1

MEMORANDUM 

TO: Jim Eddinger, U.S. Environmental Protection Agency, OAQPS 

FROM: Graham Gibson and Amanda Singleton, ERG 

DATE: April 2010 

SUBJECT: Development of Fuel Switching Costs and Emission Reductions for Industrial, 

Commercial, and Institutional Boilers for the National Emission Standards for 

Hazardous Air Pollutants – Area Source 

1.0 INTRODUCTION 

The purpose of this memorandum is to discuss the cost and emission impacts resulting 

from existing boilers switching to natural gas. Fuel switching is a potential control option that 

would require some boilers to convert to natural gas, which emits lower emissions of some 

compounds when combusted compared to most solid and liquid fuels. For many pollutants, fuel 

switching generally results in greater emission reductions than add-on technologies can achieve. 

For this analysis, the cost, emission, and operational impacts of switching biomass, coal and 

liquid fuel boilers to natural gas are presented. 

Section 2.0 summarizes the results of the analysis. Section 3.0 discusses the 

methodology used to estimate the cost and emission impacts of fuel switching. Section 4.0 

presents the emission reduction impacts of fuel switching. Section 5.0 presents references. 

Detailed calculation tables are in Appendix A. 
2

2.0 RESULTS OF ANALYSIS 

Table 2.1 summarizes the capital investment and annual costs estimated for fuel 

switching all area source boilers from their current fuel to natural gas. Fuel switching would 

require nearly $258 billion in capital and over $13 billion in annual costs. Of these totals, boilers 

firing distillate liquids incur 91 percent of the capital costs while boilers firing biomass account 

for the majority of annual costs. Additionally, EPA estimates that boilers located at educational 

services (Standard Industrial Classification (SIC) code 82) will incur the largest portion of all 

capital costs, at 38 percent. Boilers at lumber and wood products facilities (SIC code 24) 

account for the majority of annual costs, at 46 percent. 

Table 2.1 – Summary of Capital and Annual Costs for Fuel Switching to Natural Gas

Fuel Capital Costs 

($, Millions) 

Annual Costs 

($, Millions) 

Biomass 18,720 9,257 

Coal 382 1,228 

Distillate Liquid 235,384 2,288 

Residual Liquid 3,335 288 

Total 257,821 13,060 

The annual costs for biomass are comparatively high because of the added cost to landfill 

biomass diverted from fuel usage and the larger relative difference in fuel prices between natural 

gas and biomass compared with the price difference between natural gas and other fuels. 

Tables 2.2 and 2.3 summarize the emission reductions for selected pollutants as a result 

of fuel switching. These tables show the total amount of emission reductions that could be 

achieved from fuel switching compared to unchanged operation of all units.
3

Table 2.2 – Summary of Emission Reductions of Metallic HAP from Fuel Switching (tpy

Non-Mercury Metallic HAP 

Fuel 

Antimony 

(Sb) 

Arsenic 

(As) 

Beryllium 

(Be) 

Cadmium 

(Cd) 

Chromium 

(Cr) 

Cobalt 

(Co) 

Lead 

(Pb) 

Manganese 

(Mn) 

Nickel 

(Ni) 

Biomass 0.7 3.1 4.7 1.9 (1.2) 0.5 23.0 897.3 0.4 

Coal 2.0 15.0 0.5 0.3 1.7 0.6 11.0 22.3 4.7 

Distillate 

Liquid 135.9 169.0 56.8 25.4 239.6 20.4 318.7 15912.6 205.1 

Residual 

Liquid 1.6 0.8 0.4 0.5 0.5 2.0 1.6 106.6 44.5 

Total 140 188 62 28 241 23 354 16,939 255 

1 Values in parentheses represent an increase in emissions for a specific pollutant as a result of switching to natural gas
4

Table 2.3 – Summary of Emission Reductions of All Other HAP from Fuel Switching (tp

Inorganic HAP Other HAP Organic HAP 

Fuel Hydrogen 

Chloride 

(HCl) 

Hydrogen 

Fluoride 

(HF) 

Sulfur 

Dioxide 

(SO2) 

Mercury 

(Hg) 

Filterable 

Particulate 

Matter 

(PM) 

Carbon 

Monoxide 

(CO) 

Total 

Hydrocarbons, 

as Propane 

(THC) 

Volatile 

Organic 

Compounds 

(VOC) 

Tota

Dioxin

Biomass 1,972 38 25 0.2 74,072 140 2.2 1.2 0.0

Coal 6,752 179 83 1.9 14,951 16 0.2 0.1 0.0

Distillate 

Liquid 2,323 194 28 2.0 14,664 (3.5) 0.5 0.3 0.0

Residual 

Liquid 119 2 48 0.0 1,291 (5) 0.4 0.2 0.0

Total 11,166 413 185 4 104,978 148 3 2 0.0

1 Values in parentheses represent an increase in emissions for a specific pollutant as a result of switching to natural gas. 2 Total mass dioxin/furan values are reported in units of lb/year. 
5

3.0 DESCRIPTION OF COST ANALYSIS 

3.1 Assigning Boilers to Fuel Switching Scenarios 

Since a complete national inventory of area source boilers is unavailable, model units 

were created to assess the impacts of each regulatory option on area source boilers. Model units 

were developed using a data reported to boiler inspector inventories in 13-states. Detailed 

information about the development of model units and the distribution of model units to various 

SIC codes are presented in another memorandum1

. 

As was done in the major source analysis, all area source boilers were assumed to be 

characterized by one of the following three scenarios: 

A. For units that use natural gas as a start-up or back-up fuel only, costs to modify 

the unit to burn solely natural gas were estimated. 

B. The boiler does not use natural gas in any capacity, but the facility does use 

natural gas for some other operation on site. This would require modifications to 

the boiler and upgrades to the on-site gas handling system to distribute gas to the 

boiler. 

C. The facility does not use natural gas at all. This would require modifications to 

the boiler, construction of an on-site gas handling system, and construction of 

piping from the most accessible main gas line. 

Additionally, Scenario C was further divided into four cases to address the potential 

availability of natural gas for each facility. 

