P.1 

OAR Box 1865 

Prepped by Charmelle Mathews 

Document Number: 

196) FR 6-19-1986 

Docket Number: 

A-83-27 

Printed 12/3/2008 3:22:25 PM Sheet 196 of 198 
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I 

A ~<? 3 ~ A 1 

Thursday * P * /V> 

June 19, 1986 

Part II 

Environmental 

Protection Agency 

40 CFR Part 60 

Air Pollution; Standards of Performance 

for New Stationary Sources, IndustrialCommercial-Institutional Steam 

Generating Units 
P.3_ 

22384 Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 

ENVIRONMENTAL PTOTECTtOM 

AGENCY 

40 CFR Part 60 

[AD-FRL-2987-6] 

Air Pollution; Standards oi 

Performance for Nero Stationary 

Sources; Industrial-CommercialInstftutiortal Steam. Generating Units 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule and notice of 

public hearing. 

SUMMARY: This proposal would amend 

Subpart Db of 40 CFR Part 60 to add 

standards limiting emissions of sulfur 

dioxide (SO2} and particulate matter 

(PM) from new, modified or 

reconstructed industrial-commercialinstitutional steam generating units. The 

proposed standards would apply to new, 

modified, and reconstructed industrialcommercial-institutional steam 

generating units capable of combusting 

more than 29 MW (100 million Btu/hour) 

heat input. 

Subpart Db, which includes emission 

standards for nitrogen oxides (NO,) and 

PM, was proposed on June 19,1984 (49 

FR 25102) for industrial-commercialinstitutional steam generating units. At 

that time, standards for SO2 emissions 

and for PM emissions from oil-fired 

industrial-commercial-institutional 

steam generating units were still under 

development. 

Electric utility steam generating units 

larger than 73 MW (250 million Btu/ 

hour) heat input capacity would not be 

covered by the proposed standards. 

They would continue to be subject to 

separate standards under 40 CFR Part 

60, Subpart Da. 

The proposed standards implement 

Section 111 of the Clean Air Act and. are 

based on the determination that 

emissions from industrial-commercialinstitutional steam generating units 

cause, or contribute significantly to, air 

pollution which may reasonably be 

anticipated to endanger public health or 

welfare. The intent is to require new, 

modified, and reconstructed industrialcommercial-institutional steam 

generating units to control emissions to 

the level achievable by the best 

demonstrated technological system of 

continuous emission reduction, 

considering costs, nonair quality health, 

and environmental and energy impacts. 

DATES; Comments. Comments must be 

received on or before September 2,1986. 

Public Hearing. If anyone requests to 

speak at a public hearing by July 10, 

1986, a public hearing will be held on 

August 4,1986 beginning at 10:00 a.m. 

Persons interested in attending the 

hearing should call Ms. Shelby Journigan 

at (919) 541-5578 to verify that a hearing 

will be held. 

Request to Speak at Hearing. Persons 

wishing to present oral testimony must 

request to speak at the public hearing by 

July 10,1986. 

Incorporation by Reference. The 

incorporation by reference of certain 

publications in these standards will be 

approved by the Director of the Federal 

Register as of the date of publication of 

the final rule. 

ADDRESSES: Comments. Comments 

should be submitted (in duplicate if 

possible) to: Central Docket Section 

(LE-131), Attention Docket Number A83-27, U.S. Environmental Protection 

Agency, 401 M Street SW, Washington, 

DC 20460. 

Public Hearing. If anyone requests a 

public hearing, it will be held at EPA's 

Office of Administration Auditorium, 

Research Triangle Park, North Carolina. 

Persons interested in attending the 

hearing or wishing to present oral 

testimony should notify Ms. Shelby 

Journigan, Standards Development 

Branch (MD-13), U.S. Environmental 

Protection Agency, Research Triangle 

Park, North Carolina 27711, telephone 

number (919) 541-5578. 

Background Information Documents. 

The background information documents 

(BID's) for the proposed standards 

consist of nine documents. See 

SUPPLEMENTARY INFORMATION for a 

listing of these documents. Anyone 

wishing to review the BID's should 

contact their respective trade 

association. 

