## 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 Co sts 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 discu ss 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 a nd process heaters to convert to natural gas, which emits lower emissions of some compounds co mpared 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 sole ly 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. S ection 5.0 presents the 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 major source boilers and process heaters to natural gas. Fuel switching would require over $3 billion in capital co sts and over $13 billion in annual costs. Of these totals, units firing coal or biomass, either w holly or partially, incu r 47 percent of the cap ital and virtually all of the annual costs. Additionally, boilers or pr ocess heaters located at facilities in North American Industry Classification Sy stem (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 gr eater 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 rela tive difference in fuel prices between natural gas and biomass compared with the price difference between na tural gas and coal. Although liquid units will incur a capital cost to install upgraded equipment fo r switching to natural ga s, current fuel price

## 3 data for distillate and residual liquids result in a net annualized cost savings when switching to natural gas since the fuel oil costs ar e more expensive than natural gas.

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.4Table 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 0.6 11.8 1.7 1.3 (1.2) 0.6 35.7 196.9 (0.7) 2.5Coal 17.6 128.3 1.4 3.2 29.0 10.2 21.8 174.2 49.2 1212.3DistillateLiquid11.3 14.1 4.7 2.1 19.9 1.7 26.5 1323.5 17.0 17.2NaturalGasN/A N/A N/A N/A N/AN/A N/A N/A N/A N/AProcessGases0.4 0.1 0.0 1.0 (2.7) (0.0) 11.1 (0.9) (3.6) 0.4RefineryGas(0.0) (0.0) (0.0) (0.0) (0.2) (0.0) (0.0) (0.1) (0.4) (0.0)ResidualLiquid9.9 4.9 2.4 2.7 3.2 11.8 9.6 639.2 266.9 6.8Total 40 159 10 10 48 24 105 2,333 328 1,2391Values in parentheses represent an increase in emissions for a specific pollutant as a result of switching to natural gas5Table 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 1,527 30 16,142 0.3 23,047 204,091 4,568 2,055 0.80 294Coal 39,806 1,179 341,953 7.4 20,390 105,656 558 3,513 0.36 336DistillateLiquid200 17 5,198 0.2 1,031 85,106 86 289 0.02 2NaturalGasN/A N/A N/A N/A N/AN/A N/A N/A N/A N/AProcessGases120 14 5,727 0.1 526 3,599 185 380 0.00 (21)RefineryGas2 6,792 933 0.0 140 5,197 3,256 1,597 (0.00) 445ResidualLiquid634 11 16,321 0.0 7,746 4,030 120 433 0.03 (12)Total 42,289 8,043 386,274 8 52,880 407,679 8,773 8,267 1.2 1,0441Values in parentheses represent an increase in emissions fora specific pollutant as a result of switching to natural gas.2Emission reductions and increases in dioxin/furans are reported in units of lb/year.

## 6 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 de veloped and used as the basi s 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. De tailed information about this database can be

found in other memoranda 1



## . All boilers that did not report burning solely natural gas were revi ewed and categorized

into one of three scenarios in order to a ssess the impacts of switc hing to natural gas:

A. The boiler or process heat er 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 natu ral 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 th at burn solely natural gas we re placed in Scenario A but there were not cost estimates prepared for these un its 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 natura l 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 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.

## 7 Each boiler and process heater in the questionn aire 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 pro cess heater not identified as firi ng natural gas, but located at a facility that had another combus tion unit firing natural gas was assigned to Scenario B. If another unit at the facility was combusting natura l gas, it was assumed that a natural gas line was available at the facility, so costs incurred for fu el switching the boiler or process heater would be to modify the on-site gas handling system to di rect gas to the boiler a nd modify the boiler or process heater combustor to fire natural gas. All the boilers and proce ss 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 f acility, 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-digi t NAICS level, sizes were grouped according to one of four categories: less th an 10 mmBtu/hr, between 10 and 100 mmBtu/hr, between 100 and 250 mmBtu/hr, and greater th an 250 mmBtu/hr; and th e 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 (refine ry gas or blends of refinery and natural gas), and Gas 2 (other process gase s) . For each group, an average design capacity and average annual hours of operation were calcula ted 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 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. 2 