C1: The main gas line is close to the plant, but the plant is in a city or near a city. 

Therefore, a higher cost per foot of pipe would be incurred. 

C2: The main gas line is a moderate distance from the plant, and the plant is in a rural 

location. A lower cost per foot of pipe would be incurred. 

C3: The main gas line is far from the plant, and the plant is in a rural location. A 

lower cost per foot of pipe would be incurred. 

C4: Gas is not available at all. 
6

Each model boiler was assigned to a either a coal, biomass, heavy liquid or light liquid 

fuel category. Since the model units did not contain information on start-up or back-up fuels, or 

whether or not natural gas was used at other combustion units at the same facility, the 

distributions assigned to Scenarios A and B were based on the fuel distribution reported for 597 

solid and liquid fuel boilers at area source facilities in the 2008 ICR.2

 If a boiler reported 

combusting natural gas in any capacity in the ICR, it was assigned to Scenario A. Any boiler not 

identified as firing natural gas but located at a facility that had another combustion unit firing 

natural gas was assigned to Scenario B. It was assumed that a natural gas line was available at 

the facility, so costs incurred for switching the boiler to fire natural gas would be for 

modification of the on-site gas handling system and for boiler combustor modifications. 

Scenario C units were assumed to be all the boilers that were not assigned to scenarios A or B. 

Table 3.1 shows the distribution of area source boilers to scenarios A, B, and C according to the 

2008 ICR survey. 

Table 3.1: Distribution of Area Source Boilers to Scenarios A, B, and C in the 2008 ICR Survey 

Fuel Category 

Design Capacity 

Size Range 

(mmBtu/hr) 

Case A 

Distribution 

(%) 

Case B 

Distribution 

(%) 

Case C 

Distribution 

(%) 

Biomass 0 to 10 0.00% 0.00% 100.00% 

Biomass 10 to 100 7.79% 15.58% 76.62% 

Biomass 100 to 250 0.00% 33.33% 66.67% 

Coal 0 to 10 100.00% 0.00% 0.00% 

Coal 10 to 100 37.93% 36.21% 25.86% 

Distillate Liquid 0 to 10 2.86% 16.19% 80.95% 

Distillate Liquid 10 to 100 72.73% 9.09% 18.18% 

Distillate Liquid 100 to 250 62.50% 6.25% 31.25% 

Residual Liquid 0 to 10 12.50% 0.00% 87.50% 

Residual Liquid 10 to 100 75.49% 2.94% 21.57% 

Residual Liquid 100 to 250 86.36% 9.09% 4.55% 

As, described in another memorandum, the model units in each scenario were grouped 

according to fuel category for each model boiler (coal, biomass, heavy liquid, or light liquid), the 

size of the boiler, small, (less than 10 mmBtu/hr), or large (greater than or equal to 10 

mmBtu/hr), and the two-digit SIC code reported for the facility in the area source boiler 

inventory.1

 The distribution of units in Scenarios A, B, and C was multiplied by the number of 

boilers in each group to estimate the number of units in each scenario for each SIC group. 
7

The survey questionnaire did not ask facilities to report information on availability of 

natural gas pipelines, or distances to nearby pipeline distribution systems. Instead, to 

approximate the number of units assigned to each of the four cases in Scenario C, the 

percentages used in the 2002 fuel switching analysis for the vacated rule were used to 

approximate the pipeline distances and rural vs. urban settings for each of the facilities in 

Scenario C.3 Using these distributions, the number of units in C4 was expected to be negligible, 

so the Scenario C units were distributed via the following percentages: C1=5%, C2=85%, and 

C3=10%. 

3.2 Development of Cost Inputs and Factors 

The same base costs and cost sources that were used for the major source analysis were 

also used in this analysis, and are described in another memorandum.4 The equations used to 

calculate capital and annual costs are provided in Appendix A-1. Inputs to the cost equations are 

summarized in Appendix A-2. 

3.2.1 Capital Costs 

Capital costs were calculated using the same methods as the major source fuel switching 

analysis, and are described in another memorandum.4 Appendix A-1 presents the equations used 

to calculate total capital costs. Appendix A-3 presents the cost components used to calculate 

capital costs. Appendix A-4 presents the costs calculated for each scenario described in Section 

3.1 above. 

3.2.2 Total Annual Costs 

Total annual cost components considered in this analysis include: 

- Annualized capital recovery 

- Difference in fuel costs between natural gas and current fuel blend 

- Efficiency loss due to fuel switching 

- Cost to landfill biomass diverted from fuel usage 

Annual costs were calculated using the same methods as the major source fuel switching 

analysis, with one exception, and the methods used in the major source analysis are described in 

another memorandum.4 For area source boilers, if a unit switches to natural gas, there are no 
8

additional compliance costs the gas boiler since area source boilers firing natural gas are not 

covered under the NESHAP for Industrial, Commercial and Institutional Boilers at Area Sources 

of HAP. Therefore, the compliance costs to conduct a tune-up at natural gas boilers are not 

considered in this fuel switching analysis. 

To estimate the difference in fuel costs at area source boilers, each two-digit SIC code 

group was classified as either commercial or industrial, and the appropriate industrial and 

commercial fuel prices were assigned to each group, as discussed in Section 3.2.2 of the major 

source fuel switching analysis.4

 Fuel prices are not expected to differ between area and major 

sources of HAP. Appendix A-1 presents the equations used to calculate total annual costs. 

Inputs for annual costs are summarized in Appendix A-2. 

3.3 Calculation of Cost Impacts 

Capital and annual costs of fuel switching all of the boilers assigned to each applicable 

group of common SIC codes are presented in Appendix A-4. Information on the amount of 

natural-gas co-fired with other fuels was not reported in the boiler inspector survey, and for this 

analysis, it was assumed that models co-firing any amount of fuel with natural gas would 

completely switch to natural gas. This provides a conservative cost estimate of the costs to 

switch to natural gas. Appendix A-5 compares the costs of fuel switching to the costs of add-on 

control technologies for each subcategory. 

