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OAR Box 1865 

Prepped by Charmelle Mathews 

Document Number: 

105)IV-K-(A)-3 

Docket Number: 

A-83-27 

Printed 12/3/2008 9:15:33 AM Sheet 105 of 105 
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ENERGY AND ENVTOONMENTAL ANALYSIS, INC. 

1655 NORTH FORT MYER DR ARLINGTON, VIRGINIA 22209 

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REVISED IMPACTS OF ALTERNATIVE 

SULFUR DIOXIDE NEW SOURCE 

PERFORMANCE STANDARDS FOR INDUSTRIAL 

FOSSIL FUEL-FIRED BOILERS 

Prepared for: 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

Office of Air Quality Planning and Standards 

Research Triangle Park, North Carolina 27711 

Prepared by: 

ENERGY AND ENVIRONMENTAL ANALYSIS, INC. 

1655 North Fort Myer Drive, Suite 600. 

Arlington, Virginia 22209 

February 1987 
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This report was furnished to the U.S. Environmental Protection Agency by 

Energy and Environmental Analysis, Inc., Arlington, Virginia, in fulfillment 

of Contract Number 68-02-4202. The contents of this report are reproduced 

herein as received from the contractor. 

The opinions, findings, and conclusions expressed are those of the author 

and not necessarily those of the U.S. Environmental Protection Agency. 

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TABLE OF CONTENTS 

Page 

1. INTRODUCTION 1-1 

2. METHODOLOGY 2-1 

2.1 Analytical Approach 2-1 

2.2 Key Model ing Assumptions 2-2 

2.3 Evaluation Criteria 2-14 

References 2-16 

3. PROJECTED IMPACTS OF ALTERNATIVE S02 EMISSIONS STANDARDS 3-1 

3.1 Regulatory Baseline and Alternative SO2 

Emissions Standards 3-1 

3.2 Projected National Impacts of the Alternative SO2 

Emissions Standards 3-1 • 

3.3 Regional SO2 Emissions Forecasts 3-18 

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LIST OF TABLES 

Page 

2-1 Industrial Boiler Pollution Control Equipment Options in IFCAM . 2-3 

2-2 Projected Industrial Fossil Fuel Demand 2-5 

2-3 Crude Oil Price Forecasts 2-10 

2-4 Industrial Oil and Natural Gas Price Scenarios 2-11 

2-5 Projected Trends in Industrial Burnertip Prices in 

the Middle Atlantic Region 2-12 

3-1 Regulatory Baseline NSPS Assumptions 3-2 

3-2 Alternative SO2 NSPS Emissions Standards for New 

Industrial Fossil Fuel-Fired Boilers 3-3 

3-3 Projected Fuel Demand in 1990 for Large New Industrial 

Fossil Fuel-Fired Boilers 3-5 

3-4 Comparison of Total Projected SO2 Emissions in 1990 from 

New Large Industrial Fossil Fuel-Fired Boilers 3-7 

3-5 Comparisons of Projected Costs 3-10 

3-6 Projected Demand for Scrubbers 3-12 

3-7 Comparison of Projected PM Emissions in 1990 from 

New Large Industrial Fossil Fuel-Fired Boilers 3-13 

3-8 Comparison of IFCAM Projections 3-14 

3-9 Projected Regional SO2 Emissions in 1990 3-19 

3-10 Projected Regional SO2 Emissions in 1990 3-20 

3-11 Projected Regional S02 Emissions in 1990 3-21 

3-12 Projected Regional SO2 Emissions in 1990 3-22 

3-13 Projected Regional SO2 Emissions in 1990 3-23 

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LIST OF FIGURES 

Page 

1 Federal Regions of the United States 2-6 

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1. INTRODUCTION 

This report presents projected environmental, cost, and energy impacts of 

alternative sulfur dioxide (SO2) air emission standards for new industrial 

fossil fuel-fired boilers. These draft standards would supersede the emission 

regulations that currently exist in Subpart D of 40 CFR Part 60. The effects 

of the alternative SO2 emission standards are assessed in this report. The 

methodology used to examine environmental, cost, and fossil fuel results 

projected under current and alternative SO2 emission regulations also is 

discussed. 

For individual boilers, air emission regulations can play a significant 

role in determining boiler fuel choice and the levels of air emissions. Air 

emission regulations can result in measurable national and regional environmental, cost, and energy impacts, including changes in the types of fossil 

fuels combusted and changes in the level of air pollutant emissions generated 

by new industrial fossil fuel-fired boilers. 

The analysis of alternative regulations is designed to highlight potential 

environmental, cost, and energy impacts. These impacts are measured in terms 

of the projected change under current versus alternative air emission regulations. The analysis of environmental impacts focuses on changes in levels 

of air emissions. Cost impacts are evaluated in terms of incremental changes 

in the total annualized costs for boiler and pollution control equipment 

capital, operating, and fuel costs. Energy impacts are evaluated in terms of 

shifts in the demand between fuel types (e.g., coal or residual fuel oil 

versus natural gas). 

Current SO2 emission regulations serve as the base case, from which all 

impacts are measured. Briefly, SO2 emission control regulations in the base 

case for new industrial boilers are the current New Source Performance 

Standards (NSPS) for boilers with heat input capacity greater than 73 MW (250 

MMBtu/hr). Current SO2 emission regulations for all smaller boilers -- and for 

boilers larger than 73 MW (250 MMBtu/hr) heat input of more stringer than NSPS 

-- are State Implementation Plan regulations (SIP's). 

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'This analysis examines projected impacts in the fifth year following 

proposal of standards. It was assumed that the recommended standards would be 

proposed in 1985 and that the impact analysis should, therefore, focus on 

projected results for new industrial fossil fuel-fired boilers installed in 

the five-year period between 1986 and 1990.* The emissions and energy demand 

projections presented in this report represent annual estimates for calendar 

year 1990. 

This report addresses only fossil fuel (coal, oil and natural gas) 

consumption in large new industrial boilers. It does not analyze commercialinstitutional boilers or non-fossil fuel-fired steam generating units (i.e., 

wood or municipal solid waste combustion). 

The balance of this report is presented in two parts. Section 2 presents 

the modeling approach employed to analyze the alternative standards and 

describes key assumptions and inputs. The revised potential 1990 national and 

regional impacts for the alternative standards are summarized in Section 3. 

This report is an update of a report dated March 1985.** This update 

summarizes revised projected environmental, cost and energy impacts based on 

revised (lower) industrial fuel price forecasts. 

*In fact, the recommended standards were proposed on June 19, 1986 (51 FR 

22385). 

**Projected Impacts of Alternative Sulfur Dioxide New Source Performance Standards for Industrial Fossil Fuel-Fired Boilers. Energy and Environmental 

Analysis, Inc., Arlington, Virginia. Prepared for the U.S. Environmental 

Protection Agency, Office of Air Quality Planning and Standards. March 1985. 

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2. METHODOLOGY 

The methodology for assessing the environmental, cost, and energy impacts 

of the alternative air emission standards is described briefly in this section. 

The first part describes the model used to project the mix of industrial 

boiler fossil fuel demand, the level of air emissions, and the annualized cost 

of generating steam. The second part summarizes key modeling assumptions and 

model inputs used in this analysis. The third part briefly describes the 

criteria used to evaluate emission, cost, and energy impacts of alternative 

regulations. 

2.1 ANALYTICAL APPROACH 

This analysis is based upon results from the Industrial Fuel Choice 

Analysis Model (IFCAM), an energy demand model developed by Energy and Environmental Analysis, Inc. (EEA). In addition to generating fuel mix estimates, 

IFCAM projects levels of air emissions and steam generating costs. 

IFCAM is a disaggregated process engineering model; models of this type 

simulate the effects of specific policies on new and existing technical 

alternatives, including innovative boiler designs and new pollution control 

equipment. IFCAM is designed to assess the impact of several factors on fuel 

choice decisions in the industrial sector, including fuel prices, energy and 

environmental policies, and capital and annual operating and maintenance (O&M) 

costs of firing alternative fossil fuels. 

The U.S. Department of Energy (DOE) is the primary source for projections 

of overall industrial fossil fuel demand by region. IFCAM disaggregates DOE 

industrial fossil fuel demand forecasts into nine industrial subsectors. 

Energy use in each of these industrial subsectors then is divided into boiler 

and process heat applications. 

