1

MEMORANDUM 

TO: Jim Eddinger, U.S. Environmental Protection Agency, OAQPS (C439-01) 

FROM: Graham Gibson, ERG 

DATE: April 2010 

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

Commercial, and Institutional Boilers and Process Heaters National Emission 

Standards for Hazardous Air Pollutants

1.0 INTRODUCTION 

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

from existing boilers and process heaters switching to natural gas. Fuel switching is a potential 

control option that would require some boilers and process heaters to convert to natural gas, 

which emits lower emissions of some compounds 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 fuel 

switching combustion units that burn fuels other than solely natural gas are presented. 

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

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

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

calculation tables are in Appendix A. 
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2.0 RESULTS OF ANALYSIS 

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

switching all major source boilers and process heaters to natural gas. Fuel switching would 

require over $3 billion in capital costs and over $13 billion in annual costs. Of these totals, units 

firing coal or biomass, either wholly or partially, incur 47 percent of the capital and virtually all 

of the annual costs. Additionally, boilers or process heaters located at facilities in North 

American Industry Classification System (NAICS) code 322 account for the majority of all costs, 

at 22 percent of the capital and 47 percent of the annual costs. 

Table 2.1 – Summary of Capital and Annual Costs (2008$) 

for Fuel Switching to Natural Gas

Fuel Capital Costs 

($, Millions) 

Annual 

Costs/(Savings) 

($, Millions) 

Biomass 393 6,905 

Coal 1,171 8,122 

Distillate Liquid 165 (1,988) 

Process Gases 191 158 

Refinery Gas 1,271 1,002 

Residual Liquid 165 (668) 

Total 3,357 13,532 

Although coal units experience greater capital costs to switch to natural gas, the annual 

costs for biomass units are greater 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 coal. Although liquid units will 

incur a capital cost to install upgraded equipment for switching to natural gas, current fuel price 
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data for distillate and residual liquids result in a net annualized cost savings when switching to 

natural gas since the fuel oil costs are more expensive than natural gas. 

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.
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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 0.6 11.8 1.7 1.3 (1.2) 0.6 35.7 196.9 (0.7) 

Coal 17.6 128.3 1.4 3.2 29.0 10.2 21.8 174.2 49.2 

Distillate 

Liquid 11.3 14.1 4.7 2.1 19.9 1.7 26.5 1323.5 17.0 

Natural 

Gas N/A N/A N/A N/A N/A N/A N/A N/A N/A 

Process 

Gases 0.4 0.1 0.0 1.0 (2.7) (0.0) 11.1 (0.9) (3.6) 

Refinery 

Gas (0.0) (0.0) (0.0) (0.0) (0.2) (0.0) (0.0) (0.1) (0.4) 

Residual 

Liquid 9.9 4.9 2.4 2.7 3.2 11.8 9.6 639.2 266.9 

Total 40 159 10 10 48 24 105 2,333 328 

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

Total M

Dioxins/F

Biomass 1,527 30 16,142 0.3 23,047 204,091 4,568 2,055 0.80 

Coal 39,806 1,179 341,953 7.4 20,390 105,656 558 3,513 0.36 

Distillate 

Liquid 200 17 5,198 0.2 1,031 85,106 86 289 0.02 

Natural 

Gas N/A N/A N/A N/A N/A N/A N/A N/A N/A 

Process 

Gases 120 14 5,727 0.1 526 3,599 185 380 0.00 

Refinery 

Gas 2 6,792 933 0.0 140 5,197 3,256 1,597 (0.00

Residual 

Liquid 634 11 16,321 0.0 7,746 4,030 120 433 0.03 

Total 42,289 8,043 386,274 8 52,880 407,679 8,773 8,267 1.2 

1 Values in parentheses represent an increase in emissions for a specific pollutant as a result of switching to natural gas. 2 Emission reductions and increases in dioxin/furans are reported in units of lb/year. 
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3.0 DESCRIPTION OF COST ANALYSIS 

3.1 Assigning Boilers and Process Heaters to Fuel Switching Scenarios

A database containing the reported data from the 2008 Boiler and Process Heater 

Questionnaire (ICR No. 2286.01) was developed and used as the basis for this analysis. An 

inventory of all combustion units for which data were received was generated and then narrowed 

to major source boilers and process heaters. Detailed information about this database can be 

found in other memoranda1

. 

All boilers that did not report burning solely natural gas were reviewed and categorized 

into one of three scenarios in order to assess the impacts of switching to natural gas: 

A. The boiler or process heater already has the ability to burn natural gas in any 

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

modify the unit to burn natural gas only were estimated. 

B. The boiler or process heater does not use natural gas in any capacity, but the 

facility does use natural gas for some operation on site. This would require 

modifications to the boiler or process heater 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 or process heater, construction of an on-site gas handling system, and 

construction of a pipeline to the facility from the most accessible main gas line. 

All boilers or process heaters that burn solely natural gas were placed in Scenario A but 

there were not cost estimates prepared for these units since they will not incur any costs to switch 

to natural gas. Additionally, Scenario C was further divided into four cases to address the 

potential availability of natural gas at different facilities: 

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. 
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Each boiler and process heater in the questionnaire results database, other than those units 

assigned to the natural gas fuel category, were assigned to one of the above scenarios based on 

the fuel data reported in the 2008 questionnaire. If a unit reported combusting natural gas in any 

capacity (e.g., start-up, periods of gas curtailment, co-fired with other fuels) it was assigned to 

Scenario A. Any boiler or process heater not identified as firing natural gas, but located at a 

facility that had another combustion unit firing natural gas was assigned to Scenario B. If 

another unit at the facility was combusting natural gas, it was assumed that a natural gas line was 

available at the facility, so costs incurred for fuel switching the boiler or process heater would be 

to modify the on-site gas handling system to direct gas to the boiler and modify the boiler or 

process heater combustor to fire natural gas. All the boilers and process heaters that were not 

assigned to scenarios A or B were assigned to Scenario C. 