4.0 DESCRIPTION OF EMISSION REDUCTION ANALYSES 

Similar methods used to estimate the emission reductions from fuel switching are major 

source boilers and process heaters were used to estimate the emission reductions from fuel 

switching at area source boilers, although the source of emission factors differed slightly for area 

sources.

4

 Appendix A-6 presents the emission reductions for selected compounds from fuel 

switching for each subcategory. Emission reductions were estimated for Hg, filterable PM, HCl, 

HF, SO2, CO, THC, VOC, total mass dioxins/furans, formaldehyde, and non-mercury metallic 

HAP. Emission reductions from fuel switching were calculated by subtracting the emission rates 

and concentrations estimated from burning natural gas from the baseline emission rates and 
9

concentrations estimated from burning the existing fuel assigned to each model boiler. In 

general emissions of Hg, filterable PM, HCl, HF, SO2, THC, VOC, and non-mercury metallic 

HAP decreased when switching to NG. Liquid fuels experienced an increase in CO emissions as 

a result of fuel switching, however overall emissions of CO were reduced across all fuel types. 

Fuel switching is estimated to cause a small increase in total dioxin/furan emissions for distillate 

liquid and coal, but the overall dioxin/furan emissions were reduced by switching to natural gas. 

Emissions of formaldehyde increased slightly for each fuel category except for distillate liquid. 

Emission reductions were calculated for each model boiler, not according to SIC s group. 

Baseline emission factors from the current fuels used at each model were estimated for the 

baseline emissions analysis at area source boilers and are discussed in another memorandum.5

 

For this analysis, the average baseline emission factors developed for uncontrolled boilers firing 

natural gas were used as the basis for estimating emission reductions for natural gas. Reductions 

were calculated on a ton per year basis by subtracting the baseline emission factor for natural gas 

from the baseline emission factors assigned to each model boiler. 

To calculate the annual emission reductions resulting from fuel switching to natural gas, 

the emission factors, which were available on a lb/mmBtu basis, were converted to tons per year 

using Equation 5 in Appendix A-1. To make this conversion, the annual hours of operation and 

boiler design capacity reported in the survey were used for each unit in the inventory. Similarly, 

when baseline emissions were calculated as concentrations, either on a ppm @ 3% O2 or 

ng/dscm @7% O2 basis, the concentrations were converted to tons per year using Equations 6 & 

7 in Appendix A-1. The exhaust flowrate and oxygen content of the exhaust at each unit in the 

inventory is needed in order to convert emission concentrations into an annual emission rate. 

The oxygen contents were approximated using other data sources for typical boiler exhausts, and 

the flowrate was estimated using the reported design capacity for each unit, according to the 

procedures outlined in another memorandum.6,7

Appendix A-7 compares the fuel switching emission reductions to reductions achieved 

using add-on control technologies under the proposed regulatory option.
10

5.0 REFERENCES 

1. Singleton, A., ERG. Developing Model Units for Boiler Area Sources. April 2010. 

2. Survey Database containing Results of the 2008 Questionnaire for Boilers, Process 

Heaters, & Other Combustion Units (ICR No. 2286.01). 

3. Leatherwood, C. ERG. Memorandum to Jim Eddinger, U.S. EPA, OAQPS. Development 

 of Fuel Switching Costs and Emission Reductions for Industrial/Commercial/Institutional 

 Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants. 

 October 2002. 

4. Gibson, G., ERG. Development of Fuel Switching Costs and Emission Reductions for 

Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission 

Standards for Hazardous Air Pollutants – Major Source. April 2010. 

5. Gibson, G. and A. Singleton, ERG. Development of Baseline Emission Factors for 

Boilers and Process Heaters at Commercial, Industrial and Institutional Facilities. April 

2010. 

6. McClutchey, S. and A. Singleton, ERG. Methodology for Estimating Control Costs for 

Industrial, Commercial, Institutional Boilers National Emission Standards for Hazardous 

Air Pollutants – Area Source. April 2010. 

7. McClutchey, S. and A. Singleton, ERG. Methodology for Estimating Control Costs for 

Industrial, Commercial, Institutional Boilers and Process Heaters National Emission 

Standards for Hazardous Air Pollutants – Major Source. April 2010. 
Appendix A-1: Equations Used in Fuel Switching Analysis

Equation 1 - Total Capital Cost (2008$)

Total Capital Investment (2008$) = TCI A + TCIB + TCIC

Where:

Total Capital Investment of Scenario A (TCI A) = 293 * CFfs,a * DC * f

 293 = conversion factor, kWh per mmBtu

 CFfs,a = cost factor for fuel switching for scenario A, $/kW (see Appendix A-3)

 DC = design capacity (mmBtu/hr)

 f = capacity factor, 0.65 for solid fuel units and 0.5 for liquid fuel units

Total Capital Investment of Scenario B (TCI B) = 293 * CFfs,b * DC * f

 293 = conversion factor, kWh per mmBtu

 CFfs,b = cost factor for fuel switching for scenario B, $/kW (see Appendix A-3)

 DC = design capacity (mmBtu/hr)

 f = capacity factor, 0.65 for solid fuel units and 0.5 for liquid fuel units

Total Capital Investment of Scenario C (TCI C) = Σ TCICi

 TCICi = TCIB + ( Li * CFpipe,i )

 i = denotation for either scenario C1, C2, or C3

 Li = length of pipe needed to connect facility to pipeline (ft)

 CFpipe,i = cost per foot of pipe (2008$/ft)

Equation 2 - Total Annual Cost (2008$)

Total Annual Cost (2008$) = delF + EL + CR + TACLF

Where:

Difference in Fuel Cost (delF) is defined in Equation 3

Efficiency Loss (EL) = ELF * f * DC * CFNG * Ophours

 ELF = efficiency loss factor, 0.05

 Ophours = annual operating hours reported in 2008 survey (hours/year)

Capital Recovery (CR) = TCI * CRF

 CRF = capital recovery factor, 0.09439

Fuel Cost/Savings to Landfill Biomass Diverted from Fuel Usage (TAC LF) is defined in Equation 4

Equation 3 - Annualized Fuel Cost/Savings (2008$)

TAC (2008$) = delF = (CFNG - CFo) * DC * f * Ophours

Where:

CFNG = cost of natural gas ($/mmBtu)

CFo = cost of original fuel ($/mmBtu)

DC = design capacity (mmBtu/hr)

f = capacity factor, 0.65 for solid fuel units and 0.5 for liquid fuel units

Ophours = annual operating hours averaged per NAICS group

Equation 4 - Total Annual Cost to Landfill Biomass Diverted from Fuel Usage (2008$)

TACLF = f * DC * χ * 1000000 * (1 / HHV) * 0.0005 * Ophours * CFtipping

Where:

DC = design capacity (mmBtu/hr)

f = capacity factor, 0.65 for solid fuel units and 0.5 for liquid fuel units

χ = 0.882, the average heat input contribution of biomass for units in the biomass category. This is the portion of the heat input assumed to be 

diverted to a landfill.