Industrial boiler fossil fuel use is subdivided further to reflect the 

amount of fuel that will be used in new and existing boilers of different 

sizes and capacity utilization rates. Existing boilers are classified 

according to the type of fuel they are designed to fire and whether they can 

be retrofitted to fire alternative fuels. Eight size classes and five annual 

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' capacity utilization rate categories are delineated for both new and existing 

boilers. 

Each new boiler is sited in an Air Quality Control Region (AQCR). New 

boilers are located within each AQCR according to historical siting patterns. 

Because State environmental regulations for existing and new boilers often 

vary by AQCR, IFCAM applies current regulations on an AQCR basis. These 

regulations are based on State air laws for existing fossil fuel-fired boilers. 

The boilers represented in IFCAM are fired by one of several types of 

fossil fuels: coal, distillate fuel oil, residual fuel oil, or natural gas. 

IFCAM provides a choice between nine coal types that vary by sulfur, ash, and 

Btu content. Additionally, four residual fuel oil types that vary by sulfur 

content are available. The price of each fuel type can vary by region. 

The pollution control equipment options available in IFCAM are presented 

in Table 2-1. For each fuel type (i.e., coal, oil, and gas), the least cost 

pollution control strategy that meets the alternative standard is calculated. 

The least cost strategy includes finding the lowest cost option in terms of 

the boiler, pollution control equipment, and annual fuel costs. 

Based on the characteristics of each combustor (e.g., size, operating 

rate, pollution control requirements), capital and operating costs are 

generated for each fuel type. The fuel type associated with the lowest 

after-tax present value (including expected fuel expenses and boiler and 

pollution control equipment capital and O&M costs) of the total cost of 

generating steam over the boiler's investment period is selected. 

2.2 KEY MODELING ASSUMPTIONS 

This section presents the approach used in this analysis to model 

variables that could affect significantly the mix of fossil fuels demanded by 

. industrial boiler owners.* These variables are: 

• Regional industrial fossil fuel demand projections 

• Energy policies 

• Fuel price forecasts 

• Environmental policies. 

*0ther assumptions are summarized in Reference 1. 

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TABLE 2-1. INDUSTRIAL BOILER POLLUTION CONTROL 

EQUIPMENT OPTIONS IN IFCAM 

Pollutant Technology 

S02 

PM 

NOv 

Flue gas desulfurization 

dual alkali3 

lime spray dryingb 

sodium 

Single mechanical collector 

Dual mechanical collector 

Side stream separator 

Electrostatic precipitator 

Fabric filter 

Combustion modification 

low excess air 

staged combustion air 

a Tray type scrubber. 

" Combined SO2/PM emissions control system; includes a fabric filter. 

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2.2.1 Regional Industrial Fossil Fuel Demand Projections 

DOE is the primary source of projections of total industrial fossil fuel 

demand. The rate of projected growth in industrial fossil fuel demand is a 

significant parameter because it determines, to a large extent, the expected 

demand for new industrial fossil fuel-fired boilers. 

DOE does not project regional estimates of fuel consumption in industrial 

boilers. DOE does project regional estimates of total industrial fossil fuel 

demand for heat and power using the Energy Information Administration's 

(ElA's) Intermediate Future Forecasting System (IFFS). IFFS includes an 

econometric industrial energy demand model, the Purchased Heat and Power 

System (PURHAPS).2>

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The EIA regional industrial fossil fuel demand forecasts are summarized 

in Table 2-2. The ten Federal regions are illustrated in Figure 1. These 

projections are assumed to remain the same for the regulatory baseline and 

alternative regulations examined in Section 3 because the cost impacts are not 

expected to be sufficiently high to alter total projected energy demand. 

The projections shown in Table 2-2 are a function of macroeconomic 

variable projections. For example, real growth in the Gross National Product 

between 1985 and 1990 was assumed to average 2.9 percent per year and real 

growth in manufacturing output between 1985 and 1990 was assumed to average 

3.3. percent per year. The Federal Reserve Board industrial production index 

was expected to increase at a rate of 3.7 percent annually between 1985 and 

1990.4 

Not all of the projected net increase in industrial fossil fuel demand 

shown in Table 2-2 is attributable to new industrial boilers. A significant 

portion of this net increase is attributable to new process heat equipment. 

2.2.2 Energy Policies 

Energy policies contained in the National Energy Act of 1978 and the 

Omnibus Reconciliation Act of 1981 are key modeling assumptions in this 

analysis. These bills contain sections relevant to industrial boiler fuel 

choice, including: 

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TABLE 2-2. PROJECTED INDUSTRIAL FOSSIL FUEL DEMAND3 

PJ (IO12 Btu) 

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Region 

1985 1990 1985 1990 

Refinery Refinery Industry" Industry0 

1. New England 

2. New York/New Jersey 

3. Middle Atlantic 

4. South Atlantic 

5. 

6. 

7. 

8. 

9. 

10. 

U.S 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

. Total 

0 

(0) 

48 

(43) 

62 

(59) 

46 

(44) 

107 

(101) 

509 

(482) 

26 

(25) 

34 

(32) 

127 

(120) 

33 

(31) 

992 

(937) 

0 

(0) 

43 

(41) 

57 

(54) 

43 

(41) 

99 

(94) 

473 

(448) 

25 

(24) 

32 

(30) 

117 

(111) 

30 

(28) 

919 

(871) 

207 

(196) 

512 

(485) 

946 

(897) 

1,615 

(1,531) 

2,339 

(2,217) 

2,915 

(2,763) 

628 

(595) 

557 

(528) 

733 

(695) 

442 

(419) 

10,894 

(10,326) 

224 

(212) 

541 

(513) 

1,017 

(964) 

1,728 

(1,638) 

2,499 

(2,369) 

3,180 

(3,014) 

668 

(633) 

627 

(594) 

817 

(774) 

510 

(483) 

11,811 

(11,194) 

a U.S. Department of Energy, Energy Information Administration. 1982 Annual 

Energy Outlook, Middle World Oil Price (Case A) . The regional distribution is 

unofficial and has not been reviewed by EIA. Sum of non-metallurgical coal, 

natural gas, distillate and residual fuel oil. Excludes petro-chemical 

feedstocks and natural gas consumed as lease and plant fuels. Includes total 

boiler and process heat fossil fuel demand. 

D Excludes fuel consumption in petroleum refineries. Includes construction, 

mining, agriculture, fishing, forestry, and other manufacturing sectors. 

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FIGURE 1 

Federal Regions of the United States 

REGION NAMES 

1. New England 

2 New Yoik/New Jeisey 

3 Middle Atlantic 

4 South Atlantic 

5 Midwest 

6. Southwest 

7 Cential 

d Noith Cential 

9 West 

10 Noitliwest 
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• ' The Energy Tax Act of 1978 (ETA) 

• The Economic Recovery Tax Act of 1981 (ERTA). 

The ETA provided several tax incentives for the use of coal and 

alternative fuels. Additional investment tax credits (ITC's) were granted for 

coal and alternative fuel commercial investments. Under the ETA, ITC's and 

accelerated depreciation alternatives are denied for oil and gas investments. 

The ETA authorized a 10 percent tax credit (in addition to the standard 

10 percent ITC) for coal and alternative fuel investments made between October 

1, 1978 and December 31, 1982, including investments in the following: 

• Boilers and other combustors that use coal or an alternative fuel. 

• Equipment to produce alternative fuels. 

• Pollution control equipment. 

• Equipment for handling and storage of alternative fuels. 

Because authorization for the additional ITC expired in 1982, this provision 

has not been modeled for this analysis of projected new industrial boiler 

installations from 1986 to 1990. 

In IFCAM, these provisions are modeled for the calculation of after-tax 

boiler and pollution control equipment capital cost cash flows. Investments 

in new industrial coal-fired boilers receive the standard 10 percent ITC and 

qualify for an accelerated depreciation method, whereas no ITC's and straight 

line depreciation are calculated for new industrial oil- and gas-fired boiler 

investments. 

The ERTA revised the depreciation schedules for capital investment and 

thus improved the tax incentives for new industrial boilers. The depreciation 

period for new coal-, oil- and natural gas-fired industrial boilers was 

reduced to five years. 

The Tax Equity and Fiscal Responsibility Act (TEFRA) of 1982 revised the 

Accelerated Cost Recovery System (ACRS) annual recovery percentages for 

five-year period recovery property acquired after 1985. TEFRA also reduced 

the basis for depreciation by 50 percent of the ITC taken when the regular ITC 

(10 percent for five-year recovery period property placed in service after 

1980) is selected. These TEFRA Federal tax code revisions are reflected in 

this analysis. They do not apply to new industrial oil and gas boiler invest2-7 
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ments because they are not permitted to be depreciated using the ACRS accelerated depreciation schedule and they do not qualify for the ITC. The TEFRA 

Federal tax code revisions do apply to new industrial coal boiler investments. 