Next, the inventory of all major source boilers and process heaters were grouped 

according to the NAICS code reported for each facility, the size of the unit and the 10% fuel 

category assigned to the unit. The methods used to assign the 10% fuel category are presented in 

another memorandum.8

 NAICS were grouped at the 3-digit NAICS level, sizes were grouped 

according to one of four categories: less than 10 mmBtu/hr, between 10 and 100 mmBtu/hr, 

between 100 and 250 mmBtu/hr, and greater than 250 mmBtu/hr; and the fuels were grouped 

according to one of nine categories assigned to the unit: bagasse, coal, dry biomass, wet biomass, 

heavy liquids, light liquids, Gas 1 (natural gas only), Gas 1 (refinery gas or blends of refinery 

and natural gas), and Gas 2 (other process gases) . For each group, an average design capacity 

and average annual hours of operation were calculated using data reported for each of the units 

within the group. The number of units assigned to scenarios A, B, and C were summed for each 

of these groups. 

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.2

 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%. 
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3.2 Development of Cost Inputs and Factors 

The same base costs and cost sources that were used for the 2002 analysis for the vacated 

rule were also used in this analysis, but escalated to 2008 costs. 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 

Appendix A-3 presents the cost components used in the 2002 ERG analysis for Scenarios 

A and B. The Appendix lists the capital costs of each component required to upgrade burners or 

gas handling systems to allow a unit to fire natural gas.3 This feasibility study was used to 

develop capital cost breakdowns, in dollars per kilowatt of capacity ($/kW), for fuel switching to 

natural gas for five utility boilers at four different sites. For the four utility boilers studied, 

different breakdowns, component groupings, and component names were used. Similar 

components were grouped together based on descriptions provided and engineering judgment. 

The table also allocates components to the gas handling system, combustion equipment, or other 

(administrative, vendor representative, startup, etc...) costs. Components were assigned to 

scenarios A and B using engineering judgment based on the costs that would probably be 

incurred for each scenario. The costs for four of these boilers were averaged together, and then 

escalated to 2008$. Average costs were used to account for differences between the studies for 

each of the four boilers. 

Appendix A-4 presents the costs calculated for each scenario. The average costs for gas 

handling systems, combustor modifications, and other administrative and start-up costs were 

calculated to estimate the total cost of fuel switching for each scenario and to provide a 

normalized cost factor, based on the size of the boiler or process heater. 

For scenario C, cases C1, C2, and C3, the only additional costs beyond those for 

scenario B are the costs for the piping and piping installation (e.g., Case C1 cost = Scenario B 

cost + Case C1 piping cost). For this analysis, the pipe lengths used in cost estimates were 500 

feet for case C1, 1 mile for case C2, and 10 miles for case C3. Pipe lengths were based on 

engineering judgment, information provided in the 1986 feasibility study, and a study of 

pipelines in the United States4

. The cost per foot of pipe was determined based on whether the 
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scenario would be in a city or a rural area. A cost of $186 per foot of pipe was used for pipelines 

in a city (case C1), while costs of $37 and $22 per foot of pipe were used for pipelines in rural 

locations (cases C2 and C3, respectively). These values were based on the costs used in the 2002 

ERG analysis, escalated to 2008$. The higher cost for city pipelines are due to greater 

construction costs to install pipelines in smaller, more congested areas. 

3.2.2 Total Annual Costs 

The total annual cost components for fuel switching industrial boilers and process heaters 

to natural gas 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 

- Additional costs for gas-fired units to demonstrate compliance with the proposed 

rule 

- SO2 allowances 

- Capacity recovery 

Annualized capital costs were estimated using an interest rate of 7 percent and assuming 

that the burner and fuel handling equipment have a 20-year life span (equal to a capital recovery 

factor (CRF) of 0.09439). The annualized capital was calculated by multiplying the total capital 

investment by the CRF. 

Differences in fuel costs were calculated based on the prices obtained from the 

Department of Energy (DOE) Energy Information Administration (EIA) Tonto database for fuels 

delivered to commercial and industrial facilities, 20085

 The costs for distillate fuel and natural 

gas depend on whether the facility receiving the gas is an industrial or commercial fuel account, 

and the NAICS code groups discussed in Section 3.1 were used to delineate whether the 

purchased fuel price would be industrial or commercial. The prices of these fuels were converted 

to a dollars per million Btu ($/mmBtu) basis using higher heating values (HHV) reported in EPA 

mandatory reporting rule for greenhouse gases (40 CFR Part 98 subpart C).6

 For distillate fuel 

oil, the HHV for No. 2 fuel oil was used, for residual fuel oil, the HHV for No. 6 fuel oil was 

used, and for coal, the HHV for coal delivered to the mixed industrial sector was used. 
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Biomass cost = Free (assumed to be an industrial byproduct or fuel used by 

 third parties in lieu of landfilling the waste and not a 

purchased fuel) 