1000000 = conversion factor, Btu per mmBtu

HHV = heat content of biomass (Btu/lb)

0.0005 = conversion factor, tons per lb

Ophours = annual operating hours reported in 2008 survey (hours/year)

CFtipping = cost to send one ton of biomass to a landfill, $42.14/ton
Appendix A-1: Equations Used in Fuel Switching Analysis

Equation 5 - Conversion of lb/MMBtu Emission Factors to Ton Per Year Basis

Annual Emission Rate (tpy) = ERHI * 0.0005 * Ophours

Where:

ERHI = emission rate (lb/mmBtu)

0.0005 = conversion factor, tons per lb

Ophours = annual operating hours reported in 2008 survey (hours/year)

Equation 6 - Conversion of ppm @ 3% O2 Emission Factors to Ton Per Year Basis

Annual Emission Rate (tpy) = ERC * 0.000001 * ρair * QS * 60 * Ophours * 0.0005 * (20.946 – O2) / (20.946 – Std O2)

Where:

ERC = emission concentration (ppm @ 3% O2)

0.000001 = conversion factor, ppm to parts

ρair = density of air, 0.0749 lb/dscf

QS = exhaust flowrate (dscfm), see calculations in Control Cost Memorandum.

60 = conversion factor, minutes per hour

Ophours = annual operating hours reported in 2008 survey (hours/year)

0.0005 = conversion factor, tons per lb

20.946 = percentage of oxygen in ambient air

O2 = percentage of oxygen assumed in exhaust gas, see calculations in Control Cost Memorandum.

Std. O2 = 3 percent oxygen in standardized emission concentration for proposed rule

Equation 7 - Conversion of ng/dscm @ 7% O2 Emission Factors to Ton Per Year Basis

Annual Emission Rate (tpy) = ERC * 0.0283 * QS * 60 * Ophours * 0.000000001 * 0.0022 * 0.0005 * (20.946 – O 2) / (20.946 – Std O2)

Where:

ERC = emission concentration (ng/dscm @ 7% O 2)

0.0283 = conversion factor, dry standard cubic meter per dry std. cubic foot

QS = exhaust flowrate (dscfm), see calculations in Control Cost Memorandum.

60 = conversion factor, minutes per hour

Ophours = annual operating hours reported in 2008 survey (hours/year)

0.000000001 = conversion factor, g per ng

0.0022 = conversion factor, lb per g

0.0005 = conversion factor, tons per lb

20.946 = percentage of oxygen in ambient air

O2 = percentage of oxygen assumed in exhaust gas, see calculations in Control Cost Memorandum.

Std O2 = 7 percent oxygen in standardized emission concentration for proposed rule
Appendix A-2: Cost and Emission Reduction Equation Inputs and Constants

Parameter Description Value Unit

CFfs,a Cost factor for fuel switching for scenario A (see App A-3) $13.01 2008$/

CFfs,b Cost factor for fuel switching for scenario B (see App A-3) $18.81 2008$/

f Capacity factor (fraction of unit design capacity) 0.65 (solid fuel) 0.5 (liquid fuel) -

LC1 Length of pipe needed for scenario C1 500 ft

LC2 Length of pipe needed for scenario C2 5,280 ft

LC3 Length of pipe needed for scenario C3 52,800 ft

CFpipe,C1 Cost per foot of pipe for scenario C1 $186 2008$

CFpipe,C2 Cost per foot of pipe for scenario C2 $37 2008$

CFpipe,C3 Cost per foot of pipe for scenario C3 $22 2008$

ELF Efficiency loss factor 0.05 -

CRF Capital recovery factor (lifetime of fuel switching equipment is 20 years, at i = 7%) 0.09439 -

χ

The average heat input contribution of biomass for units in the biomass category. This is the portion of the heat input assumed to be diverted to a landfill.

0.882 -

HHV Higher heating value of biomass 8,600 Btu/lb

CFtipping Tipping fee to dispose of biomass in a landfill $42.14 2008$/

ρair Density of air 0.0749 lb/dsc
Appendix A-3: Capital Cost Components for Area Source Boilers to Switch to Natural Gas

Scenario A

System

Capital Cost Components

Gas 

system

Boiler 

system Boiler 1 Boiler 2 Boiler 3 Boiler 4

Average 

Cost

Average Cost 

(in 2008 Dollars)

Electrical boiler x 1.5 2 0.28

Superheater upgrading x 2.31

Gas ignition control system x 3.5

Boiler controls x

Boiler modifications x 3.2 2.1 4.04

Burner managment system x

Valves, instruments, controls x 3 0.4

Ignitor modifications x 0.57

Fans, ducts, temp. probes x 0.1

Mechanical fabrication pkg x 0.72 0.24

Purging x 0.01

Subtotal 9.7 5.21 4.5 4.56 5.99 10.79

Administrative

Design

Engineering 0.5

Project Management 0.5 0.95 0.5

Test, start-up, calibration 0.21 0.1

Training

Transportation 0.01

Vendor representative 0.1 0.88 0.5

Building and excavation 0.5

Subtotal 0.6 2.05 1.6 0.7 1.24 2.23

Total 7.23 13.01

Scenario B

System

Capital Cost Components

Gas 

system

Boiler 

system Boiler 1 Boiler 2 Boiler 3 Boiler 4

Average 

Cost

Average Cost 

(in 2008 Dollars)