The Tax Reform Act of 1986 has changed several of these key parameters. 

These changes have not been incorporated in this analysis because this analysis 

was initiated before this new tax legislation was passed by Congress. The Tax 

Reform Act of 1986: 

• Reduced the business Federal income tax rate. 

• Repealed the normal investment tax credit for property placed in 

service beginning January 1, 1986. 

t Modified the ACRS and changed the method of depreciation for 

property place in service in 1987 and later. 

Repeal of the investment tax credit does increase the after-tax costs of 

capital-intensive projects such as investments in new coal-fired boilers. 

These new Federal tax code revisions are not expected to significantly change 

the results presented in Section 3. 

In addition, provisions of the Powerplant and Industrial Fuel Use Act of 

1978, which prohibit the use of oil or natural gas in large new industrial 

boilers, are an available feature in IFCAM but currently are not utilized in 

the analysis of the potential impacts of the recommended NSPS. Industrial 

plants can apply to the U.S. Department of Energy for a permanent exemption 

from these restrictions. 

2.2.3 Fuel Price Forecasts 

Fuel choice decisions in IFCAM are based on selecting the alternative 

with the lowest total boiler and pollution control equipment after-tax net 

present value of capital, annual O&M and fuel expenses over a 15-year period. 

In this analysis, the fuel expenses are estimated based on projected regional 

delivered fuel prices from 1987 to the year 2001. 

Naturally there is uncertainty related to energy market conditions over 

the next fifteen years. Two forecasts of oil prices were developed in order 

to evaluate the sensitivity of IFCAM results (projected impacts of alternative 

NSPS) to this key exogenous assumption, industrial fuel price differences. 

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Table 2-3 presents the two crude oil price forecasts. Both forecasts are 

based on DOE's (Office of Policy, Planning and Analysis) WOIL forecasting 

model. EEA estimated regional industrial distillate and residual fuel oil and 

natural gas prices for both crude oil price projections.^ 

EEA developed sensitivity cases to reflect the uncertainty of how natural 

gas markets will respond to a market environment of lower oil prices. For 

each of the two oil price forecasts, EEA estimated two sets of industrial 

natural gas burnertip prices: 

• A "carriage" price (in response to FERC Order #436). 

• A traditional local distribution company (LDC) sales price. 

For the Low Oil Price Scenario (where competition with residual fuel oil will 

be most severe), EEA prepared sensitivity cases with respect to the degree of 

flexibility that the natural gas market participants will exercise in response 

to the lower oil prices. 

Table 2-4 shows that there are four distinct industrial natural gas price 

projections for the Low Oil Price Scenario and two distinct industrial natural 

gas price forecasts for the High Oil Price Scenario. Therefore, there are six 

new combinations of industrial fuel oil and natural gas price forecasts. The 

major trends in industrial burnertip prices between these six combinations are 

highlighted in Table 2-5 using the Middle Atlantic region as an example. 

In the Low Oil Price case, 0.8 percent sulfur residual fuel oil is priced 

to industrial customers at $2.70/MMBtu in 1990 and $3.71/MMBtu in 1995. As 

shown, natural gas prices in the carriage market are: 

• Competitive with residual fuel oil in the Flexible Market case 

through 1995. 

t At parity with resid in 1990 in the Rigid Market case and priced 

above resid in 1995. 

LDC gas prices for industrial customers are significantly higher than industrial 0.8 percent sulfur residual fuel oil prices in both cases. 

Industrial sales prices offered by local gas distribution companies 

(LDC's) reflect the continuation of the traditional utility rate structures in 

the gas industry prior to FERC Order 436. Burnertip gas prices to industrial 

customers of LDC's are much higher than in the carriage market due to the 

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TABLE 2-3. CRUDE OIL PRICE FORECASTS3 

(1985 $/bbl) 

Low oil 

price scenario 

26.76 

13.34 

14.47 

20.08 

High oil 

price scenario 

26.76 

21.16 

23.87 

27.02 

1985 actual 

1988 

1990 

1995 

2000 24.61 30.61 

2005 30.79 37.42 

a Average U.S. refiner acquisition cost of crude oil 

Analysis, Inc. Summer 1986. Reference 5. 

Energy and Environmental 

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TABLE 2-4. INDUSTRIAL OIL AND NATURAL GAS PRICE SCENARIOS 

LOW OIL PRICE SCENARIO 

• Distillate fuel oil prices 

• Residual fuel oil prices (0.3, 0.8, 1.6 and 3.0 percent sulfur) 

• Natural gas 

- flexible carriage market price 

- local distribution company price assuming the existence of a 

flexible carriage market 

- rigid carriage market price 

- local distribution company price assuming the existence of a rigid 

carriage market 

HIGH OIL PRICE SCENARIO 

• Distillate fuel oil prices 

• Residual fuel oil prices (0.3, 0.8, 1.6 and 3.0 percent sulfur) 

• Natural gas 

- carriage market price 

- local distribution company price 

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TABLE 2-5. PROJECTED TRENDS IN INDUSTRIAL BURNERTIP 

PRICES IN THE MIDDLE ATLANTIC REGION1 

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2.70 

2.54 

3.32 

3.71 

3.62 

4.47 

Low oil price with flexible gas market 

0.8% S residual oil 

Carriage market gas price 

LDC sales gas price 

Low oil price with gas market rigidity 

0.8% S residual oil 

Carriage market gas price 

LDC sales gas price 

High oil price 

0.8% S residual oil 4.39 4.96 

Carriage market gas price 4.18 4.74 

LDC sales gas price 4.61 5.91 

3 Reference 5. 

2.70 

2.73 

3.30 

3.71 

3.81 

4.53 

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I higher transmission and distribution margins. These higher margins: 

• Fully recover the costs of the transmission costs authorized in 

FERC rate-setting procedures. 

• Are applicable only to segments of the industrial sector (primarily 

high valued uses and applications not switchable to oil) which do 

not gain access to carriage. 

Thus, the willingness of natural gas pipeline and distribution companies to 

discount transmission margins on carriage transactions becomes a crucial factor 

in gas versus oil competition under low oil prices. 

The High Oil Price Scenario reflects a competitive outcome for gas which 

is very similar to the Low Oil Price/Flexible Gas Market case, although the 

overall price levels for gas and oil are significantly higher. Gas can be 

delivered to the industrial sector at prices competitive with residual fuel 

oil. 

IFCAM results from five of these six combinations of oil and natural gas 

price forecasts are presented in Section 3. IFCAM has not yet been run with 

the Low Oil Prices/local distribution company gas prices with flexible carriage 

market because these estimates are very similar to the Low Oil Prices/local 

distribution company gas prices with rigid carriage market (see Table 2-5). 

Only one set of projected industrial coal prices was used in this 

analysis. However, it is a recent forecast.** Therefore, the fuel price 

scenarios have different projected industrial distillate and residual fuel oil 

and natural gas prices but identical projected industrial coal prices. 

Alternative coal price projections are not expected to change the results 

which are summarized in Section 3. 

The industrial coal types in IFCAM have been defined by ICF Incorporated 

in terms of coal type (bituminous or subbituminous) and sulfur, ash, and Btu 

content. There are up to nine distinct coal types per region in IFCAM: six 

sulfur classes for bituminous coals and three sulfur classes for subbituminous 

coals. All nine coal types are not applicable for all ten Federal regions. 

2.2.4 Environmental Policies 

Environmental policies embodied in the 1970 Clean Air Act (CAA) and the 

subsequent 1977 amendments define the regulatory context for this analysis. 

The Act gave the EPA the authority to establish National Ambient Air Quality 

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, Standards (NAAQS) that would protect the health and welfare of the population. 

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There are currently NAAQS for six "criteria pollutants": sulfur oxides, PM, 

NOx, lead, carbon monoxide (CO), and ozone. Industrial sources are subject to 

two classes of environmental regulations adopted to ensure compliance with 

ambient air standards: State Implementation Plan (SIP's) and Nonattainment 

(NA)/Prevention of Significant Deterioration (PSD). The CAA gave the EPA the 

authority to promulgate NSPS regulations governing the emissions of pollutants 

from specific categories of newly constructed sources. Each new source must 

meet requirements of all of these programs. 