Docket. Docket Number A-83-27, 

containing supporting information used 

in developing the proposed standards, is 

available for public inspection and 

copying between 8:00 a.m. and 4:00 p.m., 

Monday through Friday, at EPA's 

Central Docket Section, West Tower 

Lobby, Gallery 1, Waterside Mall, 401 M 

Street SW, Washington, DC 20460. A 

reasonable fee may be charged for 

copying. 

FQR FURTHER INFORMATION CONTACT: 

Mr. Fred Porter or Ms. Dianne Byrne, 

Standards Development Branch, 

Emission Standards and Engineering 

Division (MD-13), U.S. Environmental 

Protection Agency, Research Triangle 

Park, North Carolina 27711, telephone 

number (919) 541-5578. 

SUPPLEMENTARY INFORMATION: 

Background Information Documents 

The background information 

documents (BID's) for the proposed 

standards consist of nine documents as 

follows: 

1. Fossil Fuel Fired Industrial 

Boilers—Background Information, 

Volumes 1 and 2 (EPA-450/3-82-006a 

and b, March 1982). 

2. Nonfossil Fuel Fired Industrial 

Boilers—Background Information (EPA450/3-82-007, March 1982). 

3. Industrial Boiler SO2 Technology 

Update Report (EPA-450/3-85-009, July 

1984). 

4. Fluidized Bed Combustion: 

Effectiveness as an SO2 Control 

Technology for Industrial Boilers (EPA450/3-85-010, September 1984). 

5. Industrial Boiler SO2 Cost Report 

(EPA-450/3-85-011, November 1984). 

6. Projected Impacts of Alternative 

Sulfur Dioxide New Source Performance 

Standards for Industrial Fossil FuelFired Boilers (EPA-45013-86-007, March 

1985). 

7. An Analysis of the Costs and Cost 

Effectiveness of SO2 Control for Mixed 

Fuel-Fired Steam Generating Units 

(EPA-450/3-86-001, January 1986). 

8. An Analysis of the Costs and Cost 

Effectiveness of Allowing SO2 Emission 

Credits for Cogeneration Systems (EPA450/3-85-030, December 1985). 

9. Summary of Regulatory Analysis: 

New Source Performance Standards for 

Industrial-Commercial-Institutional 

Steam Generating Units of Greater than 

100 Million Btu/hour Heat Input 

Capacity (EPA-450/3-86-005, June 1986). 

These reports are being provided to 

industry trade associations. Because of 

the number of volumes involved and the 

associated printing and distribution 

costs, only a limited number of sets was 

printed. The trade associations have, 

therefore, agreed to allow member 

groups access to their document sets. 

Anyone wishing to review the BID's 

should contact their representative trade 

association. If the trade association does 

not have access to the BID's. a set will 

be provided to the association for the 

use of their membership. 

A limited number of volumes of 

documents 1 and 2 above are available 

through the National Technical 

Information Service, U.S. Department of 

Commerce, Springfield,' Virginia 22161, 

telephone number (703) 487-4650. The 

price of the three-volume set is $28.00. 

Preamble Outline 

I. Introduction 

A. New Source Performance Standards— 

General 

B. NSPS Decision Scheme 

C. Overview of This Preamble 

II. Summary of the Standards 

A. Source Category To Be Regulated 

B. Pollutants To Be Regulated 

C. Best Demonstrated Technology 
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Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 22385 