Electrical gas meter house x 0.6

Regulator house extension x 0.13

Mechanical erection pkg x 2.9

Platforms and supports x 0.17

Gas house extension x 0.5

Conduit and Cable x 2 0.16

U.G. Piping and tap x 0.3

Grating and pipe supports x 0.3

Meters, regulators, and scrubber x 2.6

Purging x 0.01

Subtotal 2.8 3.37 3.5 3.22 5.80

Electrical boiler x 1.5 2 0.28

Fans, ducts, temp. probes x 0.1

Mechanical fabrication pkg x 0.72 0.24

Superheater upgrading x 2.31

Gas ignition control system x 3.5

Boiler controls x

Boiler modifications x 3.2 2.1 4.04

Burner managment system x

Fans x

Valves, instruments, controls x 3 0.4

Ignitor modifications x 0.57

Subtotal 9.7 5.2 4.5 4.56 5.99 10.78

Administrative

Design

Engineering 0.5

Overhead 0.2

Project Management 0.5 0.95 0.5

Test, start-up, calibration 0.21 0.1

Training

Transportation 0.01

Vendor representative 0.1 0.88 0.5

Building and excavation 0.5

Subtotal 0.6 2.05 1.6 0.7 1.24 2.23

Total 10.45 18.81

Cost Breakdowns ($/kw) for Each Site

Cost Breakdowns ($/kw) for Each Site
Appendix A-4: Summary of Total Capital Investment and Total Annual Costs

Table 1 - Total Capital Investment, 2008$

A B C1 C2 C3 C Total Total

01 $0 $0 $0 $0 $0 $0 $0

02 $5,966,925 $1,325,292 $3,186,223 $360,946,570 $433,656,883 $797,789,676 $805,081,89307 $0 $0 $0 $0 $0 $0 $009 $0 $0 $0 $0 $0 $0 $014 $7,303 $86,900 $626,391 $113,082,657 $137,646,952 $251,355,999 $251,450,20316 $0 $0 $0 $0 $0 $0 $017 $4,133,268 $976,539 $2,837,471 $351,754,671 $423,482,413 $778,074,555 $783,184,36220 $72,764,982 $22,025,731 $58,944,431 $6,907,888,893 $8,128,243,066 $15,095,076,389 $15,189,867,10223 $7,303 $86,900 $626,391 $113,082,657 $137,646,952 $251,355,999 $251,450,20324 $9,286,668 $31,999,911 $64,826,563 $5,952,977,567 $7,018,085,396 $13,035,889,525 $13,077,176,10426 $0 $0 $0 $0 $0 $0 $040 $46,111 $382,696 $2,894,954 $447,452,864 $521,145,749 $971,493,568 $971,922,37541 $0 $0 $0 $0 $0 $0 $042 $7,303 $86,900 $626,391 $113,082,657 $137,646,952 $251,355,999 $251,450,20343 $0 $0 $0 $0 $0 $0 $044 $0 $0 $0 $0 $0 $0 $045 $2,212,549 $348,752 $441,799 $9,191,899 $10,174,470 $19,808,168 $22,369,46947 $0 $0 $0 $0 $0 $0 $048 $99,525 $859,799 $6,442,593 $1,002,100,461 $1,170,120,239 $2,178,663,293 $2,179,622,61650 $2,917,751 $2,893,169 $4,377,869 $338,932,724 $415,104,046 $758,414,640 $764,225,56051 $11,212,234 $4,054,219 $6,190,245 $490,427,259 $593,128,020 $1,089,745,525 $1,105,011,97852 $0 $0 $0 $0 $0 $0 $053 $6,001,723 $1,620,222 $5,528,178 $695,315,912 $817,154,815 $1,517,998,905 $1,525,620,85154 $0 $0 $0 $0 $0 $0 $055 $446,869 $667,664 $6,901,784 $1,107,043,509 $1,307,488,156 $2,421,433,448 $2,422,547,98157 $0 $0 $0 $0 $0 $0 $058 $131,723 $1,050,202 $7,749,555 $1,225,334,663 $1,445,430,745 $2,678,514,963 $2,679,696,88959 $0 $0 $2,698,351 $480,477,609 $569,891,643 $1,053,067,603 $1,053,067,60360 $46,111 $382,696 $2,894,954 $447,452,864 $521,145,749 $971,493,568 $971,922,37564 $2,212,549 $348,752 $441,799 $9,191,899 $10,174,470 $19,808,168 $22,369,46965 $5,765,607 $8,040,598 $29,906,542 $3,939,310,362 $4,645,779,485 $8,614,996,389 $8,628,802,59470 $6,575,751 $6,355,572 $43,853,341 $6,738,937,533 $7,935,709,984 $14,718,500,858 $14,731,432,18172 $10,658,070 $4,137,321 $20,327,424 $2,937,114,138 $3,472,615,768 $6,430,057,331 $6,444,852,72173 $27,495 $191,269 $1,493,921 $222,252,496 $275,311,373 $499,057,789 $499,276,55375 $1,014,496 $1,222,999 $13,877,333 $2,232,643,553 $2,614,863,982 $4,861,384,868 $4,863,622,36376 $0 $0 $0 $0 $0 $0 $079 $165,827 $1,327,368 $10,073,746 $1,558,703,668 $1,838,736,631 $3,407,514,045 $3,409,007,24180 $143,882,362 $46,450,260 $164,991,592 $21,322,077,406 $25,082,379,678 $46,569,448,676 $46,759,781,29781 $0 $0 $0 $0 $0 $0 $082 $65,601,522 $50,526,031 $299,040,726 $44,728,065,695 $52,608,291,516 $97,635,397,937 $97,751,525,48983 $0 $0 $0 $0 $0 $0 $084 $27,495 $191,269 $1,493,921 $222,252,496 $275,311,373 $499,057,789 $499,276,55386 $2,635,434 $3,855,623 $29,536,477 $4,605,239,354 $5,417,826,231 $10,052,602,063 $10,059,093,12187 $238,546 $667,664 $5,692,179 $912,494,293 $1,091,322,360 $2,009,508,831 $2,010,415,041