For purposes of this analysis, no attempt was made to predict the impact 

of NA, PSD, or local regulations not part of SIP's. Therefore, each new 

boiler is assumed to be subject to a SIP or NSPS, whichever may be more 

stringent. The SIP's in IFCAM are characteristic of those regulations for 

existing industrial fossil fuel-fired boilers. 

A set of SIP regulations reflecting the regional diversity of air emission 

limits has been compiled for use in IFCAM. These SIP's are identified by 

pollutant, fuel type, boiler size, and AQCR and are converted to pounds of 

pollutant per million Btu of fuel burned. The SIP file is current as of July 

1980 for particulate matter and nitrogen oxide emission standards. The SIP 

file has been updated to March 1983 for SO2 emission regulations. 

The CAA requires that SIP's include provisions designed to upgrade areas 

of air quality not in attainment with NAAQS. To the extent that nonattainment 

provisions are reflected in the SIP's, nonattainment-related SIP revisions are 

incorporated into the IFCAM SIP file. 

Because only a limited number of nonattainment SIP revisions are modeled 

in IFCAM, and PSD regulations have not been addressed, the stringency of local 

regulations may be understated. Consequently, the impact of the alternative 

emission regulations may be overstated because a number of boilers may be 

subject to more stringent local regulations than are reflected in IFCAM. 

2.3 EVALUATION CRITERIA 

Throughout the development of alternative emission regulations for new 

industrial boilers, a set of key output parameters has been considered to be 

particularly useful in comparing projected aggregate impacts of alternative 

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regulations. This set of criteria includes the following three parameters: 

• Level of emissions. 

• Cost of generating steam. 

• Coal and residual fuel oil demand. 

These criteria are used to evaluate impacts of the alternative standards for 

distinct boiler size classes and are described in this section. 

The level of SO2 emissions projected under alternative regulations is a 

primary criterion by which to evaluate these regulations. The level of 

emissions is function of both the regulatory scenario and the mix of fuels 

demanded. 

In addition, the effect of alternative regulations on the total expected 

cost of generating steam in new industrial boilers is evaluated. Steam costs 

include capital and operating costs for the boiler, capital and operating 

costs for any required pollution control equipment, and fuel costs. The cost 

impact of the alternative standards is the change from the base case in the 

total cost of generating steam. For this analysis, aggregate costs for the 

least-cost fuel types are presented on a before-tax annualized basis using a 10 

percent discount rate and a 15-year investment period. 

The potential for increase residual fuel oil and coal combustion in the 

industrial sector is also partly a function of environmental regulations. 

Proposed air emission standards may affect projected residual fuel oil and 

coal demand in new industrial boilers. 

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REFERENCES 

1. Description of the Industrial Fuel Choice Analysis Model. Energy and 

Environmental Analysis, Inc. Arlington, Virginia. Prepared for the U.S. 

Environmental Protection Agency, Office of Air Quality Planning and 

Standards. May 1985. 

2. 1982 Annual Energy Outlook. U.S. Department of Energy, Energy Information 

Administration. D0E/EIA-0383(82). April 1983. 

3. Supplement to the 1982 Annual Energy Outlook. U.S. Department of Energy, 

Energy Information Administration. D0E/EIA-0408(82). July 1983. 

4. Reference 2, p. 126; Reference 3, p. 53. 

5. Projections of Industrial Fuel Oil and Natural Gas Prices. Energy and 

Environmental Analysis, Inc. Arlington, Virginia. Prepared for the U.S. 

Environmental Protection Agency, Office of Air Quality Planning and 

Standards. October 1986. 

6. Memorandum from Ebert, C. (ICF, Inc.) to Shelby, M. (EPA). New Coal 

Prices for Industrial NSPS Analyses. July 31, 1986. 

2-16 
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3. PROJECTED IMPACTS OF ALTERNATIVE S02 EMISSION STANDARDS 

This section describes the regulatory baseline NSPS air emissions standards and alternative SOg emissions regulations for new industrial fossil 

fuel-fired boilers. Projected emissions, cost and energy demand effects of 

the alternative standards, relative to the regulatory baseline, are summarized. 

3.1 REGULATORY BASELINE AND ALTERNATIVE S02 EMISSIONS STANDARDS 

The regulatory baseline is represented by current and proposed air 

emissions standards: the current SO2 NSPS, the recently promulgated PM NSPS 

and SO2 and PM SIP's. Table 3-1 presents the current SO2 NSPS and the promulgated PM NSPS. New industrial boilers are assumed to be subject to a SIP if 

the SIP is more stringent than the applicable NSPS shown in this table. 

N 0X emissions regulations and pollution control costs were not considered 

in this analysis. EPA promulgated a revised N0X NSPS for new industrial steam 

generating units in November 1986 (51 FR 42769). It was assumed that the 

recently promulgated N0X NSPS would not significantly affect the expected 

impacts of alternative SO2 NSPS for new industrial oil and coal boilers. 

The alternative SO2 emissions standards are presented in Table 3-2. 

These alternatives are applicable for new industrial residual fuel oil and 

coal boilers larger than 29 MW (100 MMBtu/hr). The applicable regulation is 

either an emissions ceiling (i.e., alternative control level I) or a fixed 

percentage reduction (i.e., alternative control level III). 

Compliance with the alternative SO2 NSPS emission standards is achieved 

by burning a low sulfur fuel type (with an uncontrolled emission rate equal to 

or lower than the emissions ceiling in Table 3-2) or scrubbing a high sulfur 

fuel type. When scrubbing, the controlled SOg emission rate must remain lower 

than the ceiling presented in Table 3-2. 

3.2 PROJECTED NATIONAL IMPACTS OF THE ALTERNATIVE S02 EMISSIONS STANDARDS 

This section presents IFCAM projections of total SOg emissions, fuel 

demand by fuel type in 1990 from new industrial fossil fuel-fired boilers 

larger than 29 MW (100 MMBtu/hr) and installed between 1985 and 1990. This 

section also presents IFCAM projections of total capital and annualized costs 

3-1 
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TABLE 3-1. REGULATORY BASELINE NSPS ASSUMPTIONS 

ng/J (lb/MMBtu) 

Fuel type 

Natural gas 

Distillate fuel oil 

Residual fuel oil 

Coal 

Boiler size 

category 

MW (MMBtu/hr) 

<73 

>73 

<73 

>73 

<73 

>73 

<29 

29-73 

>73 

(<250) 

(>250) 

V A 

ro ro 

cn cn CD CD 

V A 

ro ro 

cn cn 

CD CD 

(<100) 

(100-250) 

(>250) 

344 

344 

516 

S02 

--

(0.8)3>

e 

SIP 

(0.8)a»

e 

SIP 

SIP 

(1.2)3»

d 

43 

43 

43 CVI CVJ CVJ CVJ 

PM 

(0.1)a '

e 

(0.1)3>

e 

SIP 

(0.1)3>

e 

SIP u 

(0.05)P'C 

(0.05)b 

3 Current NSPS (40 CFR Part 60, Subpart D for fossil fuel-fired steam 

generators). 

b Promulgated NSPS (51 FR 42769). 

c 86 ng/J (0.20 lb/MMBtu) of the annual capacity utilization rate is less than 

30 percent and construction commenced between June 19, 1984 and November 25, 

1986. Not directly applicable in this analysis because IFCAM does not select 

coal as a new boiler fuel type if the annual capacity utilization rate is less 

than 30 percent. 

" 30-day rolling average. 

e Not applicable in this analysis because new large industrial oil-fired 

boilers in IFCAM are assumed to be two packaged units (each less than 73 MW), 

not a single large field-erected unit. 

3-2 
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TABLE 3-2. ALTERNATIVE S02 NSPS EMISSIONS STANDARDS FOR NEW 

INDUSTRIAL FOSSIL FUEL-FIRED BOILERS 

Residual Fuel Oil Coal 

Boiler size 

Alternative category Ceiling Required Ceiling3 Required 

control (MMBtu/ (lb/ percentage (lb/ percentage 

level MW hr) ng/J MMBtu) reduction ng/J MMBtu) reduction 

Baseline 29-73 (100-250) --

>73 (>250) 

I >29 (>100) 344 (0.8) 

II >29 (>100) 1.29 (0.3) 

II III >29 (>100) 344 (0.8) 

516 

516 

516 

516 

(1.2) 

(1.2) 

(1.2) 

(1.2) 

— 

--

90° 

90b 

3 30-day rolling average. 

D Scrubbing is required. 

3-3 
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for these new industrial boiler investments. IFCAM projections for the 

regulatory baseline NSPS assumptions are compared with IFCAM forecasts for the 

three alternative SO2 NSPS emissions standards. 