Coal cost = $54.42/short ton = $2.43/mmBtu 

assuming 22.35 mmBtu per short ton heating value 

Distillate Oil cost = 312.7 cents/gallon for commercial delivery= 

 $22.66/mmBtu 

 320.6 cents/gallon for industrial delivery= 

 $23.23/mmBtu 

 assuming 0.138 mmBtu per gallon heating value 

Natural Gas cost = $11.99/thousand standard cubic feet for comer. delivery = 

 $11.66/MMBtu 

 $9.58/thousand standard cubic feet for ind. delivery = 

 $9.32/MMBtu 

assuming 1.028 mmBtu per thousand scf heating value 

Process Gas cost = Free, assumed to be flared if not used for energy recovery 

Refinery Gas cost = Free, assumed to be flared if not used for energy recovery 

Residual Oil cost = $194.4 cents/gallon = $12.96/MMBtu 

 assuming 0.15 mmBtu per gallon heating value 

An annual fuel savings was calculated based on the average annual hours of operation for 

each group of units in the same NAICS, fuel, and size category. Any combustion unit that did 

not report an annual operating time was assumed to operate 8,400 hours per (i.e., two weeks 

down time per year). Further, all boilers and process heaters were assumed to operate at 90 

percent of the average design capacity for each NAICS, fuel, and size category. The annual fuel 

savings was calculated using Equation 3 in Appendix A-1. 

The 1986 feasibility study provides an average efficiency loss of 5 percent when 

converting to natural gas.3

 This value was used to calculate the additional heat input required to 

overcome the loss. The equations used to calculate capital and annual costs are provided in 

Appendix A-1. Inputs for cost equations are summarized in Appendix A-2. 

It was assumed that boilers and process heaters combusting biomass would incur 

additional costs to landfill any biomass no longer combusted as a result of fuel switching to 

natural gas. This additional cost only applied to biomass units since other solid fuels are 

purchased fuels or fuels that would be flared off in the event a unit switched to natural gas. The 

equation used to calculate the cost of sending unused biomass to a landfill is found in Appendix 

A-1. These costs are based on a solid waste tipping fee of $42.14 per ton, consistent with the 

waste disposal costs used in the control cost memorandum.7 
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 Natural gas fired units are one of the affected subcategories under the NESHAP for 

Industrial, Commercial, and Institutional Boilers and Process Heaters at Major Sources HAP. As 

a result, if a unit switches from their current fuel to natural gas, the unit will still need to 

demonstrate compliance with the requirements for new natural gas units. Natural gas units are 

required to conduct an annual tune-up to demonstrate compliance with the proposed rule, and so 

the costs of an annual tune-up have been added. Costs for an annual tune-up are discussed in an 

another memorandum.7 

SO2 allowances and capacity recovery were not included in the analysis because there 

was insufficient information to estimate them. Additionally, they are not considered to be as 

significant as the annualized capital costs and annual fuel cost differences, and their exclusion 

should not have a significant impact on the results of the analysis. 

3.3 Calculation of Cost Impacts 

Capital and annual costs of fuel switching all of the boilers and process heaters assigned 

to each applicable group of common NAICS codes are presented in Appendix A-4. 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

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. In general emissions of Hg, filterable PM, HCl, HF, SO2, CO, THC, VOC, and nonmercury metallic HAP decreased when switching to NG. For residual liquid and process gas 

subcategories, formaldehyde emissions increased as a result of fuel switching. However, total 

emissions of formaldehyde experienced a net reduction when all fuel categories were factored. 

Overall emissions of total mass dioxins/furans increased as a result of fuel switching. 

Emission reductions were calculated on the combustion unit level, not by NAICS 

subcategory. Baseline emission factors from the current fuels reported at each unit in the major 
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source boiler and process heater inventory were calculated for the baseline emissions analysis 

and are discussed in another memorandum8. For this analysis, the average baseline emission 

factors developed for uncontrolled units firing only natural gas were used as the basis for 

estimating emission reductions for natural gas. 

Emission reductions from fuel switching were calculated on a ton per year basis by 

subtracting the emission rates and concentrations estimated from burning natural gas from the 

baseline emission rates and concentrations estimated from burning the existing fuel(s). 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.7 

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

using add-on control technologies.
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5.0 REFERENCES

1. Gibson, Graham. ERG. Data Dictionary for Boiler, Process Heater, and Other 

Combustion Unit Survey Databases. April 2010. 

2. Leatherwood, Chad. 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. 

3. Fay, James, et al, Massachusetts Institute of Technology. Feasibility and Cost of 

Converting Oil- and Coal-fired Utility Boilers to Intermittent Use of Natural Gas. 

December 1986. 

4. U.S. Department of Energy. Energy Information Administration. Capacity and Service 

on the Interstate Natural Gas Pipeline System. 1990, Regional Profiles and Analyses. 

June, 1992. DOE/EIA-0556. 

5. U.S. Department of Energy, EIA. 2008 Delivered Fuel Prices to Industrial and 

Commerical Clients. http://www.eia.doe.gov/

6. U.S. EPA. Mandatory Greenhouse Gas Reporting Rule. 40 CFR Part 98. Table C-1 from 

SUBPART C OF PART 98—DEFAULT CO2 EMISSION FACTORS AND HIGH 

HEAT VALUES FOR VARIOUS TYPES OF FUEL: 

http://www.epa.gov/climatechange/emissions/downloads09/GHG-MRR-FinalRule.pdf

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

the Major Source Industrial, Commercial and Institutional Boilers and Process Heaters 

National Emission Standards for Hazardous Air Pollutants. April 2010. 