91 to 98 $39,991,164 $21,220,014 $60,371,832 $7,297,164,180 $8,578,003,889 $15,935,539,900 $15,996,751,078

Unknown $12,320,739 $2,690,428 $7,342,756 $831,981,025 $985,262,226 $1,824,586,007 $1,839,597,174

Total $406,405,405 $216,072,762 $866,237,732 $117,713,973,533 $138,618,781,211 $257,198,992,476 $257,821,470,643

SIC

TCI
Appendix A-4: Summary of Total Capital Investment and Total Annual Costs

Table 2 - Total Annual Costs, 2008$

A B C1 C2 C3 C Total

Biomass Diverted from 

Fuel Usage Efficiency Loss Total

01 $0 $0 $0 $0 $0 $0 $0 $0 $002 ($144,757,462) ($22,204,237) ($1,997,452) ($23,673,472) $34,997,997 $9,327,074 $0 $12,848,645 ($144,785,980)07 $0 $0 $0 $0 $0 $0 $0 $0 $009 $0 $0 $0 $0 $0 $0 $0 $0 $014 ($177,175) ($1,455,941) ($247,872) $3,770,280 $12,061,946 $15,584,354 $0 $547,961 $14,499,19916 $0 $0 $0 $0 $0 $0 $0 $0 $017 ($100,272,986) ($16,361,161) ($2,030,370) ($13,964,305) $35,212,828 $19,218,152 $0 $9,422,940 ($87,993,055)20 ($1,069,448,992) ($133,183,994) ($7,025,195) $424,590,758 $742,236,940 $1,159,802,504 $137,588,836 $192,260,556 $287,018,91123 ($177,175) ($1,455,941) ($247,872) $3,770,280 $12,061,946 $15,584,354 $0 $547,961 $14,499,19924 $199,346,482 $473,860,559 $155,609,453 $3,113,141,822 $962,291,570 $4,231,042,846 $853,773,019 $184,554,901 $5,942,577,80726 $0 $0 $0 $0 $0 $0 $0 $0 $040 ($1,118,648) ($6,411,780) ($1,205,474) $15,052,199 $45,968,328 $59,815,053 $0 $2,167,205 $54,451,83041 $0 $0 $0 $0 $0 $0 $0 $0 $042 ($177,175) ($1,455,941) ($247,872) $3,770,280 $12,061,946 $15,584,354 $0 $547,961 $14,499,19943 $0 $0 $0 $0 $0 $0 $0 $0 $044 $0 $0 $0 $0 $0 $0 $0 $0 $045 ($53,676,392) ($5,843,075) ($1,133,497) ($9,709,166) ($214,831) ($11,057,494) $0 $3,868,591 ($66,708,371)47 $0 $0 $0 $0 $0 $0 $0 $0 $048 ($2,414,471) ($14,405,261) ($2,924,163) $33,702,030 $103,385,753 $134,163,620 $0 $4,877,950 $122,221,83750 ($36,123,829) $34,786,486 $6,686,995 $164,329,539 $54,369,471 $225,386,005 $45,411,938 $17,210,127 $286,670,72751 ($187,026,177) $16,764,589 $5,390,429 $134,482,288 $66,830,925 $206,703,642 $45,411,938 $32,930,853 $114,784,84452 $0 $0 $0 $0 $0 $0 $0 $0 $053 ($145,601,664) ($27,145,572) ($3,062,673) ($12,690,941) $68,904,298 $53,150,683 $0 $14,484,350 ($105,112,202)54 $0 $0 $0 $0 $0 $0 $0 $0 $055 ($3,121,874) ($11,186,192) ($2,656,533) $50,334,509 $117,031,048 $164,709,025 $0 $7,676,528 $158,077,48756 $0 $0 $0 $0 $0 $0 $0 $0 $057 $0 $0 $0 $0 $0 $0 $0 $0 $058 ($3,195,601) ($17,595,323) ($3,614,140) $40,849,453 $127,579,689 $164,815,003 $0 $5,965,695 $149,989,77459 $0 $0 $6,720,560 $153,258,350 $66,723,798 $226,702,708 $23,563,148 $6,357,219 $256,623,07660 ($1,118,648) ($6,411,780) ($1,205,474) $15,052,199 $45,968,328 $59,815,053 $0 $2,167,205 $54,451,83064 ($53,676,392) ($5,843,075) ($1,133,497) ($9,709,166) ($214,831) ($11,057,494) $0 $3,868,591 ($66,708,371)65 $3,369,342 $3,223,570 ($9,699,735) $162,121,734 $414,282,473 $566,704,472 $0 $33,998,277 $607,295,66070 ($159,527,556) ($106,482,687) ($12,934,337) $326,751,254 $713,729,160 $1,027,546,077 $23,563,148 $47,951,797 $833,050,77972 ($258,564,520) ($69,317,602) ($10,716,208) $43,600,521 $300,969,888 $333,854,201 $0 $33,129,666 $39,101,74573 ($667,027) ($3,204,566) ($789,539) $7,157,384 $24,194,018 $30,561,863 $0 $1,089,623 $27,779,89375 ($6,046,267) ($20,490,402) ($4,930,470) $107,333,096 $234,722,075 $337,124,701 $0 $16,337,299 $326,925,33076 $0 $0 $0 $0 $0 $0 $0 $0 $079 ($4,022,971) ($22,239,027) ($4,681,038) $52,019,972 $162,309,138 $209,648,073 $0 $7,585,868 $190,971,94280 ($3,347,339,835) ($640,300,556) ($102,977,436) $16,966,843 $2,130,255,969 $2,044,245,375 $0 $370,877,073 ($1,572,517,942)81 $0 $0 $0 $0 $0 $0 $0 $0 $082 ($1,145,185,416) ($708,586,944) ($134,042,793) $1,412,808,542 $4,633,061,703 $5,911,827,452 $23,563,148 $337,539,913 $4,419,158,15383 $0 $0 $0 $0 $0 $0 $0 $0 $084 ($667,027) ($3,204,566) ($789,539) $7,157,384 $24,194,018 $30,561,863 $0 $1,089,623 $27,779,89386 ($63,935,578) ($64,597,983) ($6,600,256) $281,116,880 $493,718,931 $768,235,556 $23,563,148 $30,290,882 $693,556,02687 ($2,519,307) ($11,186,192) ($2,522,450) $35,790,746 $97,050,069 $130,318,366 $0 $5,356,377 $121,969,244