## 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%.

## 8 3.2 Development of Cost Inputs and Factors

The same base costs and cost sources that were used for th e 2002 analysis for the vacated rule were also used in this analysis, but escala ted to 2008 costs. The equations used to calculate capital and annual costs are pr ovided in Appendix A-1. Input s 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 fu el switching to natural gas for five utility boilers at four differe nt sites. For the four utility boilers studied, different breakdowns, component groupings, a nd component names were used. Similar components were grouped together based on descri ptions provided and engineering judgment. The table also allocates components to the gas handling system, combustion equipment, or other (administrative, vendor representative, start up, 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 fo r each scenario. The average costs for gas handling systems, combustor modifications, and other administrative a nd 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 pipi ng 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 m iles 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 States 4 

## . The cost per foot of pipe wa s determined based on whether the

## 9 scenario would be in a city or a rural area. A co st 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 co st for city pipelines are due to greater construction costs to install pipeline s in smaller, more congested areas.

3.2.2 Total Annual Costs The total annual cost component s 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 - SO 2 

## 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) Tont o database for fuels

delivered to commercial a nd industrial facilities, 2008 5 

## The costs for distillate fuel and natural gas depend on whether the facility receiving the gas is an industri al or commercial fuel account, and the NAICS code groups discussed in Sect ion 3.1 were used to delineate whether the purchased fuel price would be i ndustrial or commercial. The prices of these fuels were converted to a dollars per million Btu ($/mmBtu) basis usi ng higher heating values (HHV) reported in EPA mandatory reporting rule for greenhous e gases (40 CFR Part 98 subpart C). 6 

## For distillate fuel
oil, the HHV for No. 2 fuel oil was used, for re sidual 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.

## 10 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/g allon 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 c ubic feet for ind. delivery = $9.32/MMBtu assuming 1.028 mmBtu per thousand scf heating value Process Gas cost = Free, assumed to be fl ared 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 base d on the average annual hours of operation for each group of units in the same NAICS, fuel, a nd size category. Any combustion unit that did not report an annual operating time was assume d to operate 8,400 hours per (i.e., two weeks down time per year). Further, a ll boilers and process heaters we re 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 averag e 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 ca lculate capital and annual costs are provided in Appendix A-1. Inputs for cost equati ons are summarized in Appendix A-2. It was assumed that boilers and proce ss 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 applie d to biomass units since other solid fuels are purchased fuels or fuels that woul d 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 landf ill is found in Appendix A-1. These costs are based on a solid waste tippi ng fee of $42.14 per ton, consistent with the waste disposal costs used in the control cost memorandum. 7

## 11 Natural gas fired units are one of the a ffected subcategories under the NESHAP for
Industrial, Commercial, and Inst itutional Boilers and Pr ocess 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 fo r new natural gas units. Natural gas units are required to conduct an annual tune-up to demonstr ate 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



## SO 2 

## 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 proc ess heaters assigned to each applicable group of common NAICS code s are presented in Appendix A-4. 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 EMISSION REDUCTION ANALYSES

Appendix A-6 presents the emission reducti ons 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, filterabl e 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 reduc tion when all fuel cate gories were factored.

Overall emissions of total mass dioxins/furan s increased as a resu lt of fuel switching.

Emission reductions were calculated on th e combustion unit leve l, not by NAICS subcategory. Baseline emission factors from the current fuels reported at each unit in the major

## 12 source boiler and process heater inventory were calculated for the baseline emissions analysis

and are discussed in another memorandum 8 

## . For this analysis, the average baseline emission factors developed for uncontrolled units firing on ly 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 a nd concentrations estimated from burning natural gas from the

baseline emission rates and concentrations esti mated from burning the existing fuel(s). To

calculate the annual emission re ductions resulting from fuel switching to natural gas, the
emission factors, which were available on a lb/mmB tu basis, were convert ed 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 oxyge n content of the exhaust at each unit in the inventory is needed in order to convert emission c oncentrations into an annual emission rate. The oxygen contents were approximated using other data sources for t ypical boiler exhausts, and the flowrate was estimated using the reported desi gn 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.

