would be associated with maintenance labor and a portion of it would be associated with materials.

                                                            

22 The slope of the best‐fit curves in Figures 3a and 3b are roughly 20, and because it is plotted in cost versus

percent we divide by 100 to get the slope in terms of $/kW‐yr per percent.
www.AndoverTechnology.com 15

Table 8a. List of select HR improvement options in order of cost per percent improvement in HR

(Cost in 2012 dollars. Where 200 MW data wasn’t available, other data was used.)

Technology $/kW/%

improvement A B C D

Existing  MW PC Boiler deploying Heat Rate Reduction by Condenser

Cleaning $0.00 X    

Existing 850 MW PC Boiler ‐ Combustion Optimization reduce O2 $1.26 X    

Existing 200 MW PC Boiler ‐ Intelligent Sootblowers $1.65 X    

Existing 200 MW PC Boiler ‐ Neural Net $2.48 X    

Existing 250 MW PC Boiler ‐ upgrade boiler feed pump $4.05 X X   

Existing 250 MW PC Boiler adding more air heater surface to reduce flue gas

temp $8.60 X X   

Existing  MW PC Boiler deploying Heat Rate Reduction by FGD Modifications $10.00 X X   

Existing  MW PC Boiler deploying Heat Rate Reduction by Acid Dew Point

Control Using Trona Injection $11.63 X X   

Existing  MW PC Boiler deploying Heat Rate Reduction by Combined

Environmental Controls HR Reduction $12.88 X X X

Existing  MW PC Boiler deploying Heat Rate Reduction by Conversion to

Variable Frequency Drive Fans $14.58 X X X

Existing 250 MW PC Boiler ‐ turbine upgrade $15.88 X X X

Existing  MW PC Boiler deploying Heat Rate Reduction by ESP Modifications $16.67 X X X

Existing  MW PC Boiler deploying Heat Rate Reduction by SCR Modifications $20.00 X X X X

Existing  MW PC Boiler deploying Heat Rate Reduction by Cooling Tower

Advanced Packing Upgrade $22.73 X X X X

Existing  MW PC Boiler deploying Heat Rate Reduction by Addition of Turning

Vanes and Distribution Plate in FGD $28.00 X X X X

Existing 250 MW PC Boiler reducing air heater leakage by adding new air

heater seals $30.00 X X X X

Existing  MW PC Boiler deploying Heat Rate Reduction by Conversion of

Centrifugal Fan to Axial Fan $108.33 X X X X
www.AndoverTechnology.com 16

Table 8b. List of select HR improvement options in order of cost per percent improvement in HR

(Cost in 2012 dollars. Where 200 MW data wasn’t available, other data was used.)

Technology $/kW/%

improvement A B C D

Existing 500  MW PC Boiler deploying Heat Rate Reduction by Condenser

Cleaning $0.00 X    

Existing 850 MW PC Boiler ‐ Combustion Optimization reduce O2 $1.26 X    

Existing 500 MW PC Boiler ‐ Neural Net $1.54 X    

Existing 500 MW PC Boiler ‐ Intelligent Sootblowers $1.67 X    

Existing 250 MW PC Boiler ‐ upgrade boiler feed pump $3.95 X X   

Existing 250 MW PC Boiler adding more air heater surface to reduce flue gas

temp $8.60 X X   

Existing  MW PC Boiler deploying Heat Rate Reduction by Conversion to

Variable Frequency Drive Fans $10.18 X X   

Existing  MW PC Boiler deploying Heat Rate Reduction by FGD Modifications $12.00 X X   

Existing  MW PC Boiler deploying Heat Rate Reduction by Combined

Environmental Controls HR Reduction $13.64 X X X

Existing  MW PC Boiler deploying Heat Rate Reduction by Acid Dew Point

Control Using Trona Injection $14.53 X X X

Existing 250 MW PC Boiler ‐ turbine upgrade $15.88 X X X

Existing  MW PC Boiler deploying Heat Rate Reduction by ESP Modifications $16.67 X X X