91 to 98 ($760,286,591) ($48,402,538) ($7,849,025) $441,271,172 $780,137,427 $1,213,559,575 $92,435,722 $134,539,847 $631,846,015

Unknown ($298,900,846) ($45,076,029) ($5,748,137) ($42,903,234) $80,315,810 $31,664,439 $0 $26,702,721 ($285,609,715)

Total ($7,647,031,775) ($1,485,413,162) ($158,605,609) $6,937,549,234 $12,596,197,825 $19,375,141,450 $1,268,874,046 $1,548,794,207 $13,060,364,766

SIC

TAC
TCI TAC TCI

TAC Considering Fuel 

Savings

01 - $ - $ - $ - $ 

02 805,081,893.05 $ (144,785,979.95) $ 5,603,665.00 $ 2,551,540.00 $ 

07 - $ - $ - $ - $ 

09 - $ - $ - $ - $ 

14 251,450,202.54 $ 14,499,199.06 $ 1,065,060.00 $ 366,540.00 $ 

16 - $ - $ - $ - $ 

17 783,184,362.44 $ (87,993,054.95) $ 4,800,835.00 $ 2,067,568.00 $ 

20 15,189,867,102.10 $ 287,018,910.57 $ 103,985,544.00 $ 43,504,037.00 $ 

23 251,450,202.54 $ 14,499,199.06 $ 1,065,060.00 $ 366,540.00 $ 

24 13,077,176,104.20 $ 5,942,577,807.32 $ 68,505,280.00 $ 32,453,710.00 $ 

26 - $ - $ - $ - $ 

40 971,922,374.73 $ 54,451,829.85 $ 4,260,234.00 $ 1,466,163.00 $ 

41 - $ - $ - $ - $ 

42 251,450,202.54 $ 14,499,199.06 $ 1,065,060.00 $ 366,540.00 $ 

43 - $ - $ - $ - $ 

44 - $ - $ - $ - $ 

45 22,369,469.39 $ (66,708,370.62) $ 802,830.00 $ 483,972.00 $ 

47 - $ - $ - $ - $ 

48 2,179,622,616.29 $ 122,221,837.29 $ 9,585,526.00 $ 3,298,867.00 $ 

50 764,225,560.16 $ 286,670,726.68 $ 5,350,553.00 $ 2,683,187.00 $ 

51 1,105,011,978.37 $ 114,784,844.03 $ 10,085,884.00 $ 5,221,580.00 $ 

52 - $ - $ - $ - $ 

53 1,525,620,851.19 $ (105,112,202.20) $ 8,798,839.00 $ 3,651,163.00 $ 

54 - $ - $ - $ - $ 

55 2,422,547,980.94 $ 158,077,487.22 $ 10,357,302.00 $ 3,564,475.00 $ 

56 - $ - $ - $ - $ 

58 2,679,696,888.79 $ 149,989,773.85 $ 11,715,643.00 $ 4,031,948.00 $ 

59 1,053,067,602.85 $ 256,623,075.99 $ 3,732,637.00 $ 1,284,589.00 $ 

60 971,922,374.73 $ 54,451,829.85 $ 4,260,234.00 $ 1,466,163.00 $ 

64 22,369,469.39 $ (66,708,370.62) $ 802,830.00 $ 483,972.00 $ 

65 8,628,802,594.03 $ 607,295,660.42 $ 164,967,217.00 $ 51,634,752.00 $ 

70 14,731,432,180.54 $ 833,050,779.01 $ 65,784,397.00 $ 23,262,787.00 $ 

72 6,444,852,721.31 $ 39,101,745.02 $ 31,705,665.00 $ 11,949,922.00 $ 

73 499,276,553.30 $ 27,779,892.83 $ 2,130,116.00 $ 733,082.00 $ 

75 4,863,622,362.60 $ 326,925,330.39 $ 20,810,303.00 $ 7,161,881.00 $ 

76 - $ - $ - $ - $ 

79 3,409,007,241.22 $ 190,971,942.07 $ 14,910,818.00 $ 5,131,569.00 $ 

80 46,759,781,297.34 $ (1,572,517,941.87) $ 379,580,608.00 $ 139,408,571.00 $ 

81 - $ - $ - $ - $ 

82 97,751,525,489.22 $ 4,419,158,153.46 $ 578,352,776.00 $ 198,885,995.00 $ 

83 - $ - $ - $ - $ 

84 499,276,553.30 $ 27,779,892.83 $ 2,130,116.00 $ 733,082.00 $ 

86 10,059,093,120.94 $ 693,556,025.92 $ 43,942,628.00 $ 15,330,564.00 $ 

87 2,010,415,040.88 $ 121,969,244.35 $ 8,616,166.00 $ 2,965,261.00 $ 

91 to 98 15,996,751,078.25 $ 631,846,014.95 $ 211,404,277.00 $ 72,207,180.00 $ 

Unknown 1,839,597,174.09 $ (285,609,715.05) $ 12,272,385.00 $ 5,469,622.00 $ 

Total $257,821,470,643 $13,060,364,766 $1,792,450,488 $644,186,822

SIC

Fuel Switching Costs Add-on Control Costs for Regulatory Option 3e

Appendix A-5: Comparison of Costs between Fuel Switching and Proposed 

Regulatory Option 3E
Appendix A-6 - Summary of Emission Reductions from Fuel Switching

Fuel Subcategory Pollutant

Emission Reductions 

from Fuel Switching (tpy)

Biomass Mercury (Hg) 0 

Filterable PM (PM) 74,072 

Hydrogen Chloride (HCl) 1,972 

Hydrogen Fluoride (HF) 38 

Sulfur Dioxide (SO2) 25 

Carbon Monoxide (CO) 140 

Total Hydrocarbons (THC) 2 

Volatile Organic Compounds (VOC) 1

Total Mass Dioxins/Furans 0

Arsenic (As) 3

Beryllium (Be) 5

Cadmium (Cd) 2

Cobalt (Co) 0

Chromium (Cr) (1) 