D. Format for the Standards 

E. Actual Standards 

F. Performance Testing and Monitoring 

Requirements 

G. Reporting and Recordkeeping 

III. Impacts of the Standards 

A. Air 

B. Water and Solid Waste 

C. Energy 

D. Control Costs 

E. Economic Effects 

IV. Solicitation of Public Comment 

A. Energy Price Scenarios 

B. Exemptions From Percent Reduction 

Requirements 

V. Rationale 

A. Selection of Source Category 

B. Selection of Pollutants, Fuels, and 

Affected Facilities 

C. Selection of Best System of Continuous 

Sulfur Dioxide Emission Reduction 

D. Selection of Best System of Particulate 

Matter Emission Reduction 

E. Modification and Reconstruction 

Provisions 

F. Performance Test Methods and 

Monitoring Requirements 

G. Reporting and Recordkeeping 

Requirements 

VI. Administrative Requirements 

A. Public Hearing 

B. Docket 

C. Clean Air Act Procedural Requirements 

D. Office of Management and Budget 

Reviews 

E. Regulatory Flexibility Act Compliance 

I. Introduction 

A. New Source Performance 

Standards—General 

New source performance standards 

(NSPS or standards) implement Section 

111 of the Clean Air Act. The NSPS are 

issued for categories of sources which 

cause, or contribute significantly to, air 

pollution which may reasonably be 

anticipated to endanger public health or 

welfare. They apply to new stationary 

sources of emissions; i.e., sources whose 

construction, reconstruction, or 

modification begins after a standard for 

them is proposed. 

An NSPS requires these sources to 

control emissions to the level achievable 

by the best system of continuous 

emission reduction, considering costs. 

B. NSPS Decision Scheme 

An NSPS is the product of a series of 

decisions related to certain key 

elements for the source category being 

considered for regulation. The elements 

identified in this "decision scheme" are 

generally the following: 

1. Source category to be regulated— 

usually an entire industry but can be a 

process or group of processes within an 

industry. 

2. Pollutant(s) to be regulated—the 

particular substance(s) emitted by the 

source that the standard will control. 

3. Best system of continuous emission 

reduction—the technology on which the 

standards will be based; i.e., 

. . . application of the best technological 

system of continuous emission reduction 

which (taking into consideration the cost of 

achieving such emission reduction, and any 

nonair quality health and environmental 

impacts and energy requirements) the 

Administrator determines has been 

adequately demonstrated, [section 111(a)(1)]. 

4. Affected facility—the pieces or 

groups of equipment that comprise the 

sources to which the standards will 

apply. 

5. Emission points to be regulated— 

within the affected facility, the specific 

physical location emitting pollutants 

(e.g., vents, stacks, and equipment 

leaks). 

6. Format for the standards—the form 

in which the standards are expressed; 

i.e., as a percent reduction in emissions, 

as pollutant concentrations, or as 

equipment standards. 

• 7. Actual standards—based on what 

the best demonstrated technology can 

achieve, the maximum permissible 

emissions-. 

Note.—In general, standards do not require 

that a specific technology be used to achieve 

them. The source owner/operator may select 

the method for achieving the pollution 

control required. 

8. Other possible considerations—In 

addition, NSPS often include: standards 

for visible emissions, modification/ 

reconstruction considerations, 

monitoring requirements, performance 

test methods, and reporting and 

recordkeeping requirements. 

C. Overview of This Preamble 

This preamble will: 

1. Summarize the important features 

of this NSPS by discussing the 

conclusions reached with respect to 

each of the elements in the decision 

scheme. 

2. Describe the environmental, energy, 

and economic impacts of this NSPS. 

3. Present a rationale for each of the 

decisions in the decision scheme. 

4. Present a regulatory impact 

analysis. 

5. Discuss administrative 

requirements relevant to this action. 

II. Summary of the Standards 

A. Source Category To Be Regulated 

The proposed standards for SO2 

would apply to industrial-commercialinstitutional steam generating units with 

heat input capacities greater than 29 

MW (100 million Btu/hour) combusting 

coal, oil, or mixtures of these fuels with 

any other fuels. The proposed standards 

for PM would apply to industrialcommercial-institutional steam 

generating units with heat input 

capacities greater than 29 MW (100 

million Btu/hour) combusting oil or 

mixtures of oil with any other fuels. 

B. Pollutants To Be Regulated 

Emissions of SO2 and PM would be 

regulated under the proposed standards. 

C. Best Demonstrated Technology 

The proposed standards are based on 

the preliminary conclusion that flue gas 

desulfurization (FGD) represents the 

best demonstrated technology for 

reducing emissions of SO. from coalfired industrial-commercial-institutional 

steam generating units and that FGD 

represents the best demonstrated 

technology for reducing emissions of 

SO2 and PM from oil-fired units. Flue 

gas desulfurization systems can be 

defined as processes in which the flue 

gases containing SOa are contacted by 

alkaline reagents that react with and 

absorb the SO2 gases. 

The determination of best 

demonstrated technology reflects the 

Agency's consideration of a wide 

variety of factors. These factors include 

the feasibility and availability of a 

technology, the costs of control, and 

energy and environmental effects. 

