# 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 Co sts and Emission Reductions for Industrial, Commercial, and Institutional Boilers fo r the National Emission Standards for Hazardous Air Pollutants – Area Source

1.0 INTRODUCTION

The purpose of this memorandum is to discu ss 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 natu ral 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 gr eater emission reductions than add-on technologies can achieve.
For this analysis, the cost, emission, and operatio nal 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 em ission 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 fr om their current fuel to natu ral gas. Fuel switching would require nearly $258 billion in capital and over $13 b illion in annual costs. Of these totals, boilers
firing distillate liquids incur 91 percent of the capital cost s while boilers firing biomass account
for the majority of annual costs. Additionally, EPA estimates that boilers located at educational
services (Standard Industrial Clas sification (SIC) code 82) will in cur the largest portion of all
capital costs, at 38 percent. Boilers at lu mber and wood products f acilities (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 comparativel y 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 diffe rence between natural gas and other fuels.

Tables 2.2 and 2.3 summarize the emission reductions fo r selected pollutants as a result
of fuel switching. These tables show the tota l amount of emission reductions that could be
achieved from fuel switching compared to unchanged operation of all units.3Table 2.2 – Summary of Emission Reductionsof Metallic HAP fromFuel Switching (tpy)1Non-Mercury Metallic HAPFuelAntimony(Sb)Arsenic(As)Beryllium(Be)Cadmium(Cd)Chromium(Cr)Cobalt(Co)Lead(Pb)Manganese(Mn)Nickel(Ni)Selenium(Se)Biomass 0.7 3.1 4.7 1.9 (1.2) 0.5 23.0 897.3 0.4 5.2Coal 2.0 15.0 0.5 0.3 1.7 0.6 11.0 22.3 4.7 7.0DistillateLiquid135.9 169.0 56.8 25.4 239.6 20.4 318.7 15912.6 205.1 207.0ResidualLiquid1.6 0.8 0.4 0.5 0.5 2.0 1.6 106.6 44.5 1.1Total 140 188 62 28 241 23 354 16,939 255 2201Values in parentheses represent an increase in emissions for a specific pollutant as a result of switching to natural gas4Table 2.3 – Summary of Emission Reductions ofAll Other HAP from Fuel Switching (tpy)1Inorganic HAPOther HAPOrganic HAPFuelHydrogenChloride(HCl)HydrogenFluoride(HF)SulfurDioxide(SO2)Mercury(Hg)FilterableParticulateMatter(PM)CarbonMonoxide(CO)TotalHydrocarbons,as Propane(THC)VolatileOrganicCompounds(VOC)Total MassDioxins/Furans2FormaldehydeBiomass 1,972 38 25 0.2 74,072 140 2.2 1.2 0.00083 (0.02)Coal 6,752 179 83 1.9 14,951 16 0.2 0.1 0.00007 (0.02)DistillateLiquid2,323 194 28 2.0 14,664 (3.5) 0.5 0.3 0.00013 0.08ResidualLiquid119 2 48 0.0 1,291 (5) 0.4 0.2 0.00130 (0.06)Total 11,166 413 185 4 104,978 148 3 2 0.00233 (0.02)1Values in parentheses represent an increase in emissions fora specific pollutant as a result of switching to natural gas.2Total 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 memorandum 1



# . As was done in the major source analysis, al l area source boilers were assumed to be
characterized by one of the following three scenarios:

A. For units that use natural gas as a star t-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 sy stem, 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 natura l 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 fr om 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 cont ain information on start-up or back-up fuels, or
whether or not natural gas was used at othe r combustion units at the same facility, the
distributions assigned to Scenar ios A and B were based on the fu el distribution reported for 597
solid and liquid fuel boilers at ar ea 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 com bustion 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 fi re natural gas would be for
modification of the on-site gas handling syst em 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 mode l units in each scenario were grouped
according to fuel category for each model boiler (coa l, 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 facilitie s to report information on availability of
natural gas pipelines, or distances to near by 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 an alysis 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, th e 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 a nd 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 compone nts used to calculate
capital costs. Appendix A-4 presents the cost s calculated for each scenario described in Section

3.1 above.