Existing  MW PC Boiler deploying Heat Rate Reduction by Cooling Tower

Advanced Packing Upgrade $18.18 X X X X

Existing  MW PC Boiler deploying Heat Rate Reduction by SCR Modifications $20.00 X X X X

Existing  MW PC Boiler deploying Heat Rate Reduction by Addition of Turning

Vanes and Distribution Plate in FGD $28.00 X X X X

Existing 250 MW PC Boiler reducing air heater leakage by adding new air

heater seals $30.00 X X X X

Existing  MW PC Boiler deploying Heat Rate Reduction by Conversion of

Centrifugal Fan to Axial Fan $66.67 X X X X
www.AndoverTechnology.com 17

Figure 2a. Cumulative capital cost versus cumulative percent HR improvement estimated for 200 MW

plant, cost in 2012 dollars

Figure 2a. Cumulative capital cost versus cumulative percent HR improvement estimated for 500 MW

plant, cost in 2012 dollars
www.AndoverTechnology.com 18

Figure 3a. Cumulative fixed operating cost versus cumulative percent HR improvement estimated for

200 MW plant, cost in 2012 dollars

Figure 3b. Cumulative fixed operating cost versus cumulative percent HR improvement estimated for

500 MW plant, cost in 2012 dollars
www.AndoverTechnology.com 19

Calculating FTEs Resulting from HR Improvement or from New Facilities

For construction labor and maintenance labor associated with HR reduction programs, a reasonable

total annual compensation (wages and benefits) is about $78,500 using the boilermaker rate.  For

engineering and management, a reasonable total annual compensation rate is $141,000.  

To estimate the job impacts, one would multiply the total cost, times the fraction of the total cost that is

estimated to be from labor, and divide by the total estimated annual compensation for a worker.  For

example, to estimate the labor impact of boiler HR improvements:

One‐Time Construction Labor for boiler HR Improvement

 Total capital cost of the improvement (2012 dollars)  x 0.40/$78,500 = Full Time Equivalents

Construction Labor

One‐Time Engineering and Management Labor for boiler HR Improvement

 Total capital cost of the improvement (2012 dollars) x 0.20/$141,000 = Full Time Equivalents

Engineering Labor

Continuing Maintenance Labor for boiler HR Improvement

 Total FOM increase (2012 dollars) x 0.50/$85,000 = Full Time Equivalents Maintenance Labor

For example, if 200,000 MW (200 million kW) of boilers implement HR improvements at a 2012 dollars23

capital cost of $100/kW and increased FOM cost of $1.20/kW‐yr, then,

 One‐time construction labor = 200,000,000 kW * $100/kW * 0.40/$78,500 = 101,900 FTEs

 One‐time engineering labor = 200,000,000 kW * $100/kW * 0.20/$141,000 = 28,370 FTEs

 Continuing maintenance labor = = 200,000,000 kW * 0.50 * $1.20/kW‐yr / $78,500 = 1,530 FTEs

Calculating the FTEs for new facilities constructed can be performed in a similar manner but using labor

component factors from Table 4 and total capital cost factors for new units.

                                                            

23 Because the HR improvements will occur sometime in the future (not 2012), the HR improvement costs and

labor costs will have to be adjusted for the proper year.
www.AndoverTechnology.com 20

Interpreting this information

It is important to interpret these FTE estimates with care.

Bear in mind that one FTE is the equivalent of one worker working for one year, but may not actually be

one worker working for a full year.  It could alternatively be twelve workers working for a month, two

workers working for six months or a worker at half time over a period of two years.  Therefore, the time

to perform these retrofits is important.

The Sargent & Lundy report doesn’t discuss time frames for these HR improvement projects.  In

estimating the amount of time it would take to perform these retrofits, we can go back to the proxy of

the combustion control retrofits to provide some insight.  Combustion control retrofits typically require

up to about two years to complete, maybe an average of about 18 months and often only a year or so.24  

So, we might assume that an individual method for improving heat rate takes about the same amount of

time if it is roughly the same cost.  But, to get to $100/kW and 6% heat rate improvement, you need to

combine several of these projects together since there is no single one that gets you to 6% improvement

or $100/kW in capital cost.  If you need five or more of these projects (each about $20/kW or less on

average25) then if done sequentially it will take 7.5 or more years, but they won’t be done sequentially.   