8. Gibson, G, ERG. Development of Baseline Emission Factors for Boilers and Process 

Heaters at Commercial, Industrial, and Institutional Facilities. 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 + TCItune-up

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 (fraction of design capacity the boiler is estimated to operate), 0.9

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 (fraction of design capacity the boiler is estimated to operate), 0.9

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)

TCItune-up = capital investment for a boiler tune-up, $6,477 per boiler

Equation 2 - Total Annual Cost (2008$)

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

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

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

TACtune-up = total annual cost of a boiler tune-up, $1,580 per boiler

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, (fraction of design capacity the boiler is estimated to operate), 0.9

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, (fraction of design capacity the boiler is estimated to operate), 0.9

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) $13.01 2008$/kW

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

f Capacity factor (fraction of unit design capacity) 0.9 -

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 $186 2008$/ft

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

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

TCItune-up Capital investment for a boiler tune-up $6,477 2008$/unit

TACtune-up

Annual cost for a boiler tune-up (annualized over 5 years at i = 

7%) $1,580 2008$/unit

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 $42.14 2008$/ton

ρair Density of air 0.0749 lb/dscf
Appendix A-3. Fuel Switching--Components of Capital Cost for Each Natural Gas Scenario

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

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 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 from Fuel Switching to Natural Gas

Table 1 - Total Capital Investment, 2008$

A B C1 C2 C3 C Total

Tune-Up for Gas 

Units Total

111 $3,782,203 $0 $0 $0 $0 $0 $19,431 $3,801,634113 $0 $0 $0 $196,514 $0 $196,514 $6,477 $202,991115 $0 $1,614,780 $0 $0 $0 $0 $12,954 $1,627,734211 $1,185,560 $0 $0 $393,029 $0 $393,029 $58,293 $1,636,882212 $9,019,806 $6,617,238 $0 $8,189,353 $0 $8,189,353 $142,494 $23,968,891221 $95,033,854 $66,459,170 $58,729,485 $86,222,135 $73,464,724 $218,416,344 $1,800,606 $381,709,973311 $67,922,533 $40,018,264 $93,047 $43,096,372 $16,843,445 $60,032,863 $1,243,584 $169,217,244312 $2,037,891 $1,237,263 $0 $2,416,349 $0 $2,416,349 $77,724 $5,769,227313 $369,699 $2,875,190 $0 $1,468,579 $0 $1,468,579 $77,724 $4,791,192314 $0 $1,454,955 $0 $0 $0 $0 $19,431 $1,474,386316 $63,672 $0 $0 $1,375,601 $1,179,086 $2,554,687 $58,293 $2,676,652321 $26,007,969 $12,560,203 $12,751,823 $40,063,711 $29,693,742 $82,509,276 $1,794,129 $122,871,577322 $247,013,145 $146,107,030 $99,008,523 $144,210,557 $109,926,264 $353,145,343 $1,936,623 $748,202,141323 $3,186,449 $27,556 $0 $393,029 $0 $393,029 $187,833 $3,794,866324 $136,093,699 $884,821,541 $0 $6,828,545 $2,025,291 $8,853,836 $12,390,501 $1,042,159,577325 $241,261,392 $126,624,294 $0 $34,889,071 $25,527,383 $60,416,455 $3,257,931 $431,560,071326 $15,170,844 $6,853,268 $0 $806,071 $0 $806,071 $524,637 $23,354,821327 $54,522 $1,295 $0 $1,375,601 $1,179,086 $2,554,687 $64,770 $2,675,273331 $115,145,749 $10,669,526 $0 $1,179,086 $1,179,086 $2,358,172 $705,993 $128,879,440332 $5,776,883 $27,556 $0 $589,543 $0 $589,543 $116,586 $6,510,568333 $8,512,353 $14,297,630 $0 $0 $0 $0 $71,247 $22,881,230334 $0 $0 $0 $0 $0 $0 $0 $0335 $1,182,243 $0 $0 $0 $0 $0 $45,339 $1,227,582336 $20,592,052 $13,487,719 $93,047 $16,877,207 $2,358,172 $19,328,426 $693,039 $54,101,236337 $735,149 $767,357 $837,644 $8,234,902 $5,483,701 $14,556,248 $356,235 $16,414,988339 $34,314 $218,739 $0 $0 $0 $0 $32,385 $285,439423 $55,818 $0 $0 $0 $0 $0 $6,477 $62,295424 $0 $0 $0 $0 $0 $0 $0 $0441 $0 $0 $0 $0 $0 $0 $0 $0481 $5,351,893 $567,653 $0 $0 $0 $0 $181,356 $6,100,902482 $0 $1,322,687 $0 $0 $0 $0 $19,431 $1,342,118486 $0 $55,112 $0 $0 $0 $0 $12,954 $68,066488 $0 $0 $0 $589,543 $0 $589,543 $19,431 $608,974493 $251,549 $0 $0 $196,514 $0 $196,514 $19,431 $467,494531 $2,301,348 $0 $0 $0 $0 $0 $25,908 $2,327,256541 $3,097,441 $617,254 $0 $1,179,086 $1,179,086 $2,358,172 $90,678 $6,163,545561 $228,762 $0 $0 $0 $0 $0 $6,477 $235,239562 $54,712 $240,013 $0 $196,514 $0 $196,514 $32,385 $523,624611 $39,909,019 $13,673,947 $0 $0 $0 $0 $783,717 $54,366,683622 $986,528 $4,529,885 $0 $0 $0 $0 $84,201 $5,600,614623 $0 $0 $0 $196,514 $0 $196,514 $6,477 $202,991811 $215,799 $155,967 $0 $0 $0 $0 $19,431 $391,197921 $482,307 $1,984 $0 $0 $0 $0 $25,908 $510,199928 $8,916,868 $20,825,199 $2,278,241 $23,532,837 $19,406,036 $45,217,114 $1,625,727 $76,584,907

Total $1,062,034,024 $1,378,730,274 $173,791,808 $424,696,264 $289,445,103 $887,933,175 $28,654,248 $3,357,351,722

NAICS

TCI
Appendix A-4: Summary of Total Capital Investment and Total Annual Costs from Fuel Switching to Natural Gas