Before promulgating a final rule, the 

Agency will review its preliminary 

finding that FGD represents best 

demonstrated technology in light of the 

public comments received and the 

Agency's own additional analyses. 

D. Format for the Standards 

The proposed standards for SOs 

include both a percent reduction 

requirement and an emission limit for 

SO2. Emissions would be calculated as 

nanograms of pollutant per joule of heat 

input (ng/J) or pounds of pollutant per 

million Btu of heat input (lb/million Btu) 

supplied by the fuel. The proposed 

standards for PM establish an emission 

limit which is also calculated on a ng/J 

or lb/million Btu heat input basis. 

E. Actual Standards 

1. Sulfur Dioxide 

The proposed regulation would 

require all coal-fired industrialcommercial-institutional steam 

generating units equipped with 

conventional wet FGD systems or lime 

spray drying systems and all coal-fired 

fluidized bed combustion (FBC) systems 

to achieve a 90 percent reduction in SO2 

emissions and meet an emission limit of 

516 ng SO2/J (1.2 lb SOs/million Btu} 

heat input. Coal-fired steam generating 

units using an emerging technology for 

SO2 control would be required to 
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223S® Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 

achieve a 50 percent reduction in SO2 

emissions and meet an emission limit of 

258 ng SO2/J (0.6 lb S02/million Btu) 

heat input. Steam generating units firing 

mixtures of coal with any other fuel 

(except oil or natural gas) and having an 

annual fossil fuel utilization factor for 

coal of 30 percent (0.30) or less would be 

required to meet an SOz emission limit 

of 516 ng/J (1.2 lb SOa/million Btu) heat 

input. 

The proposed standards would 

require all oil-fired industrialcommercial-institutional steam 

generating units equipped with 

conventional wet FGD systems or lime 

spray drying systems and all oil-fired 

FBC systems to achieve a 80 percent 

reduction in SO2 emissions and meet an 

emission limit of 344 ng SO2/J (0.8 lb 

SOa/million Btu) heat input. Oil-fired 

steam generating units using an 

emerging technology to control SO2 

emissions would be required to achieve 

a 50 percent reduction in SCh emissions 

and meet an emission limit of 172 ng 

SOa/J (0.4 lb SOa/million Btu) heat input. 

Steam generating units firing oil and 

meeting an SOa emission limit of 86 ng/J 

(0.2 lb SOa/million Btu) or less would 

not be required to achieve a further 

percent reduction in SOa emissions. 

The emission limit for steam 

generating units firing a mixture of coal 

and oil would be determined by 

proration. 

2. Particulate Matter 

The proposed regulation would 

establish a PM emission limit of 43 ng/J 

(0.1 lb/million Btu) heat input for 

industrial-commercial-institutional 

steam generating units firing oil, either 

alone or in combination with other fuels. 

F. Performance Testing and Monitoring 

Requirements 

The proposed regulation would 

require continuous monitoring of SOa 

emissions. Compliance with the percent 

reduction requirements and emission 

limits would be determined on a 

continuous 30-day rolling average basis 

by calculating the average percent 

reduction and S02 emissions for 30 

consecutive steam generating unit 

operating days, as measured by the 

continuous emission monitoring system 

(CEMS). These calculations would'be 

made in accordance with Reference 

Method 19 or 19A. 

The performance testing and 

monitoring requirements for PM would 

be the same as those proposed 

previously for coal-, wood-, and solid 

waste-fired steam generating units (49 

FR 25102, June 19,1984). 

G. Reporting and Recordkeeping • 

The proposed regulation would 

require steam generating unit owners or 

operators to submit a notification of the 

intent to initiate operation of a new, 

modified, or reconstructed steam 

generating unit, as well as the results of 

the initial performance test and 

performance evaluation of the CEMS, if 

applicable. In addition, if an owner or 

operator installs an emerging technology 

to control SOa emissions, a complete 

description of the technology would be 

submitted. . 

Quarterly reports of SOa emissions 

would also be required under the 

proposed regulation. Each report would 

include all 30-day rolling average 

percent reduction and emission values 

calculated during the calendar quarter. 

Records of all data collected would be 

maintained for a period of 2 years. 