If they do up to two at a time with a six month overlap, that’s roughly three and a half years or more.  

So, a roughly 4 year range may be reasonable.  The labor would be spread out pretty evenly over this

period.  Rather than a single project such as a scrubber that has a substantial engineering period that

precedes the very extensive construction labor, it is fair to say that in the case of HR improvements this

would be a series of small projects, each with a portion of construction labor preceded by some

engineering (albeit, far less extensive engineering than for a scrubber).  The labor for a series of HR

improvement projects can therefore be assumed to be spread out roughly evenly over the period.  It is

fair to say that there would likely be a brief initial period that would mainly be the engineering for the

first project, but for the most part labor would be spread pretty evenly over most of the time period

associated with the series of HR improvement projects.

For reasons discussed in the previous paragraph, FTE’s associated with one‐time construction and

engineering jobs will likely be spread over a multiple‐year period as facilities select those methods that

are technically appropriate for their boilers and make those modifications.  If the 101,900 FTEs of

construction labor estimated above are spread over, say, a 5‐year period, that will equate to about

25,000 FTEs per year.  This would include a wide range of construction trades, such as boilermakers,

electricians, iron and steel workers, millwrights, etc.  If 20% of these FTE’s were boilermakers (this was

roughly what it was for the Brandon Shores wet scrubber,26  although that may or may not be very

representative for this situation), that would mean an increase in employment of 5,000 boilermakers

                                                            

24 I looked for something to cite on the time frame for combustion controls, but couldn’t find anything easily.  

Having said that, I can’t imagine any knowledgeable person arguing this point because this is pretty widely

viewed as a reasonable number for a combustion control retrofit. 25 Some will be very inexpensive with regard to capital cost and are quickly implemented while others – such as

turbine retrofits – may cost more than $20/kW and take longer to implement. 26 Andover Technology Partners, “ENGINEERING AND ECONOMIC FACTORS AFFECTING THE INSTALLATION OF

CONTROL TECHNOLOGIES ‐ An update”, December 15, 2011, pg 16
www.AndoverTechnology.com 21

per year.  From Figure 1, the construction boilermaker labor force could easily respond to that increase

in demand as it has in the past.

Similarly, if 500 units (assuming an average size about 400 MW for a total of 200,000 MW) install HR

reduction methods and if the 1,530 FTEs of annual maintenance labor estimated above are spread over

these 500 units, this equates to about 3 FTE’s per unit.  In practice this does not mean that each unit will

have 3 more full‐time maintenance staff.  What is more likely to happen is that there may be some

additional full‐time maintenance staff (let’s say one per plant, just as an example), but the company will

contract out additional maintenance activities that will likely employ several workers for periods of time

that are less than a year.  This is because to sustain the HR improvement, it will be necessary to increase

maintenance activities.  Otherwise, the gains will slowly be lost.

In fact, in the past it was not unusual for there to be a dedicated performance engineer for each unit.   

Today, it is rare to have a dedicated performance engineer.  Dedicated performance engineers have

become less common as companies have reduced staffing costs and maintenance costs and combined

the performance engineer function with other duties, or eliminated it altogether.  There are also

companies that in the past made a good business of performing HR performance testing and HR

optimization of power plants.  There are far fewer of these companies today because of the reduced

budgets for operations and maintenance.  If there is greater emphasis on HR improvements in the future

as a result of CO2 emission requirements, it is likely that performance improvement and maintenance

will receive more attention and resources than it currently does.
www.AndoverTechnology.com 22

Appendix A

The tables on the following pages were developed for US EPA’s Greenhouse Gas Mitigation Options Database using the d

and Lundy Report. These tables were used to estimate the heat rate reductions for a boiler and the estimated costs.
www.AndoverTechnology.com 23