## 13 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 Reduc tions for Industrial/Commercial/Institutional Boilers and Process Heaters National Emissi on Standards for Hazardous Air Pollutants

. October, 2002.

3. Fay, James, et al, Massachus etts Institute of Technology. Feasibility and Cost of Converting Oil- and Coal-fired Utility Boilers to Interm ittent Use of Natural Gas

. December 1986.

4. U.S. Department of Energy. En ergy 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 Reporti ng Rule. 40 CFR Part 98. Table C-1 from SUBPART C OF PART 98—DEFAULT CO 2 EMISSION FACTORS AND HIGH HEAT VALUES FOR VARIOUS TYPES OF FUEL: http://www.epa.gov/climatechange/emissi ons/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 fo r Hazardous Air Pollutants . April 2010.

8. Gibson, G, ERG. Development of Baseline Emission Factors for Boilers and Process Heaters at Commercial, Industrial, an d 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 + TCI B + TCI C + TCI tune-up 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 (fraction of design capacity the boiler is estimated to operate), 0.9 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 (fraction of design capacity the boiler is estimated to operate), 0.9 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)
TCI tune-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 + TAC LF + TAC tune-up 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 Cost to Landfill Biomass Diverted from Fuel Usage (TAC LF ) is defined in Equation 4
TAC tune-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 = (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, (fraction of design capacity the boiler is estimated to operate), 0.9 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, (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 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 rule

# Appendix A-2: Cost and Emission Reduction Equation Inputs and Constants

Parameter Description Value Unit CF fs,a 

### Cost factor for fuel switching for scenario A (see App A-3) 

## $13.01 2008$/kW
CF fs,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 - L C1 

### Length of pipe needed for scenario C1 

## 500 ft
L C2 

### Length of pipe needed for scenario C2 

## 5,280 ft
L C3 

### Length of pipe needed for scenario C3 

## 52,800 ft CF pipe,C1 

### Cost per foot of pipe for scenario C1 

## $186 2008$/ft
CF pipe,C2 

### Cost per foot of pipe for scenario C2 

## $37 2008$/ft
CF pipe,C3 

### Cost per foot of pipe for scenario C3 

## $22 2008$/ft
TCI tune-up 

### Capital investment for a boiler tune-up 

## $6,477 2008$/unit

TAC tune-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 CF tipping 

### Tipping fee to dispose of biomass in a landfill 

## $42.14 2008$/ton

ρ air 

### 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 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 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 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 ($/kw) for Each SiteAppendix A-4: Summary of Total Capital Investment and Total Annual Costs from Fuel Switching to Natural GasTable 1 - Total Capital Investment, 2008$A B C1 C2 C3 C TotalTune-Up for GasUnits Total111 $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$76,584,907Total $1,062,034,024 $1,378,730,274 $173,791,808 $424,696,264 $289,445,103 $887,933,175 $28,654,248 $3,357,351,722NAICSTCIAppendix A-4: Summary of Total Capital Investment and Total Annual Costs from Fuel Switching to Natural GasTable 2 - Total Annual Costs, 2008$/yrA B C1 C2 C3 C TotalBiomass Divertedfrom Fuel Usageto LandfillTune-Up for GasUnits Efficiency Loss Total111 $66,610,976 $0 $0 $0 $0 $0 $0 $4,740 $4,184,839$70,800,555113 $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 $13,532,052,794NAICSTACTCI 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 $13,532,052,79 4 $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 Pro p osed Re g ulator y O p tion 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 4eFuel 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