3.2.1 Fuel Demand Impacts 

IFCAM projects that 604 new industrial fossil fuel-fired (coal, fuel oil, 

or natural gas) boilers, each larger than 29 MW (100 MMBtu/hr), will be 

installed during this period in the United States. They are expected to 

consume a total of 525 PJ (498 trillion Btu) in 1990. This projected "population" of large new industrial boilers is based on: 

t The U.S. Department of Energy's assumed rate of growth in total 

industrial fossil fuel demand (see Table 2-2). 

t Estimates of how much of this projected increase will be consumed 

in industrial boilers versus process heaters. 

• Estimates of the retirements of existing industrial boilers during 

the 1986-1990 period. 

• Estimates of the distribution of fuel demand in new large versus 

small industrial boilers. 

This forecast of new large industrial fossil fuel-fired boiler installations 

is held constant in this analysis and is not altered as a function of other 

input assumptions (e.g., projected oil and gas prices or alternative SO2 NSPS). 

IFCAM selects the compliance strategy for each of the 604 new large industrial fossil fuel-fired boilers by comparing the after-tax net present values 

of the projected fuel costs and boiler and pollution control equipment capital 

and annual non-fuel 0&M costs by fuel type: 

• Natural gas 

t Distillate fuel oil 

t Residual fuel oil (0.3, 0.8, 1.6 and 3.0 percent sulfur) 

• Coal (up to nine bituminous and subbituminous types). 

The alternative control levels affect the selection of the least-cost fuel type 

by altering the pollution control equipment requirements and costs. 

Table 3-3 presents the projected fossil fuel mix by fuel price scenario, 

SO2 NSPS alternative, and fuel type. The fuel mix is not fixed; it is a 

function of the fuel price scenario, the alternative SO2 NSPS, and many other 

model parameters (i.e., boiler and pollution control equipment cost estimates). 

3-4 
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Oil 

prices 

Low 

High 

TABLE 3-3. PROJECTED FUEL DEMAND IN 1990 FOR LARGE 

NEW INDUSTRIAL FOSSIL FUEL-FIRED BOILERS3 

PJ (101Z Btu) 

Gas 

prices 

Alternative 

control 

level 

Natural 

gas 

Residual 

fuel oil 

LDC/rigid 

Carriage/rigid 

Carriage/flexible 

LDC 

Carriage 

Baseline 

I 

II 

III 

Baseline 

I 

II 

III 

Baseline 

I 

II 

III 

Baseline 

I 

II 

III 

Baseline 

I 

II 

III 

80 

208 

208 

283 

196 

410 

525 

525 

406 

521 

525 

525 

266 

289 

299 

326 

246 

517 

525 

525 

(76) 

(197) 

(197) 

(268) 

(186) 

(389) 

(498) 

(498) 

(385) . 

(494) 

(498) 

(498) 

(253) 

(274) 

(283) 

(309) 

(233) 

(490) 

(498) 

(498) 

445 

317 

317 

242 

329 

115 

0 

0 

119 

4 

0 

0 

259 

236 

227 

199 

280 

8 

0 

0 

(422) 

(301) 

(301) 

(229) 

(312) 

(109) 

(0) 

(0) 

(113) 

(4) 

(0) 

(0) 

(246) 

(224) 

(215) 

(189) 

(265) 

(8) 

(0) 

(0) 

3 Each larger than 29 MW (100 MMBtu/hr) and installed between 1985 and 1990. 

Total fossil fuel demand in 1990 is 525 PJ (498 trillion Btu). 

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Coal'is not selected because the projected industrial natural gas and residual 

fuel oil prices are not large enough to offset the relatively high coal boiler 

and pollution control equipment capital and annual non-fuel O&M expenses. 

Table 3-3 presents results for five combinations of projected industrial 

fuel oil and natural gas prices. There is significant demand for residual fuel 

oil under each of the alternative control levels for the two sets of industrial 

fuel price projections which use estimates of local distribution company (LDC) 

natural gas prices*. In these cases, total residual fuel oil demand in 1990 

ranges from 199 PJ (189 trillion Btu) to 445 PJ (422 trillion Btu). 

However, there is little or no demand for residual fuel oil in 1990 in 

alternative control levels I through III for the three sets of industrial fuel 

price forecasts which assume the carriage market natural gas prices. In most 

regions, the industrial carriage market natural gas prices are expected to be 

lower than the projected industrial 0.8 percent sulfur residual fuel oil 

prices. As a result, when alternative control level I requires an SO2 emission 

ceiling of 344 ng/J (0.8 lb/MMBtu) for residual fuel oil, IFCAM usually selects 

natural gas as the least cost compliance option. 

Table 3-3 does indicate that natural gas is typically the least-cost compliance strategy in IFCAM in response to alternative SO2 emission standards 

for industrial boilers. This is predicated on the assumption that the Powerplant and Industrial Fuel Use Act of 1978 will not severely restrict the use of 

oil and natural gas in new large industrial boilers. For example, industrial 

plants can apply to the U.S. Department of Energy for a permanent exemption 

from these restrictions. 

3.2.2 Projected SO2 Emissions 

Table 3-4 summarizes the SO2 emissions forecasts for the regulatory 

baseline, three alternative control levels and five combinations of oil and 

natural gas price projections. The projected SO2 emissions reductions are 

significant (up to 99 percent). 

Some portion of the SO2 emissions reduction presented in Table 3-4 is due 

to the fact that the fuel mix is not held constant between the regulatory 

* Reference Section 2.2.3 for a description of LDC versus carriage market 

natural gas prices. 

3-6 
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I TABLE 3-4. COMPARISON OF TOTAL PROJECTED S02 EMISSIONS IN 

1990 FROM NEW LARGE INDUSTRIAL FOSSIL FUEL-FIRED BOILERS3 

Gg (IO3 short tons) 

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Oil Gas Alternative Control Level 

prices prices Baseline I II III 

Low 

High 

LDC/rigid 

Carriage/rigid 

Carriage/flexible 

LDC 

Carriage 

355 

(391) 

324 

(357) 

118 

(130) 

187 

(206) 

297 

(327) 

99 

(109) 

40 

(44) 

4 

(4) 

78 

(86) CVJ 

(3) 

40 

(49) 

b 

b 

b 

b 

33 

(36) 

b 

b 

33 

(36) 

b 

b 

b 

b 

28 

(31) 

b 

b 

3 Each larger than 29 MW (100 MMBtu/hr) and installed between 1985 and 1990. 

b Less than 500 Mg (550 short tons). 

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baseline and the three alternative control levels. Some of the new industrial 

boilers are projected to burn residual fuel oil under the regulatory baseline 

assumptions and select natural gas as the least-cost compliance strategy under 

the alternative control levels. For these units, the projected SO2 emission 

reduction is 99 percent. The remaining SO2 emissions reduction is accounted 

for by burning lower sulfur residual fuel oil types or scrubbing a high sulfur 

residual fuel oil type when high sulfur oil without a scrubber was selected 

under the regulatory baseline assumptions. 

The projections of SO2 emissions for the regulatory baseline range from 

118 Gg (130,000 short tons) to 355 Gg (391,000 short tons). This range exists 

because the fuel mix is unique for each of the five sets of fuel price projections (reference Table 3-3). For example, the baseline fuel mix is primarily 

residual fuel oil for the low oil prices with LDC natural gas prices. However, 

the baseline fuel mix is primarily natural gas for the low oil prices with 

flexible carriage market natural gas prices. 

The average residual fuel oil SO2 emission rates in the regulatory 

baseline IFCAM runs are about 860 ng/J (2 lb/MMBtu). This is determined by 

the assumed location of these new boilers and the associated local SIP's. 

Alternative SO2 emission standards of 344 ng/J (0.8 lb/MMBtu) and 130 ng/J (0.3 

lb/MMBtu), therefore, are expected to result in a significant SO2 emission 

reduction (with or without selecting natural gas as the least-cost compliance 

option when high sulfur residual fuel oil was chosen under the regulatory 

baseline assumptions). 

Table 3-4 shows that projected SO2 emissions are negligible for alternative control levels II and II with the three sets of carriage market natural 

gas price projections. In these scenarios, natural gas is the only fuel type 

(reference Table 3-3) and there is no projected demand for scrubbers or oil. 

Natural gas has a very small SO2 emission rate. 

3.2.3 Projected Cost Impacts 

The projected increase in total annualized costs is expected to range 

from $5 million to $173 million. The projected increases in total annualized 

costs represent: 

• Higher fuel prices associated with using lower sulfur content fuel 

types. 