Estimated costs and HR reduction for 200 MW unit

Technology Change in HR

Capitalcost, $/kW kW basis A B FOC equation HR r

Existing 250 MW PC Boiler adding more air heater surface to reduce flue gas temp -0.93% $8.00 250,000 0.000 FOC = A + B * Capital Cost ‐0.9Existing 250 MW PC Boiler reducing air heater leakage by adding new air heater seals -0.04% $1.20 250,000 0.000 FOC = A + B * Capital Cost ‐0.0Existing 250 MW PC Boiler - turbine upgrade -2.57% $40.80 250,000 0.000 FOC = A + B * Capital Cost ‐2.5Existing 250 MW PC Boiler - upgrade boiler feed pump -0.37% $1.50 250,000 0.000 FOC = A + B * Capital Cost ‐0.3Existing 850 MW PC Boiler - Combustion Optimization reduce O2 -0.65% $0.82 850,000 0.000 FOC = A + B * Capital Cost ‐0.6Existing 200 MW PC Boiler - Neural Net -1.01% $2.50 200,000 0.100 FOC = A + B * Capital Cost ‐1.0Existing 200 MW PC Boiler - Intelligent Sootblowers -0.91% $1.50 200,000 0.167 FOC = A + B * Capital Cost ‐0.9Existing MW PC Boiler deploying Heat Rate Reduction by Acid Dew Point Control Using Trona Injection -0.86% $10.00 200,000 0.025 FOC = A + B * Capital Cost ‐0.8Existing MW PC Boiler deploying Heat Rate Reduction by Condenser Cleaning -0.50% $0.00 200,000 30000 0.000 FOC = A + B * Capital Cost ‐0.5Existing MW PC Boiler deploying Heat Rate Reduction by Conversion of Centrifugal Fan to Axial Fan -0.30% $32.50 200,000 50000 0.000 FOC = A + B * Capital Cost ‐0.3Existing MW PC Boiler deploying Heat Rate Reduction by Conversion to Variable Frequency Drive Fans -0.60% $8.75 200,000 20000 0.000 FOC = A + B * Capital Cost ‐0.6Existing MW PC Boiler deploying Heat Rate Reduction by Addition of Turning Vanes and Distribution Plate in FGD -0.02% $0.56 450,000 0 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by FGD Modifications -0.25% $2.50 200,000 25000 0.000 FOC = A + B * Capital Cost ‐0.
www.AndoverTechnology.com 24

Estimated costs and HR reduction for 200 MW unit

Technology Change in HR

Capitalcost, $/kW kW basis A B FOC equation HR r

Existing MW PC Boiler deploying Heat Rate Reduction by ESP Modifications -0.03% $0.50 200,000 12500 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by SCR Modifications -0.05% $1.00 500,000 25000 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by Combined Environmental Controls HR Reduction -0.33% $4.25 200,000 50000 0.000 FOC = A + B * Capital Cost ‐0.3Existing MW PC Boiler deploying Heat Rate Reduction by Cooling Tower Advanced Packing Upgrade -0.33% $7.50 200,000 37500 0.000 FOC = A + B * Capital Cost ‐0.3Existing MW PC Boiler deploying Heat Rate Reduction by Upgrade of Coal Handling and Conveying Motors -0.01% unknown 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by Upgrade of Pulverizer Motors -0.05% unknown 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by Upgrade of Ash Handling Motors -0.01% unknown 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by Upgrade of Condensate Pump Motors -0.02% unknown 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by Upgrade of Miscellaneous Motors -0.02% unknown 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by Upgrade of Steam Turbine Generator Auxiliary Motors -0.01% unknown 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by Upgrade of Cooling Water Pump Motors -0.07% unknown 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by Upgrade of Cooling Tower Fan Motors -0.03% unknown 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.0
www.AndoverTechnology.com 25