Table 2 - Total Annual Costs, 2008$/yr

A B C1 C2 C3 C Total

Biomass Diverted 

from Fuel Usage 

to Landfill

Tune-Up for Gas 

Units Efficiency Loss Total

111 $66,610,976 $0 $0 $0 $0 $0 $0 $4,740 $4,184,839 $70,800,555

113 $0 $0 $0 $5,534,195 $0 $5,534,195 $1,022,192 $1,580 $275,782 $6,833,750115 $0 $20,597,607 $0 $0 $0 $0 $0 $3,160 $1,291,392 $21,892,159211 $111,905 $0 $0 ($1,069,847) $0 ($1,069,847) $0 $14,220 $1,490,124 $546,402212 $146,641,797 $72,751,607 $0 $69,693,463 $0 $69,693,463 $0 $34,760 $20,477,915 $309,599,541221 $535,158,555 $444,940,647 ($19,703,592) ($416,607,154) ($55,700,746) ($492,011,491) $37,598,344 $439,240 $149,982,105 $676,107,399311 $555,711,392 $350,116,594 $18,762,590 $354,654,867 $47,381,552 $420,799,010 $79,563,031 $303,360 $98,731,402 $1,505,224,789312 $192,356 $8,498,488 $0 $24,629,604 $0 $24,629,604 $0 $18,960 $4,210,274 $37,549,682313 $34,896 $17,424,066 $0 $3,815,283 $0 $3,815,283 $0 $18,960 $1,671,499 $22,964,704314 $0 $11,924,194 $0 $0 $0 $0 $0 $4,740 $797,196 $12,726,130316 ($1,101,001) $0 $0 ($3,909,882) ($487,664) ($4,397,545) $0 $14,220 $495,845 ($4,988,481)321 $389,448,035 $150,610,154 $45,319,553 $866,844,302 $95,108,450 $1,007,272,305 $356,311,527 $437,660 $79,829,765 $1,983,909,445322 $2,819,434,712 $1,325,879,989 $81,733,992 $909,877,393 $103,320,466 $1,094,931,851 $751,778,836 $472,420 $365,581,205 $6,358,079,013323 ($13,738,038) $2,601 $0 ($327,115) $0 ($327,115) $0 $45,820 $2,416,765 ($11,599,966)324 ($7,375,944) $107,149,999 $0 ($91,407,925) ($735,442) ($92,143,368) $0 $3,022,540 $722,738,307 $733,391,534325 $169,139,949 $271,196,122 $0 $70,597,317 $5,333,357 $75,930,674 $0 $794,740 $288,755,580 $805,817,065326 ($42,302,387) $43,745,889 $0 ($8,519,791) $0 ($8,519,791) $320,194 $127,980 $14,972,862 $8,344,748327 $359,844 ($2,110) $0 ($1,403,072) ($107,694) ($1,510,766) $0 $15,800 $82,966 ($1,054,267)331 $212,688,603 ($14,030,726) $0 ($3,087,391) ($421,820) ($3,509,212) $0 $172,220 $98,456,665 $293,777,549332 $34,703,685 $2,601 $0 ($1,350,268) $0 ($1,350,268) $0 $28,440 $4,120,227 $37,504,685333 $114,371,224 $137,098,025 $0 $0 $0 $0 $0 $17,380 $17,028,049 $268,514,679334 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0335 ($231,116) $0 $0 $0 $0 $0 $0 $11,060 $739,159 $519,103336 ($81,770,316) $31,535,174 ($217,855) $1,055,139 ($2,571,412) ($1,734,128) $204,594 $169,060 $19,205,553 ($32,390,063)337 $7,760,126 $6,346,167 $1,576,594 $46,023,140 $4,504,785 $52,104,519 $11,717,157 $86,900 $3,639,648 $81,654,518339 $609,628 ($315,009) $0 $0 $0 $0 $140,595 $7,900 $73,291 $516,405423 ($1,181,889) $0 $0 $0 $0 $0 $0 $1,580 $65,294 ($1,115,015)424 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0441 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0481 ($179,987) ($256,001) $0 $0 $0 $0 $0 $44,240 $4,427,387 $4,035,639482 $0 $8,099,568 $0 $0 $0 $0 $0 $4,740 $503,712 $8,608,020486 $0 $5,202 $0 $0 $0 $0 $0 $3,160 $44,075 $52,437488 $0 $0 $0 ($58,123,089) $0 ($58,123,089) $0 $4,740 $3,199,830 ($54,918,519)493 ($911,778) $0 $0 ($449,212) $0 ($449,212) $0 $4,740 $77,181 ($1,279,070)531 $217,224 $0 $0 $0 $0 $0 $0 $6,320 $1,266,836 $1,490,380541 ($11,490,080) $4,524,106 $0 ($6,979,091) ($1,070,437) ($8,049,528) $0 $22,120 $2,328,797 ($12,664,585)561 $21,593 $0 $0 $0 $0 $0 $0 $1,580 $7,556 $30,729562 ($48,193) ($30,702) $0 ($290,318) $0 ($290,318) $0 $7,900 $118,469 ($242,844)611 $275,792,832 $97,411,996 $0 $0 $0 $0 $0 $191,180 $36,367,915 $409,763,923622 $9,038,577 $36,000,681 $0 $0 $0 $0 $0 $20,540 $3,173,039 $48,232,837623 $0 $0 $0 $4,202,785 $0 $4,202,785 $0 $1,580 $264,291 $4,468,656811 ($4,515,328) ($2,253,127) $0 $0 $0 $0 $0 $4,740 $374,195 ($6,389,520)921 $45,525 $187 $0 $0 $0 $0 $0 $6,320 $193,965 $245,997928 ($61,160,588) ($41,700,885) ($1,683,083) $22,416,323 $6,611,451 $27,344,691 $0 $396,580 $20,612,854 ($54,507,348)