III. Impacts of the Standards 

A. Air 

Compared to a steam generating unit 

as presently controlled by a typical 

State implementation plan (SIP), the 

proposed standards could reduce 

emissions of SO2 from a typical 

industrial-commercial-institutional 

steam generating unit by between 465 

Mg/year (510 tons/year) and 2,420 Mg/ 

year (2,670 tons/year), depending on 

steam generating unit size and the type 

of fuel fired. 

The proposed standards could reduce 

emissions of PM from a typical oil-fired 

industrial-commercial-institutional 

steam generating unit by about 49 Mg/ 

year (54 tons/year). 

In the fifth year after this NSPS 

becomes applicable, nationwide 

emissions of SO2 would be decreased by 

about 290,000 Mg/year (320,000 tons/ 

year) compared with projected emission 

levels under the regulatory baseline. 

Nationwide emissions of PM would be 

decreased by about 12,000 Mg/year 

(13,000 tons/year) compared with 

projected emissions under the regulatory 

baseline. 

B. Water and Solid Waste 

In the fifth year after the proposed 

standards become applicable, national 

solid and liquid waste production 

associated with industrial- commercialinstitutional steam generating units 

could nearly double compared to the 

regulatory baseline. This increase, 

however, would represent only a small 

portion of the total waste production at 

most manufacturing plants employing 

steam generating units. In addition, the 

wastes produced by SOa control 

processes are nonhazardous and 

nontoxic and can be disposed of along 

with the other manufacturing plant 

wastes using traditional treatment and 

disposal techniques. Therefore, no 

adverse water or solid waste impacts 

are anticipated as a result of the 

proposed standards. 

C. Energy 

The proposed standards will not 

result in significant impacts on national 

fuel use markets. Fuel switching from 

coal and oil to natural gas is projected 

to occur, but the impact of this fuel 

switching on coal, oil, and natural gas 

markets would be small. 

D. Control Costs 

1. Typical Steam Generating Unit Costs 

Under the proposed standards, the 

capital cost of a typical industrialcommercral-institutional steam 

generating unit could increase by 

between 4 and 25 percent over the costs 

at the regulatory baseline. The 

magnitude of the increase would depend 

on several factors, including steam 

generating unit size, capacity factor, 

regional location, the type of control 

device installed, and the type of fuel 

fired. Similarly, annualized costs for a . 

typical steam generating unit could 

increase by between 6 and 22 percent 

over the costs at the regulatory baseline, 

depending on the factors mentioned 

above. 

2. Nationwide Costs 

During the fifth year of applicability of 

the proposed standards, the nationwide 

annualized costs for industrialcommercial-institutional steam 

generating units would be about $3.93 

billion, compared with about $3.77 

billion under the regulatory baseline. 

This represents an increase in 

annualized costs of about $165 million, 

or a potential national annualized cost 

increase of about 4 percent as a result of 

the proposed standards. 

E. Economic Effects 

The industry-specific economic effects 

of the proposed standards were 

assessed for six industries which were 

considered likely to experience the most 

severe impacts. For these six industries, 

product prices were projected to 

increase by less than 0.01 to 1.5 percent 

in the fifth year following promulgation 

of the proposed standards, assuming 

"full cost pass-through" of increased 

steam costs. Value added was projected 

to increase by about 0.01 to 5 percent, 

again assuming "full cost pass-through." 

Assuming "full cost absorption" of 

increased steam costs, return on assets 

was projected to decrease by 0.03 to 2.8 

percentage points. Again, this" analysis 
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Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules. 223B7 

was based on the "worse case" scenario 

for the most severely affected industry 

groups. 

IV. Solicitation of Public Comment 

The standards being proposed today 

reflect the Agency's directive [section 

lll(a)(l)(A)(ii) of the Clean Air Act] to 

establish percent reduction standards 

for fossil fuel-fired sources provided the 

impacts of such requirements are 

reasonable. Accordingly, today's 

proposed standards also reflect the 

Agency's judgment of what represents 

reasonable impacts. To determine 

whether impacts are reasonable, the 

Agency considers such factors as costs, 

emission reductions, nonair 

environmental impacts, and the cost 

effectiveness of the standards compared 

to less stringent regulatory options. Each 

of these impacts is discussed in this 

preamble. 