3-8 
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t' The levelized capital and annual operating and maintenance costs of 

a FGD system. 

Table 3-5 shows that the total projected annualized cost increases for 

the low oil prices with the flexible carriage market natural gas prices 

are relatively low ($5 million). Alternative control levels I, II and II do 

not include demand for FGD systems; the only compliance strategy selected by 

IFCAM in these cases is natural gas. There is no expected difference in the 

total annualized cost increases between alternative control levels I, II and 

III because the compliance strategies are identical: all of the new industrial 

boilers are expected to burn natural gas because these natural gas prices are 

lower than the projected prices for 0.8 percent sulfur residual fuel oil. 

Similarly, there is no expected difference in the total annualized cost 

increases between alternative control levels I, II and III for the high oil 

prices with carriage market natural gas prices ($29 million) or for the low 

oil prices with rigid carriage market natural gas prices ($45 million). 

The range of total annualized cost increases, $5 million to $45 million, 

is a function of the fuel price projections. For the low oil prices with 

flexible carriage market natural gas prices, there is a small fuel price 

increase associated with selecting natural gas under alternative control level 

I when residual fuel oil was chosen under the regulatory baseline assumptions. 

For the high oil prices with carriage market natural gas prices, this 

difference between natural gas and residual fuel oil prices is larger. As a 

result, the total annualized cost increase is $29 million for the high oil 

prices with carriage market natural gas prices versus $5 million for the low 

oil prices with flexible carriage market natural gas prices. This difference 

between natural gas and residual fuel oil prices is even larger for the low 

oil prices with rigid carriage market natural gas prices and this leads to a 

$45 million total annualized cost increase. 

The low and high oil prices with LDC natural gas prices IFCAM results do 

show significant differences in the total annualized cost increases with 

respect to alternative control levels I, II and III. Table 3-6 summarizes the 

compliance strategies for new large industrial residual fuel oil-fired boilers. 

Scrubbers are not the primary compliance option selected in IFCAM for the 

regulatory baseline or alternative control levels I or II. FGD systems are the 

3-9 
P.35 

TABLE 3-5. COMPARISONS OF PROJECTED COSTS3 

(millions of 1985 dollars) 

Oil 

prices 

Gas 

prices 

Alternative 

control 

level 

Increase in 

Total total annualized Total 

annualized costs over the capital 

costs'3'

0 Baseline costs0 

Low 

High 

LDC/rigid 

Carriage/rigid 

Carriage/flexible 

LDC 

Carriage 

Baseline 

I 

II 

III 

Baseline 

I 

II 

III 

Baseline 

I 

II 

III 

Baseline 

I 

II 

III 

Baseline 

I 

II 

III 

2,363 

2,423 

2,460 

2,536 

2,343 

2,390 

2,388 

2,388 

2,850 

2,856 

2,855 

2,855 

2,896 

2,951 

2,985 

3,004 

2,329 

2,358 

2,358 

2,358 

60 

97 

173 

.. 

47 

45 

45 

6 

5 

5 

55 

89 

108 

29 

29 

29 

2,469 

2,456 

2,468 

2,663 

2,451 

2,437 

2,434 

2,434 

2,489 

2,485 

2,434 

2,434 

2,476 

2,476 

2,537 

2,629 

2,443 

2,434 

2,434 

2,434 

3 New industrial fossil fuel-fired boilers larger than 29 MW (100 MMBtu/hr) 

and installed between 1985 and 1990. 

b Capital costs x 0.13147 (a capital recovery factor based on a 10 percent 

interest rate and a 15-year period) plus annual non-fuel 0&M costs plus 

levelized fuel costs. 

c Includes total boiler and pollution control equipment expenses. 

3-10 
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only compliance option for residual fuel oil boilers for alternative control 

level III. 

The scenarios with LDC natural gas prices have higher projected total 

annualized cost increases ($55 million to $183 million) than the scenarios with 

carriage market natural gas prices ($5 million to $47 million) for two reasons: 

t Scrubbers are selected for the scenarios with LDC natural gas 

prices; scrubbers are not selected for the scenarios with carriage 

market natural gas prices. 

• The differences between natural gas and residual fuel oil prices 

are larger for the scenarios with LDC natural gas prices in comparison with the scenarios which are based on carriage market natural 

gas prices. 

3.2.4 Projected PM Emissions 

The alternative control levels are also expected to reduce projected PM 

emissions (beyond the reduction attributable to the recently promulgated PM 

NSPS) for two reasons: 

• There is a higher demand for natural gas under the alternative 

control levels versus the regulatory baseline and natural gas has a 

lower PM emissions rate than residual fuel oil. 

• The alternative control levels result in an increased use of 

scrubbers (which reduce PM emissions as well as reduce SO2 

emissions) or in an increased demand for low or very low sulfur 

residual fuel oil (which has a lower PM emissions rate than middle 

or high sulfur residual fuel oil). 

Table 3-7 summarizes the projections of PM emissions. 

3.2.5 Summarv of Projected National SO2 Emissions Reductions and Total 

Annualized Cost Increases 

Table 3-8 presents a comparison of projected national SO2 emissions 

reductions and total annualized cost increases for each of the five sets of 

industrial fuel price forecasts. National average cost-effectiveness ratios 

(total annualized cost increases divided by the total annual SO2 emissions 

reductions) are also included in this table. This table summarizes incremental 

changes in the projected annual SO2 emissions reductions, total annualized 

costs increases and incremental cost-effectiveness ratios. 

As noted in Table 3-7, the alternative control levels are expected to 

result in reductions in total PM emissions. This is not reflected in Table 

3-11 
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TABLE 3-6. PROJECTED DEMANC 

Alternative Total no. of 

Oil Gas control residual fuel 

prices prices level oil boilers3 

Low LDC Baseline NA 

I 383 

II 383 

III 223 

High LDC Baseline 308 

I 278 

II 266 

III 192 

FOR SCRUBBERS 

Total no. of 

scrubbers0 

16 

10 

19 

223 

27 

30 

87 

192 

3 New industrial boilers larger than 29 MW (100 MMBtu/hr) and 

between 1985 and 1990. 

D Subset of the total number of residual fuel 

scrubbers. 

3-12 

Scrubber liquid 

waste in 1990 

103 cubic meters 

590 

240 

740 

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1,211 ! 

1,751 | 

5,092 

8,167 1 

j 

installed 

oil boilers. All sodium 

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TABLE 3-7. COMPARISON OF TOTAL PROJECTED PM EMISSIONS IN 1990 FROM 

NEW LARGE INDUSTRIAL FOSSIL FUEL-FIRED BOILERS3 

Gg (IO3 short tons) 

Alternative control level 

Oil Gas 

prices prices Baseline I II III 

1 

1 

1 

H 

II 

fl 

Low 

High 

LDC/rigid 

Carriage/rigid 

Carriage/flexible 

LDC 

Carriage 

15 

(17) 

24 

(27) 

11 

(12) 

27 

(30) 

ro ro cn co 

10 

(11) 

5 

(6) 

3 

(3) 

10 

(12) 

3 

(3) 

lO CO 

CO CO 

3 

(3) 

7 

(8) 

3 

(3) 

10 

(H) 

3 

(3) 

3 

(3) 

12 

(13) 

3 

(3) 

3 Each larger than 29 MW (100 MMBtu/hr) and installed between 1985 and 1990. 

3-13 
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TABLE 3-8. COMPARISON OF IFCAM PROJECTIONS3 

Baseline vs. alternative 

control level I 

SO2 emission red., Gg 

(103 short tons) 

Tot. ann. cost increase, 

$1985 IO6 

Incremental C-E, 

1985 $/Mg 

(1985 $/short ton) 

Alternative control 

levels I vs. II 

SO2 emission red., Gg 

(IO3 short tons) 

Tot. ann. cost increase, 

$1985 IO6 

Incremental C-E, 

1985 $/Mg 

(1985 $/short ton) 

Alternative control 

levels II vs. Ill 

SO2 emission red., Gg 

(IO3 short tons) 

(rigid) 

low 

oil 

prices 

284 

(313) 

47 

165 

(150) 

40 

(44) 

0 

0 

(0) 

0 

(0) 

Carriage market 

natural gas prices 

(flexible) (rigid) 

low high 

oil oil 

prices 

294 

(324) 

29 

100 

(91) 

3 

(3) 

0 

0 

(0) 

0 

(0) 

prices 

114 

(126) 

5 

47 

(43) 

4 

(4) 

0 

0 

(0) 

0 

(0) 

LCD 

gas 

low 

oil 

natural 

prices 

high 

oil 

prices prices 

256 

(282) 

60 

234 

(212) 

54 

(60) 

37 

675 

(612) 

12 

(13) 

109 

(120) 

55 

503 

(456) 

45 

(50) 

35 

774 

(702) 

5 

(6) 

Tot. ann. cost increase, 

$1985 IO6 

Incremental C-E, 

1985 $/Mg 

(1985 $/short ton) 

76 19 

6,562 3,549 

(5,953) (3,220) 

3 Reference Tables 3-4 and 3-5. 

3-14 
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3-8*. The procedure for calculating incremental cost-effectiveness ratios in 

Table 3-8 is based on the assumptions that the PM emissions reductions are 

not considered and, because the projected total annualized cost increases are 

directly attributable to the alternative SO2 emissions standard (in the 

absence of a new PM emissions standard), the total annualized cost increases 

are comparable to the SO2 emissions reductions. The alternative would be to 

split the total annualized cost increases into two parts, one part attributable 

to the SO2 emissions reductions and the remainder attributable to the PM 

emissions reduction. In this manner, incremental cost-effectiveness ratios 

could be presented for SO2 and PM. This alternative was not adopted in this 

analysis. 