Total $5,112,086,789 $3,087,273,104 $125,788,201 $1,785,819,656 $201,164,844 $2,112,772,701 $1,238,656,470 $6,989,920 $1,974,273,810 $13,532,052,794

NAICS

TAC
TCI TAC TCI

TAC Considering Fuel 

Savings

111 3,801,633.79 $ 70,800,555.18 $ 34,394,146.13 $ 8,185,848.19 $ 

113 202,991.36 $ 6,833,749.85 $ 2,825,199.09 $ 910,548.28 $ 

115 1,627,734.08 $ 21,892,159.13 $ 5,120,044.64 $ 3,111,555.24 $ 

211 1,636,882.16 $ 546,401.61 $ 15,828,296.87 $ 5,521,319.85 $ 

212 23,968,891.48 $ 309,599,541.38 $ 143,984,529.99 $ 50,034,614.97 $ 

221 381,709,973.17 $ 676,107,399.41 $ 1,546,936,814.85 $ 605,000,865.88 $ 

311 169,217,243.80 $ 1,505,224,788.72 $ 738,316,167.15 $ 281,216,781.47 $ 

312 5,769,227.15 $ 37,549,682.23 $ 60,601,574.81 $ 25,019,865.16 $ 

313 4,791,191.87 $ 22,964,703.66 $ 26,560,064.06 $ 7,782,641.66 $ 

314 1,474,386.43 $ 12,726,129.56 $ 14,853,391.77 $ 4,030,456.42 $ 

316 2,676,651.84 $ (4,988,481.26) $ 6,137,167.88 $ 2,160,749.98 $ 

321 122,871,576.55 $ 1,983,909,445.47 $ 652,613,289.88 $ 198,099,874.72 $ 

322 748,202,140.95 $ 6,358,079,012.58 $ 2,721,639,091.10 $ 966,399,030.15 $ 

323 3,794,866.36 $ (11,599,966.07) $ 3,476,077.97 $ 2,137,285.44 $ 

324 1,042,159,577.03 $ 733,391,533.97 $ 214,106,789.09 $ 70,349,519.47 $ 

325 431,560,071.49 $ 805,817,064.54 $ 1,795,121,823.82 $ 588,533,438.21 $ 

326 23,354,820.81 $ 8,344,747.52 $ 88,047,241.37 $ 30,408,317.64 $ 

327 2,675,273.48 $ (1,054,266.55) $ 1,431,787.13 $ 1,531,150.19 $ 

331 128,879,440.03 $ 293,777,549.42 $ 861,026,139.40 $ 274,504,439.22 $ 

332 6,510,567.71 $ 37,504,685.26 $ 22,819,553.21 $ 12,873,251.39 $ 

333 22,881,229.58 $ 268,514,678.59 $ 219,743,781.84 $ 84,712,983.70 $ 

334 - $ - $ 84,201.00 $ 73,959.00 $ 

335 1,227,582.39 $ 519,103.08 $ 3,330,346.73 $ 1,473,540.62 $ 

336 54,101,235.64 $ (32,390,063.39) $ 233,229,886.77 $ 74,161,783.79 $ 

337 16,414,988.00 $ 81,654,517.99 $ 72,421,153.93 $ 23,200,513.15 $ 

339 285,438.66 $ 516,405.50 $ 2,325,391.82 $ 1,107,086.92 $ 

423 62,294.99 $ (1,115,015.27) $ 172,595.05 $ 187,926.01 $ 

424 - $ - $ 12,954.00 $ 6,604.00 $ 

441 - $ - $ 19,431.00 $ 9,479.00 $ 

481 6,100,902.27 $ 4,035,639.09 $ 26,057,055.93 $ 7,408,173.02 $ 

482 1,342,117.76 $ 8,608,020.40 $ 3,337,188.68 $ 1,255,386.33 $ 

486 68,065.95 $ 52,436.82 $ 1,502,664.00 $ 718,240.00 $ 

488 608,974.08 $ (54,918,518.55) $ 4,875,430.12 $ 1,503,307.60 $ 

493 467,494.36 $ (1,279,069.86) $ 923,521.37 $ 655,274.16 $ 

531 2,327,256.39 $ 1,490,379.95 $ 32,385.00 $ 15,229.00 $ 

541 6,163,545.21 $ (12,664,585.07) $ 19,609,176.72 $ 6,138,161.53 $ 

561 235,239.27 $ 30,728.55 $ 6,477.00 $ 3,729.00 $ 

562 523,624.20 $ (242,843.85) $ 5,587,627.30 $ 2,045,389.87 $ 

611 54,366,682.84 $ 409,763,922.75 $ 269,825,554.14 $ 95,356,751.60 $ 

622 5,600,613.99 $ 48,232,836.91 $ 23,483,772.12 $ 8,346,702.94 $ 

623 202,991.36 $ 4,468,656.28 $ 3,544,839.16 $ 1,082,691.83 $ 

811 391,196.88 $ (6,389,520.37) $ 816,775.94 $ 620,023.23 $ 

921 510,199.14 $ 245,997.04 $ 32,385.00 $ 16,083.00 $ 

928 76,584,907.14 $ (54,507,348.44) $ 152,180,442.63 $ 63,190,897.18 $ 

Total $3,357,351,722 $13,532,052,794 $9,998,994,227 $3,511,101,470

NAICS

Fuel Switching Costs

Add-on Control Costs under 

Proposed Option 4

Appendix A-5: Comparison of Costs for Fuel Switching and 

Proposed Regulatory Option 4e
Appendix A-6 - Summary of Emission Reductions for Fuel Switching