3.2.2 Total Annual Costs
Total annual cost components consid ered 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 anal ysis are described in

another memorandum. 4 

# For area source boilers, if a unit swit ches 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, Commerci al and Institutional Bo ilers at Area Sources
of HAP. Therefore, the compliance costs to co nduct 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 equa tions 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 A ppendix A-4. Information on the amount of
natural-gas co-fired with other fu els was not reported in the boile r inspector survey, and for this
analysis, it was assumed that models co-firi ng any amount of fuel with natural gas would
completely switch to natural gas. This provide s 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 EMISSI ON 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, al though the source of emission factors differed slightly for area

sources. 4 

# Appendix A-6 presents the emission reduc tions 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 we re calculated by subtrac ting 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 fuel s experienced an increase in CO emissions as
a result of fuel switching, however overall emissi ons of CO were reduced across all fuel types.
Fuel switching is estimated to cause a small increa se in total dioxin/furan emissions for distillate
liquid and coal, but the overall di oxin/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 di scussed 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 resu lting from fuel switch ing 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 th is conversion, the annual hours of operation and
boiler design capacity reported in the survey were used for each unit in th e 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 o xygen 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 u nder 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 Combus tion Units (ICR No. 2286.01).

3. Leatherwood, C. ERG. Memorandum to Jim Eddinger, U.S. EPA, OAQPS. Development of Fuel Switching Costs and Em ission Reductions for Industrial/Commercial/Institutional Boilers and Process Heaters Nati onal 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 Pro cess Heaters National Emission Standards for Hazardous Air Pollutants – Major Source. April 2010.

5. Gibson, G. and A. Singleton, ERG. Deve lopment of Baseline Emission Factors for Boilers and Process Heaters at Commercial, In dustrial 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 Boile rs 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 + TCI B + TCI C Where: Total Capital Investment of Scenario A (TCI A ) = 293 * CF fs,a * DC * f 293 = conversion factor, kWh per mmBtu CF fs,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 * CF fs,b * DC * f 293 = conversion factor, kWh per mmBtu CF fs,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 TCI C i TCI C i = TCI B + ( L i * CF pipe, i )

i = denotation for either scenario C1, C2, or C3 L i = length of pipe needed to connect facility to pipeline (ft)
CF pipe, i = cost per foot of pipe (2008$/ft)

Equation 2 - Total Annual Cost (2008$) Total Annual Cost (2008$) = delF + EL + CR + TAC LF Where: Difference in Fuel Cost (delF) is defined in Equation 3 Efficiency Loss (EL) = ELF * f * DC * CF NG * Op hours ELF = efficiency loss factor, 0.05 Op hours = 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 = (CF NG - CF o ) * DC * f * Op hours Where: CF NG = cost of natural gas ($/mmBtu)
CF o = cost of original fuel ($/mmBtu) DC = design capacity (mmBtu/hr) f = capacity factor, 0.65 for solid fuel units and 0.5 for liquid fuel units Op hours = annual operating hours averaged per NAICS group

Equation 4 - Total Annual Cost to Landfill Biomass Diverted from Fuel Usage (2008$) TAC LF = f * DC * χ * 1000000 * (1 / HHV) * 0.0005 * Op hours * CF tipping 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 inp ut 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 Op hours = annual operating hours reported in 2008 survey (hours/year)
CF tipping = 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) = ER HI * 0.0005 * Op hours Where: ER HI = emission rate (lb/mmBtu) 0.0005 = conversion factor, tons per lb Op hours = annual operating hours reported in 2008 survey (hours/year)

Equation 6 - Conversion of ppm @ 3% O 2 Emission Factors to Ton Per Year Basis Annual Emission Rate (tpy) = ER C * 0.000001 * ρ air * Q S * 60 * Op hours * 0.0005 * (20.946 – O 2 ) / (20.946 – Std O 2 )
Where: ER C = emission concentration (ppm @ 3% O 2 ) 0.000001 = conversion factor, ppm to parts
ρ air