Estimated costs and HR reduction for 500+ MW unit

Technology Change in HR

Capitalcost, $/kW kW basis A B FOC equation HR red

Existing 250 MW PC Boiler adding more air heater surface to reduce flue gas temp -0.93% $8.00 250,000 0.000 FOC = A + B * Capital Cost ‐0.9Existing 250 MW PC Boiler reducing air heater leakage by adding new air heater seals -0.04% $1.20 250,000 0.000 FOC = A + B * Capital Cost ‐0.0Existing 250 MW PC Boiler - new steam turbine seals -0.15% $1.50 250,000 0.000 FOC = A + B * Capital Cost ‐0.Existing 850 MW PC Boiler - HP cylinder turbine overhaul -0.38% $0.59 850,000 0.000 FOC = A + B * Capital Cost ‐0.3Existing 850 MW PC Boiler - Combustion Optimization reduce O2 -0.65% $0.82 850,000 0.000 FOC = A + B * Capital Cost ‐0.6Existing 500 MW PC Boiler - Neural Net -0.65% $1.00 500,000 0.100 FOC = A + B * Capital Cost ‐0.6Existing 500 MW PC Boiler - Intelligent Sootblowers -0.60% $1.00 500,000 0.100 FOC = A + B * Capital Cost ‐0.6Existing MW PC Boiler deploying Heat Rate Reduction by Acid Dew Point Control Using Trona Injection -0.86% $12.50 500,000 0.012 FOC = A + B * Capital Cost ‐0.8Existing MW PC Boiler deploying Heat Rate Reduction by Turbine Overhaul -2.01% $24.00 500,000 0.000 FOC = A + B * Capital Cost ‐2.0Existing MW PC Boiler deploying Heat Rate Reduction by Condenser Cleaning -0.50% $0.00 500,000 60000 0.000 FOC = A + B * Capital Cost ‐0.5Existing MW PC Boiler deploying Heat Rate Reduction by Overhaul of Boiler Feed Pumps -0.38% $1.10 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.3Existing MW PC Boiler deploying Heat Rate Reduction by Conversion of Centrifugal Fan to Axial Fan -0.30% $20.00 500,000 85000 0.000 FOC = A + B * Capital Cost ‐0.3Existing MW PC Boiler deploying Heat Rate Reduction by Conversion to Variable Frequency Drive Fans -0.60% $6.11 900,000 50000 0.000 FOC = A + B * Capital Cost ‐0.6
www.AndoverTechnology.com 26

Estimated costs and HR reduction for 500+ MW unit

Technology Change in HR

Capitalcost, $/kW kW basis A B FOC equation HR red

Existing MW PC Boiler deploying Heat Rate Reduction by Addition of Turning Vanes and Distribution Plate in FGD -0.02% $0.56 450,000 0 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by FGD Modifications -0.25% $3.00 500,000 50000 0.000 FOC = A + B * Capital Cost ‐0.2Existing MW PC Boiler deploying Heat Rate Reduction by ESP Modifications -0.03% $0.50 200,000 12500 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by SCR Modifications -0.05% $1.11 900,000 50000 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by Combined Environmental Controls HR Reduction -0.33% $4.50 500,000 87500 0.000 FOC = A + B * Capital Cost ‐0.3Existing MW PC Boiler deploying Heat Rate Reduction by Cooling Tower Advanced Packing Upgrade -0.33% $6.00 500,000 62500 0.000 FOC = A + B * Capital Cost ‐0.3Existing MW PC Boiler deploying Heat Rate Reduction by Upgrade of Coal Handling and Conveying Motors -0.01% unknown 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by Upgrade of Pulverizer Motors -0.05% unknown 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by Upgrade of Ash Handling Motors -0.01% unknown 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by Upgrade of Condensate Pump Motors -0.02% unknown 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by Upgrade of Miscellaneous Motors -0.02% unknown 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by Upgrade of Steam Turbine Generator Auxiliary Motors -0.01% unknown 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by Upgrade of Cooling Water Pump Motors -0.07% unknown 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.0Existing MW PC Boiler deploying Heat Rate Reduction by Upgrade of Cooling Tower Fan Motors -0.03% unknown 500,000 0 0.000 FOC = A + B * Capital Cost ‐0.0