Fuel Subcategory Pollutant

Emission Reductions from 

Fuel Switching (tpy)

Biomass Mercury (Hg) 0 

Filterable PM (PM) 23,047 

Hydrogen Chloride (HCl) 1,527 

Hydrogen Fluoride (HF) 29 

Sulfur Dioxide (SO2) 16,142 

Carbon Monoxide (CO) 204,091 

Total Hydrocarbons (THC) 4,568 

Volatile Organic Compounds (VOC) 2,055 

Total Mass Dioxins/Furans 0 

Arsenic (As) 12 

Beryllium (Be) 2 

Cadmium (Cd) 1

Cobalt (Co) 1

Chromium (Cr) (1) 

Nickel (Ni) (1)

Manganese (Mn) 197 

Lead (Pb) 36 

Antimony (Sb) 1 

Selenium (Se) 3

Total Selected Metals (TSM) 249 

Formaldehyde 294

Coal Mercury (Hg) 7 

Filterable PM (PM) 20,390 

Hydrogen Chloride (HCl) 39,806 

Hydrogen Fluoride (HF) 1,179 

Sulfur Dioxide (SO2) 341,953 

Carbon Monoxide (CO) 105,656 

Total Hydrocarbons (THC) 558 

Volatile Organic Compounds (VOC) 3,513 

Total Mass Dioxins/Furans 0 

Arsenic (As) 128 

Beryllium (Be) 1 

Cadmium (Cd) 3

Cobalt (Co) 10 

Chromium (Cr) 29

Nickel (Ni) 49

Manganese (Mn) 174 

Lead (Pb) 22 

Antimony (Sb) 18

Selenium (Se) 1,212 

Total Selected Metals (TSM) 1,647 

Formaldehyde 336 

Gas 1 (NG Only) Mercury (Hg) N/A

Filterable PM (PM) N/A

Hydrogen Chloride (HCl) N/A

Hydrogen Fluoride (HF) N/A

Sulfur Dioxide (SO2) N/A

Carbon Monoxide (CO) N/A

Total Hydrocarbons (THC) N/A

Volatile Organic Compounds (VOC) N/A

Total Mass Dioxins/Furans N/A

Arsenic (As) N/A

Beryllium (Be) N/A

Cadmium (Cd) N/A

Cobalt (Co) N/A

Chromium (Cr) N/A

Nickel (Ni) N/A

Manganese (Mn) N/A

Lead (Pb) N/A

Antimony (Sb) N/A

Selenium (Se) N/A

Total Selected Metals (TSM) N/A

Formaldehyde N/A
Appendix A-6 - Summary of Emission Reductions for Fuel Switching

Fuel Subcategory Pollutant

Emission Reductions from 

Fuel Switching (tpy)

Gas 1 (Other) Mercury (Hg) 0 

Filterable PM (PM) 140 

Hydrogen Chloride (HCl) 2 

Hydrogen Fluoride (HF) 6,792 

Sulfur Dioxide (SO2) 933 

Carbon Monoxide (CO) 5,197 

Total Hydrocarbons (THC) 3,256 

Volatile Organic Compounds (VOC) 1,597 

Total Mass Dioxins/Furans (0) 

Arsenic (As) (0)

Beryllium (Be) (0)

Cadmium (Cd) (0)

Cobalt (Co) (0)

Chromium (Cr) (0)

Nickel (Ni) (0)

Manganese (Mn) (0)

Lead (Pb) (0)

Antimony (Sb) (0)

Selenium (Se) (0)

Total Selected Metals (TSM) (1)

Formaldehyde 445 

Gas 2 Mercury (Hg) 0 

Filterable PM (PM) 526 

Hydrogen Chloride (HCl) 120

Hydrogen Fluoride (HF) 14 

Sulfur Dioxide (SO2) 5,727 

Carbon Monoxide (CO) 3,599 

Total Hydrocarbons (THC) 185 

Volatile Organic Compounds (VOC) 380

Total Mass Dioxins/Furans 0 

Arsenic (As) 0

Beryllium (Be) 0

Cadmium (Cd) 1

Cobalt (Co) (0) 

Chromium (Cr) (3)

Nickel (Ni) (4)

Manganese (Mn) (1)

Lead (Pb) 11 

Antimony (Sb) 0 

Selenium (Se) 0

Total Selected Metals (TSM) 6

Formaldehyde (21) 
Appendix A-6 - Summary of Emission Reductions for Fuel Switching

Fuel Subcategory Pollutant

Emission Reductions from 

Fuel Switching (tpy)

Heavy Liquid Mercury (Hg) 0 

Filterable PM (PM) 7,746 

Hydrogen Chloride (HCl) 634 

Hydrogen Fluoride (HF) 11 

Sulfur Dioxide (SO2) 16,321 

Carbon Monoxide (CO) 4,030 

Total Hydrocarbons (THC) 120 

Volatile Organic Compounds (VOC) 433

Total Mass Dioxins/Furans 0 

Arsenic (As) 5

Beryllium (Be) 2

Cadmium (Cd) 3

Cobalt (Co) 12 

Chromium (Cr) 3 

Nickel (Ni) 267 

Manganese (Mn) 639

Lead (Pb) 10 

Antimony (Sb) 10

Selenium (Se) 7 

Total Selected Metals (TSM) 958 

Formaldehyde (12) 