Nickel (Ni) 0 

Manganese (Mn) 897 

Lead (Pb) 23 

Antimony (Sb) 1 

Selenium (Se) 5

Total Selected Metals (TSM) 936 

Formaldehyde (0) 

Coal Mercury (Hg) 2 

Filterable PM (PM) 14,951 

Hydrogen Chloride (HCl) 6,752 

Hydrogen Fluoride (HF) 179 

Sulfur Dioxide (SO2) 83 

Carbon Monoxide (CO) 16 

Volatile Organic Compounds (VOC) 0 

Total Mass Dioxins/Furans 0

Arsenic (As) 15 

Beryllium (Be) 1 

Cadmium (Cd) 0

Cobalt (Co) 1

Chromium (Cr) 2

Nickel (Ni) 5

Manganese (Mn) 22 

Lead (Pb) 11 

Antimony (Sb) 2 

Selenium (Se) 7

Total Selected Metals (TSM) 65 

Formaldehyde (0) 

Distillate Liquid Mercury (Hg) 2 

Filterable PM (PM) 14,664 

Hydrogen Chloride (HCl) 2,323 

Hydrogen Fluoride (HF) 194 

Sulfur Dioxide (SO2) 28 

Carbon Monoxide (CO) (3) 

Total Hydrocarbons (THC) 1 

Volatile Organic Compounds (VOC) 0

Total Mass Dioxins/Furans 0 

Arsenic (As) 169 

Beryllium (Be) 57 

Cadmium (Cd) 25 

Cobalt (Co) 20 

Chromium (Cr) 240 

Nickel (Ni) 205 

Manganese (Mn) 15,913 

Lead (Pb) 319 

Antimony (Sb) 136 

Selenium (Se) 207 

Total Selected Metals (TSM) 17,290 

Formaldehyde 0 
Appendix A-6 - Summary of Emission Reductions from Fuel Switching

Fuel Subcategory Pollutant

Emission Reductions 

from Fuel Switching (tpy)

Residual Liquid Mercury (Hg) 0 

Filterable PM (PM) 1,291 

Hydrogen Chloride (HCl) 119 

Hydrogen Fluoride (HF) 2 

Sulfur Dioxide (SO2) 48 

Carbon Monoxide (CO) (5) 

Total Hydrocarbons (THC) 0 

Volatile Organic Compounds (VOC) 0

Total Mass Dioxins/Furans 0

Arsenic (As) 1

Beryllium (Be) 0

Cadmium (Cd) 0

Cobalt (Co) 2

Chromium (Cr) 1

Nickel (Ni) 44 

Manganese (Mn) 107 

Lead (Pb) 2 

Antimony (Sb) 2

Selenium (Se) 1

Total Selected Metals (TSM) 160 

Formaldehyde (0) 

TOTAL Mercury (Hg) 4 

Filterable PM (PM) 104,978 

Hydrogen Chloride (HCl) 11,166 

Hydrogen Fluoride (HF) 413 

Sulfur Dioxide (SO2) 185 

Carbon Monoxide (CO) 148 

Total Hydrocarbons (THC) 3 

Volatile Organic Compounds (VOC) 2

Total Mass Dioxins/Furans 0

Arsenic (As) 188 

Beryllium (Be) 62 

Cadmium (Cd) 28 

Cobalt (Co) 23 

Chromium (Cr) 241 

Nickel (Ni) 255 

Manganese (Mn) 16,939 

Lead (Pb) 354 

Antimony (Sb) 140 

Selenium (Se) 220 

Total Selected Metals (TSM) 18,451 

Formaldehyde (0) 
Fuel Subcategory Pollutant

Emission Reductions 

from Fuel Switching (tpy)

Emission Reductions 

from Proposed Option 

(tpy)

Biomass Mercury (Hg) 0 0 

Filterable PM (PM) 74,072 762 

Hydrogen Chloride (HCl) 1,972 21 

Total Hydrocarbons (THC) 2 428 

Volatile Organic Compounds (VOC) 1 246 

Carbon Monoxide (CO) 140 23,187 

Total Mass Dioxins/Furans 0 0 

Hydrogen Fluoride (HF) 38 1 

Sulfur Dioxide (SO2) 25 174 

Total Selected Metals (TSM) 936 10 

Coal Mercury (Hg) 2 1 

Filterable PM (PM) 14,951 5,353 

Hydrogen Chloride (HCl) 6,752 68 

Total Hydrocarbons (THC) 0 2 

Volatile Organic Compounds (VOC) 0 1 

Carbon Monoxide (CO) 16 102 

Total Mass Dioxins/Furans 0 0 

Hydrogen Fluoride (HF) 179 2 

Sulfur Dioxide (SO2) 83 530 

Total Selected Metals (TSM) 65 24 

Liquid Mercury (Hg) 2 0 

Filterable PM (PM) 15,955 232 

Hydrogen Chloride (HCl) 2,442 30 

Total Hydrocarbons (THC) 1 1,118 

Volatile Organic Compounds (VOC) 1 642 

Carbon Monoxide (CO) (8) 8,832 

Total Mass Dioxins/Furans 0 0 

Sulfur Dioxide (SO2) 77 685 

Total Selected Metals (TSM) 17,450 175 

TOTAL Mercury (Hg) 4 1 

Filterable PM (PM) 104,978 6,348 

Hydrogen Chloride (HCl) 11,166 119 

Total Hydrocarbons (THC) 3 1,548 

Volatile Organic Compounds (VOC) 2 889 

Carbon Monoxide (CO) 148 32,122 

Total Mass Dioxins/Furans 0 0 

Hydrogen Fluoride (HF) 413 5 

Sulfur Dioxide (SO2) 185 1,389 

Total Selected Metals (TSM) 18,451 209 

Appendix A-7: Comparison of Emission Reductions from Fuel Switching to Proposed 

Option 3E