A. Energy Price Scenarios 

The Agency recognizes that the cost 

impacts associated with today's 

standards are directly affected by the 

fuel prices that were projected at the 

time that the impact analyses were 

conducted and that the energy scenario 

on which the national impacts analysis 

is based, does not reflect current 

expectations of future energy prices.-

It is anticipated that an energy 

scenario prepared at the current time 

would reflect generally lower bil prices 

and a higher degree of uncertainty in 

natural gas prices than the scenario 

used in the current analysis. This would 

likely result in even lower coal 

penetration in the steam generating unit 

market than the current analysis 

indicates due to lower oil prices and 

would likely result in a wider range of 

projected emission reductions and cost 

effectiveness values resulting from the 

control of oil combustion due to 

uncertainty in relative oil and gas prices. 

The Agency intends to update its 

energy price scenarios between 

proposal and promulgation of these 

standards to determine whether the 

costs, emission reductions and, in 

particular, the cost effectiveness of this 

rule will be altered significantly. When 

the Agency completes its analysis, this 

information will be added to the docket. 

B. Exemptions from Percent Reduction 

Requirements. 

The Agency solicits comments on 

whether to expand the exemption from 

percent reduction requirements for some 

steam generating units based upon their 

size or capacity utilization rates. 

Specifically, comments are solicited on 

whether percent reduction standards 

should apply only to coal-, oil-, and 

mixed fuel-fired steam generating units 

with heat input capacities greater than 

73 MW (250 million Btu/hour) (or some 

other size category) or to steam 

generating units with annual fossil fuel 

utilization rates of more than 45 percent 

(or 30 oro15 percent). 

Standards for steam generating units 

exempted from percentage reduction 

requirements would be 516 ng SO2/J (1.2 

lb SOa/million Btu) for coal-fired steam 

generating units, 344 ng SOa/J (0.8 lb 

SOa/million Btu) for oil-fired steam 

generating units, and 516 ng SO2/J (1.2 lb 

SOa/million Btu) for mixed fuel-fired 

steam generating units. EPA also solicits 

comments on other alternative 

standards for steam generating units 

that are small or that have low capacity 

utilization rates. 

A key factor influencing the cost 

effectiveness of this proposed rule is the 

projected ability of firms to switch from 

oil to natural gas for steam generating 

units of smaller size and steam 

generating units that have low capacity 

utilization rates. Given the dramatic 

changes in oil and natural gas prices 

that have transpired since the Agency 

undertook its energy scenarios, the cost 

effectiveness of requiring a percent 

reduction in SO2 emissions for these 

categories of steam generating units 

could change. The Agency intends to 

analyze the impact of revised energy 

price forecasts upon the cost 

effectiveness of SO2 control for smaller 

steam generating units and steam 

generating units with low capacity 

utilization rates after proposal and add 

this analysis to the docket. 

As discussed above, classes of steam 

generating units would be exempt from 

percent reduction requirements on the 

basis that the impacts of a percent 

reduction requirement would be deemed 

unreasonable, and thus that the 

technologies necessary to achieve such 

percent reductions could not be said to 

be "adequately demonstrated" within 

the meaning of section 111 of the Act. 

Given the magnitudes of the costs and 

emission reductions associated with the 

controls of these steam generating units, 

the Agency is interested in receiving 

information from commenters on what 

should be the basis for determining 

when the impacts of a percent reduction 

requirement are unreasonable. 

The Agency also specifically solicits 

comments on whether the percentage 

reduction requirement in section 

lll(a)(l)(A)(ii) of the Act applies to this 

standard. Comments are invited on 

whether establishing standards based 

on the application of emission control 

technology (e.g., flue gas desulfurization) 

under the projection that most sources 

will fuel switch and thereby avoid the 

costs associated with the emission 

control technology is an appropriate 

interpretation of this section of the Act. 

In addition, comments are invited on the 

use of low sulfur fuels as the basis of 

NSPS, and the percent reduction 

associated with the pretreatment of very 

low sulfur oils. 