Light Liquid Mercury (Hg) 0 

Filterable PM (PM) 1,031 

Hydrogen Chloride (HCl) 200 

Hydrogen Fluoride (HF) 17 

Sulfur Dioxide (SO2) 5,198 

Carbon Monoxide (CO) 85,106 

Total Hydrocarbons (THC) 86 

Volatile Organic Compounds (VOC) 289 

Total Mass Dioxins/Furans 0 

Arsenic (As) 14 

Beryllium (Be) 5 

Cadmium (Cd) 2

Cobalt (Co) 2

Chromium (Cr) 20 

Nickel (Ni) 17

Manganese (Mn) 1,324 

Lead (Pb) 27 

Antimony (Sb) 11

Selenium (Se) 17

Total Selected Metals (TSM) 1,438 

Formaldehyde 2 

TOTAL Mercury (Hg) 8

Filterable PM (PM) 52,879 

Hydrogen Chloride (HCl) 42,289 

Hydrogen Fluoride (HF) 8,041 

Sulfur Dioxide (SO2) 386,274 

Carbon Monoxide (CO) 407,679 

Total Hydrocarbons (THC) 8,773 

Volatile Organic Compounds (VOC) 8,267 

Total Mass Dioxins/Furans 0 

Arsenic (As) 159 

Beryllium (Be) 10 

Cadmium (Cd) 10

Cobalt (Co) 24

Chromium (Cr) 48

Nickel (Ni) 329 

Manganese (Mn) 2,333 

Lead (Pb) 105 

Antimony (Sb) 40 

Selenium (Se) 1,239 

Total Selected Metals (TSM) 4,297 

Formaldehyde 1,044 

NA: Emission reductions for natural gas units were not calculated under the fuel switching option.
Fuel Subcategory Pollutant

Emission Reductions 

from Fuel Switching (tpy)

Emission Reductions 

from Proposed Option 

(tpy)

Biomass Mercury (Hg) 0 2.19E-01

Filterable PM (PM) 23,047 15,063

Hydrogen Chloride (HCl) 1,527 516 

Total Hydrocarbons (THC) 4,568 1,326 

Volatile Organic Compounds (VOC) 2,055 7.61E+02

Carbon Monoxide (CO) 204,091 1.08E+05

Total Mass Dioxins/Furans 0 4.47E-04

Hydrogen Fluoride (HF) 29 8.46E+00

Sulfur Dioxide (SO2) 16,142 11,159 

Total Selected Metals (TSM) 249 227 

Coal Mercury (Hg) 7 7 

Filterable PM (PM) 20,390 17,067 

Hydrogen Chloride (HCl) 39,806 40,710

Total Hydrocarbons (THC) 558 851 

Volatile Organic Compounds (VOC) 3,513 489 

Carbon Monoxide (CO) 105,656 112,286

Total Mass Dioxins/Furans 0 2.93E-04

Hydrogen Fluoride (HF) 1,179 999

Sulfur Dioxide (SO2) 341,953 319,109

Total Selected Metals (TSM) 1,647 768 

Gas 1 (NG Only) Mercury (Hg) N/A 3.88E-03

Filterable PM (PM) N/A 50 

Hydrogen Chloride (HCl) N/A 4

Total Hydrocarbons (THC) N/A 76 

Volatile Organic Compounds (VOC) N/A 43 

Carbon Monoxide (CO) N/A 482

Total Mass Dioxins/Furans N/A 1.19E-06

Hydrogen Fluoride (HF) N/A 45

Sulfur Dioxide (SO2) N/A 24

Total Selected Metals (TSM) N/A 1 

Gas 1 (Other) Mercury (Hg) 0 0 

Filterable PM (PM) 140 77 

Hydrogen Chloride (HCl) 2 6

Total Hydrocarbons (THC) 3,256 50 

Volatile Organic Compounds (VOC) 1,597 29 

Carbon Monoxide (CO) 5,197 332

Total Mass Dioxins/Furans (0) 1.37E-06

Hydrogen Fluoride (HF) 6,792 77

Sulfur Dioxide (SO2) 933 50

Total Selected Metals (TSM) (1) 1 

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

Regulatory Option 4e
Fuel Subcategory Pollutant

Emission Reductions 

from Fuel Switching (tpy)

Emission Reductions 

from Proposed Option 

(tpy)

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

Regulatory Option 4e

Gas 2 Mercury (Hg) 0 1.72E-01

Filterable PM (PM) 526 0 

Hydrogen Chloride (HCl) 120 220 

Total Hydrocarbons (THC) 185 3.02E+02

Volatile Organic Compounds (VOC) 380 1.73E+02

Carbon Monoxide (CO) 3,599 8,150

Total Mass Dioxins/Furans 0 2.16E-08

Hydrogen Fluoride (HF) 14 27

Sulfur Dioxide (SO2) 5,727 6,677

Total Selected Metals (TSM) 6 0 

Liquid Mercury (Hg) 0 5.13E-05

Filterable PM (PM) 8,777 10,433 

Hydrogen Chloride (HCl) 834 949 

Total Hydrocarbons (THC) 206 501 

Volatile Organic Compounds (VOC) 722 287 

Carbon Monoxide (CO) 89,137 102,676

Total Mass Dioxins/Furans 0 5.33E-05

Hydrogen Fluoride (HF) 27 40

Sulfur Dioxide (SO2) 21,519 23,281

Total Selected Metals (TSM) 2,396 2,203 

TOTAL Mercury (Hg) 8 8 

Filterable PM (PM) 52,879 50,120 

Hydrogen Chloride (HCl) 42,289 42,403

Total Hydrocarbons (THC) 8,773 3,105 

Volatile Organic Compounds (VOC) 8,267 1,782 

Carbon Monoxide (CO) 407,679 331,437 

Total Mass Dioxins/Furans 0 7.96E-04

Hydrogen Fluoride (HF) 8,041 1,197 

Sulfur Dioxide (SO2) 386,274 360,301 

Total Selected Metals (TSM) 4,297 3,199