= density of air, 0.0749 lb/dscf
Q S = exhaust flowrate (dscfm), see calculations in Control Cost Memorandum. 60 = conversion factor, minutes per hour Op hours = annual operating hours reported in 2008 survey (hours/year) 0.0005 = conversion factor, tons per lb 20.946 = percentage of oxygen in ambient air O 2 = percentage of oxygen assumed in exhaust gas, see calculations in Control Cost Memorandum.
Std. O 2 = 3 percent oxygen in standardized emission concentration for proposed rule

Equation 7 - Conversion of ng/dscm @ 7% O 2 Emission Factors to Ton Per Year Basis Annual Emission Rate (tpy) = ER C * 0.0283 * Q S * 60 * Op hours * 0.000000001 * 0.0022 * 0.0005 * (20.946 – O 2 ) / (20.946 – Std O 2 )
Where: ER C = emission concentration (ng/dscm @ 7% O 2 ) 0.0283 = conversion factor, dry standard cubic meter per dry std. cubic foot Q S = exhaust flowrate (dscfm), see calculations in Control Cost Memorandum. 60 = conversion factor, minutes per hour Op hours = 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 O 2 = percentage of oxygen assumed in exhaust gas, see calculations in Control Cost Memorandum.
Std O 2 = 7 percent oxygen in standardized emission concentration for proposed ruleAppendix A-2: Cost and Emission Reduction Equation Inputs and ConstantsParameter Description Value UnitCFfs,aCost factor for fuel switching for scenario A (see App A-3)$13.01 2008$/kWCFfs,bCost factor for fuel switching for scenario B (see App A-3)$18.81 2008$/kWfCapacity factor (fraction of unit design capacity)0.65 (solid fuel)0.5 (liquid fuel)-LC1Length of pipe needed for scenario C1500 ftLC2Length of pipe needed for scenario C25,280 ftLC3Length of pipe needed for scenario C352,800 ftCFpipe,C1Cost per foot of pipe for scenario C1$186 2008$/ftCFpipe,C2Cost per foot of pipe for scenario C2$37 2008$/ftCFpipe,C3Cost per foot of pipe for scenario C3$22 2008$/ftELFEfficiency loss factor0.05 -CRFCapital recovery factor (lifetime of fuel switching equipment is20 years, at i = 7%)0.09439 -χThe average heat input contribution of biomass for units in thebiomass category. This is the portion of the heat inputassumed to be diverted to a landfill.0.882 -HHVHigher heating value of biomass8,600 Btu/lbCFtippingTipping fee to dispose of biomass in a landfill$42.14 2008$/tonρairDensity of air0.0749 lb/dscf

## 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 A verage 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 A verage 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 ($/kw) for Each SiteAppendix A-4: Summary of Total Capital Investment and Total Annual CostsTable 1 - Total Capital Investment, 2008$A B C1 C2 C3 C Total Total01 $0 $0 $0 $0 $0 $0$002 $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$2,010,415,04191 to 98 $39,991,164 $21,220,014 $60,371,832 $7,297,164,180 $8,578,003,889 $15,935,539,900$15,996,751,078Unknown $12,320,739 $2,690,428 $7,342,756 $831,981,025 $985,262,226 $1,824,586,007$1,839,597,174Total $406,405,405 $216,072,762 $866,237,732 $117,713,973,533 $138,618,781,211 $257,198,992,476 $257,821,470,643SICTCIAppendix A-4: Summary of Total Capital Investment and Total Annual CostsTable 2 - Total Annual Costs, 2008$A B C1 C2 C3 C TotalBiomass Diverted fromFuel Usage Efficiency Loss Total01 $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$121,969,24491 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$631,846,015Unknown ($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 $13,060,364,766SICTAC

### 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 Re g ulator y O p tion 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