The incremental cost-effectiveness ratios which are summarized in Table 

3-8 are national averages. Individual boilers may have significantly higher 

or lower cost-effectiveness ratios. 

Table 3-8 shows that all of the annualized cost increases and almost all 

of the annual SO2 emission reductions are attributable to alternative control 

level I when the carriage market natural gas prices are used. There is some 

additional SOg emissions reductions without a total annualized cost increase 

between alternative control levels I and II using the carriage market natural 

gas prices. This is explained by observing that a few boilers burn 0.8 percent 

sulfur residual fuel oil under alternative control level I and select natural 

gas under alternative control level II with a miniscule increase in total 

annualized costs and a significant emission reduction. 

In these cases which used the carriage market natural gas prices, the 

incremental cost-effectiveness ratios are relatively low, ranging from zero to 

$165/Mg ($150/short ton). They are relatively low for two reasons. 

• The fuel mix is not held constant and many boilers select 

natural gas as the least-cost compliance option under the 

alternative control scenarios when residual fuel oil was 

selected under the baseline air emissions regulations assumptions. This resulted in a small fuel price increase and a 99 

percent SO2 emissions reduction. 

• Some boilers selected 1.6 or 3.0 percent sulfur residual fuel 

oil in order to comply with the regulatory baseline assumptions (depending upon local variability in SIP's) and burned 

0.8 percent sulfur residual fuel oil in order to comply with 

the alternative control level I requirements. For these 

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units, the incremental cost-effectiveness ratio is relatively 

low because the SO2 emission reduction is at least 50 percent 

and the fuel price increase is not very large for these oil 

price projections. 

Table 3-8 also includes national results for scenarios which used the LDC 

(non-carriage market) natural gas prices. The incremental cost-effectiveness 

ratios are higher for the LDC natural gas price results than they are for 

carriage market natural gas prices scenarios. Some boilers are expected to 

burn residual fuel oil under the regulatory baseline assumptions and to select 

natural gas as.the least-cost compliance options under one or more of the 

alternative control levels. The total annualized cost increase and the 

incremental cost-effectiveness ratio are larger for the LDC natural gas price 

scenarios because the LDC natural gas price projections are higher than the 

carriage market natural gas prices. 

There is no projected demand for scrubbers on new large industrial 

boilers using the carriage market natural gas prices. As shown in Table 3-6, 

there is demand for scrubbers for the LDC natural gas price scenarios. This 

represents another reason why the total annualized costs and incremental 

cost-effectiveness ratios are higher for the LDC natural gas price cases in 

comparison with the carriage market natural gas prices. 

For the carriage market natural gas price scenarios, all of the annual 

fuel demand in 1990 is expected to be natural gas for alternative control 

level II (reference Table 3-3). As a result, there is no additional national 

SO2 emissions reductions and no incremental national total annualized cost 

increase between alternative control levels II and III. 

Alternative control levels II and III are similar. The alternative 

control level II SO2 emission standard for residual fuel oil combustion in 

large new boilers is 129 ng/J (0.3 lb/MMBtu). The comparable emission standard 

for alternative control level III is 90 percent SO2 emissions reduction with a 

ceiling of 344 ng/J (0.8 lb/MMBtu). When alternative control level III and 

the LDC natural gas prices are selected as IFCAM input assumptions, from 54 to 

62 percent of the fuel mix in large new industrial boilers is natural gas as 

the least-cost compliance strategy and the remainder choose 90 percent SO2 

emissions removal of the highest sulfur residual fuel oil type in IFCAM, 3.0 

percent sulfur. In this analysis, alternative control level III does not 

3-16 
I 

I 

I 

I 

I 

II 

II 

fl 

II 

II 

I 

I 

reduce SO2 emissions for residual fuel oil boilers in comparison with alternative control level II because 90 percent SO2 emissions reduction for a 3.0 

percent sulfur residual fuel oil and a 129 ng/J (0.3 lb/MMBtu) SO2 emissions 

ceiling have practically the same controlled annual emissions rates. However, 

residual fuel oil boilers under alternative control levels II and III are 

subject to an increase in total annualized costs. This is because the fuel 

price differential between high sulfur and 0.3 percent sulfur residual fuel 

oil is smaller than the annualized cost of scrubbing high sulfur residual fuel 

oil. In this circumstance, the incremental cost-effectiveness ratio is very 

large, an annualized cost increase divided by a near-zero incremental annual 

SO2 emission reduction. 

Table 3-8 shows that the incremental annual SO2 emission reduction 

projections for alternative control levels II v. Ill ranges from 5 to 12 Gg 

(6,000-13,000 short tons). All of the projected incremental SO2 emission 

reduction is attributable to an increase in natural gas demand (reference Table 

3-3). The incremental total annualized cost increase ranges from $19 to 76 

million. The incremental cost-effectiveness ratios range from $3,549 to 

6,562/Mg ($3,220-5,953/short ton); these are weighted averages of very large 

incremental cost-effectiveness ratios for the residual fuel oil boilers under 

alternative control levels II and III (which experience significant cost 

increases but no emission reductions) and smaller incremental cost-effectiveness ratios for those boilers which chose to burn a ^ery low sulfur 

residual fuel oil under alternative control level II and natural gas under 

alternative control level III. 

This analysis does not include estimates of the impacts of alternative 

air emissions standards for coal combustion because coal does not "compete" in 

any of these scenarios according to the least-cost logic in IFCAM. This 

analysis does cover a wide range of regulatory options for oil combustion 

under the LDC natural gas price assumptions. These IFCAM run results are 

relevant only for alternative control I under the carriage market natural gas 

price assumptions because there are no estimates of the incremental cost-effectiveness ratios in Table 3-8 for alternative control levels I versus II or II 

versus III; there is no expected national impact of alternative control levels 

3-17 
I 

I 

I 

I 

II 

II 

H 

II 

I 

I 

I 

I 

1 

II ar III because natural gas dominates the fuel type selection under alternative control level I. 

New, large industrial boilers are more likely to face carriage market 

natural gas prices than conventional LDC tariffs. This is because the new, 

large boilers are more likely to be purchased by relatively large companies who 

tend: 

• To be more sensitive to energy costs 

t To have the leverage to negotiate with producers, pipelines and 

distributors for lower rates 

In addition, since these new boilers are assumed to be dual-fired, their 

fuel switching cost is negligible. Hence, industrial users are likely to 

switch quickly in these boilers. In addition, these boilers meet the prerequisite condition in most current distribution company carriage programs that 

only dual-fired capacity is eligible for carriage rates. 

3.3 REGIONAL S02 EMISSIONS FORECASTS 

IFCAM projects large new industrial fossil fuel-fired boiler SO2 emissions 

by Federal region. Tables 3-9 through 3-13 present the regional SO2 emissions 

forecasts for the regulatory baseline and the three alternative control levels. 

3-18 
P.44 

I 

I 

I 

I 

II 

I 

II 

I 

II 

H 

II 

I 

I 

I 

TABLE 3-9. PROJECTED REGIONAL S02 EMISSIONS IN 19903 

Gg (IO3 short tons) 

Low oil prices with flexible carriage market 

natural gas prices 

Federal region 

1. New England 

2. New York/New Jersey 

3. Middle Atlantic 

4. South Atlantic 

5. Midwest 

6. Southwest 

7. Central 

8. North Central 

9. West 

10. Northwest 

U.S. 

Regulatory 

baseline 

1.7 (1.9) 

4.0 (4.4) 

20.9 (23.0) 

39.6 (43.6) 

55.8 (61.5) 

135.9 (149.8) 

19.8 (21.8) 

12.4 (13.7) 

5.6 (6.2) 

0.9 (1.0) 

296.6 (327.0) 

Alternative control level 

I II & III 

(b) 

b (b) 

b (b) 

b Xki 

3.1 (3.4) 

(b) (b) 

1.5 (1.7) (b) (b) 

(b) (b) 

b 

b 

b 

b 

(b) 

(b) 

(b) 

(b) 

(b) 

(b) 

(b) 

(b) 

(b) 

(b) 

(b) 

(b) 

(b) (b) 

1.5 (1.6) (b) (b) 

ihl ihl 

0.1 (0.1) 

3 New industrial fossil fuel-fired boilers installed between 1985 and 1990 and 

larger than 29 MW (100 MMBtu/hr). 

b Less than 50 Mg (55 short tons). The projected SO2 emissions are relatively 

low because natural gas is the only fuel type selected. 

3-19 
P.45 

1 

1 

1 

1 

I 

1 

II 

H 

1 

II 

U 

1 

1 

1 

1 

• • , 

TABLE 3-

Federal region 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

New England 

10. 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

U.S. 

PROJECTED REGIONAL S02 EMISSIONS IN 19903 

Gg (IO3 short tons) 

Low oi prices 

Regulatory 

baseline 

3.2 

4.5 

22.2 

53.1 

55.8 

145.1 

20.6 

12.4 

5.6 

0.9 

323.4 

(3.5) 

(5.0) 

(24.5) 

(58.5) 

(61.5) 

(160.0) 

(22.7) 

(13.7) 

(6.2) 

(1.0) 

(356.5) 

with rigid carriage 

natural gas prices 

Alternative 

I 

2.3 (2.5) 

2.5 (2.8) 

10.7 (11.8) 

22.7 (25.0) 

b (b) 

b (b) 

b (b) 

b (b) 

1.5 (1.6) 

b ibl 

39.6 (43.7) 

market 

control level 

II & III 

i 

1 

b (b) 

b (b) 

b (b) 

b (b) 

b (b) 

b (b) 

b (b) 

b (b) 

b (b) 

b Ibl 

0.1 (0.1) 

I 

I 

I 

I 

3 New industrial fossil fuel-fired boilers installed between 1985 and 1990 and 

larger than 29 MW (100 MMBtu/hr). 

b Less than 50 Mg (55 short tons). The projected SO2 emissions are relatively 

low because natural gas is the only fuel type selected. 

3-20 
P.46 

1 

1 

1 

1 

1 

V 

1 

1 

II 

u 

1 

1 

1 

1 

1 

1 

1 

1 

1 

-' TABLE 3-11. 

Federal region 

1. New England 

2. New York/New Jersey 

3. Middle Atlantic 

4. South Atlantic 

5. Midwest 

6. Southwest 

7. Central 

8. North Central 

9. West 

10. Northwest 

U.S. 

3 New industrial fossil 

larger than 29 MW (100 1 

b Less than 50 Mg (55 s 

low because natural gas 

PROJECTED REGIONAL 

Gg (IO3 short 

Low oil 

Regulatory 

baseline 

3.4 

(3.7) 

5.9 

(6.5) 

25.6 

(28.2) 

53.5 

(59.0) 

65.0 

(71.6) 

145.1 

(159.9) 

20.9 

(23.0) 

12.4 

(13.7) 

11.2 

(12.4) 

12.0 

(13.2) 

345.9 

(391.2) 

S02 EMISSIONS IN 19903 

tons) 

i 

prices with LDC natural gas prices 

fuel-fired boilers i 

WIBtu/hr). 

lort tons). The 

is the only fuel 

3 

Alternat 

I 

2.4 

(2.7) 

3.9 

(4.3) 

13.8 

15.2) 

24.6 

(27.1) 

28.7 

(31.6) 

b 

(b) 

7.3 

(8.0) 

b 

(b) 

6.8 

(7.5) 

11.5 

(12.7) 

99.0 

(109.1) 

nstalled between 

ive control level 

II III 

1.1 

(1.2) 

2.1 

(2.3) 

6.4 

(7.1) 

10.0 

(11.0) 

12.1 

(13.3) 

b 

(b) 

2.9 

(3.2) 

b 

(b) 

4.8 

(5.3) 

4.7 

(5.2) 

44.2 

(48.7) 

1985 and 

projected SOg emissions are re 

type selected. 

-21 

i.o ! 

(i.i) ! 

2.0 

(2.2) 

5.9 

(6.5) ; 

9.3 

(10.3) 

10.3 

(11.3) 

b 

(b) 

1.3 

(1.4) 

b 

(b) 

1.3 

(1.4) 

1.7 

(1-9) 

32.7 

(36.1) 

1990 and 

latively 

< 
P.47 

« -. TABLE 3-12. PROJECTED REGIONAL S02 EMISSIONS IN 19903 

Gg (IO3 short tons) 

Federal region 

1. New England 

2. New York/New Jersey 

3. Middle Atlantic 

4. South Atlantic 

5. Midwest 

6. Southwest 

7. Central 

8. North Central 

9. West 

10. Northwest 

U.S. 

H" igh oil prices 

natural 

Regulatory 

baseline 

1.7 

4.0 

20.9 

16.0 

55.8 

b 

12.3 

1.8 

5.3 

b 

117.8 

(1.9) 

(4.4) 

(23.0) 

(17.6) 

(61.5) 

(b) 

(13.6) 

(2.0) 

(5.8) 

Ibl 

(129.9) 

with 

gas 

carriage 

prices 

Alternative 

I 

b 

1. 

b 

b 

b 

b 

b 

1. 

b 

b 

3. 

(b) 

5 (1.7) 

(b) 

(b) 

(b) 

(b) 

(b) 

8 (2.0) 

(b) 

ibl 

4 (3.8) 

market 

control level 

II & III 

b (b) 

b (b) 

b (b) 

b (b) 

b (b) 

b (b) 

b (b) 

b (b) 

b (b) 

b Ibl 

0.1 (0.1) 

3 New industrial fossil fuel-fired boilers installed between 1985 and 1990 and 

larger than 29 MW (100 MMBtu/hr). 

b Less than 50 Mg (55 short tons). The projected SO2 emissions are relatively 

low because natural gas is the only fuel type selected. 

3-22 
P.48 

TABLE 3-13. PROJECTED REGIONAL S02 EMISSIONS IN 19903 

Gg (IO3 short tons) 

Federal region 

1. New England 

2. New York/New Jersey 

3. Middle Atlantic 

4. South Atlantic 

5. Midwest 

6. Southwest 

7. Central 

8. North Central 

9: West 

10. Northwest 

U.S. 

Hioh oil prices 

Regulatory 

baseline 

3.4 

(3.7) 

6.3 

(6.9) 

26.2 

(28.9) 

56.1 

(61.8) 

65.4 

(72.1) 

b 

(b) 

20.6 

(22.7) 

b 

(b) 

7.9 

(8.7) 

0.9 

(1.0) 

186.8 

(205.9) 

with LDC natural gas or 

Alternat 

I 

2.4 

(2.7) 

4.3 

(4.7) 

14.3 

(15.8) 

24.6 

(27.1) 

28.9 

(31.9) 

b 

(b) 

b 

( b ) 

b 

(b) 

3.3 

(3.6) 

b 

ibl 

78.0 

(86.0) 

ices 

ive control level 

II III 

1.2 

(1.3) 

2.2 

(2.4) 

6.6 

(7.3) 

10.3 

(11.4) 

12.5 

(13.8) 

b 

(b) 

b 

(b) 

b 

(b) 

b 

(b) 

b 

ibl 

32.9 

(36.3) 

1.1 

(1.2) 

2.1 

(2.3) 

5.9 

(6.5) 

9.1 

(10.0) 

9.3 

(10.3) 

b 

(b) 

b 

(b) 

b 

(b) 

b 

(b) 

b 

ibl 

27.7 

(30.5) 

3 New industrial fossil fuel-fired boilers installed between 1985 and 1990 and 

larger than 29 MW (100 MMBtu/hr). 

b Less than 50 Mg (55 short tons). The projected SO2 emissions are relatively 

low because natural gas is the only fuel type selected. 

3-23