V. Rationale 

A. Selection of Source Category 

On August 21,1979, a priority list for 

development of additional NSPS was 

published in accordance with sections 

111(b)(1)(A) and 111(f)(1) of the Clean 

Air Act. This list identified 59 major 

stationary source categories that were 

judged to contribute significantly to air 

pollution that could reasonably be 

expected to endanger public health or 

welfare. Fossil fuel-fired industrial 

steam generating units ranked eleventh 

on this priority list of sources for which 

NSPS would be established in the future. 

Of the 10 sources ranked above fossil 

fuel-fired industrial steam generating 

units on the priority list, nine were 

major sources of volatile organic 

compound (VOC) emissions. Because 

there are many areas which have not 

attained the national ambient air quality 

standard for (NAAQS) ozone, major 

sources of VOC emissions were 

accorded a very high priority. The 

remaining source category ranked above 

fossil fuel-fired industrial steam 

generating units was stationary internal 

combustion engines, a major source of 

NO, emissions. Fossil fuel-fired 

industrial steam generating units were 

the highest ranked source of PM and 

SOa emissions, and the second highest 

ranked source of NO„ emissions when 

the priority list of source categories not 

previously regulated by NSPS was 

published. 

Wood and solid waste are widely 

used as fuel in industrial steam 

generating units. As a result, industrialcommercial-institutional steam 

generating units firing the.se fuels could 

also be significant contributors to future 

air pollution. In addition, large 

commercial and institutional steam 

generating units have essentially the 

same design, fuel capability, and 

emissions potential as industrial steam 

generating units. Consequently, on June 

19,1984, an amendment to the priority 

list was proposed that would expand the 

source category of industrial fossil fuelfired steam generating units to cover all 

steam generating units, including both 

fossil fuel-fired and nonfossil fuel-fired 

steam generating units, as well ao steam 

generating units used in commercial and 

institutional applications (49 FR 25156, 
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22388 Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 

June 19,1984). Consistent with this 

proposed amendment of the priority list, 

the source category for the proposed 

standards includes both fossil and 

nonfossil fuel-fired industrial, 

commercial and institutional steam 

generating units. 

Fossil and nonfossil fuel-fired steam 

generating units are significant sources 

of emissions of three major pollutants: 

PM, SOa, and NO,. The expected 

construction of new coal-, oil-, and 

fossil/nonfossil fuel-fired steam 

generating units as a result of plant 

expansions and replacements of existing 

steam generating units is expected to 

result in a growth in emissions from this 

source category. A number of these new 

facilities will fire coal and high sulfur 

oil. Combustion of wood and solid 

waste in combination with coal or oil is 

also projected to increase due to the ' 

lower cost of these nonfossil fuels. 

These developments could result in 

significant increases in SOa emissions if 

standards of performance are not 

established for new industrialcommercial-institutional steam 

' generating units. 

National ambient air quality 

standards have been established for SOa 

because of its known adverse effects on 

public health and welfare. Impacts of 

this pollutant have been documented in 

a criteria document prepared under 

Section 108 of the Clean Air Act. These 

effects are a major basis for concluding 

that emissions from industrialcommercial-institutional steam 

generating units constitute a potential 

danger to public health and welfare. 

Also significant is the fact that many 

new industrial-commercial-institutional 

steam generating units will be located in 

urban areas where a large population 

will be exposed to the emissions. 

B. Selection of Pollutants, Fuels, and 

Affected Facilities 

Emissions of PM from the combustion 

of oil and SOa emissions from the 

combustion of oil, coal and mixed fuels 

(i.e., combustion of mixtures of fossil 

fuels or. fossil and nonfossil fuels) would 

be the pollutants regulated under the 

proposed standards. The NSPS have 

already been proposed that would limit 

PM emissions from industrialcommercial-institutional steam 

generating units firing coal, wood, or 

solid waste and NOx emissions from • 

steam generating units firing mixtures of 

fossil fuels or fossil and nonfossil fuels 

(49 FR 25102, June 19.1984). 

The potential impacts associated with 

this "phased" approach to rulemaking 

were considered prior to proposing 

standards for PM and NO„. The 

standards being proposed today are not 

retroactive and affect only new steam 

generating units built after this date. No 

potential problems have been identified 

that might result from this phased 

approach to rulemaking and no 

unreasonable impacts are anticipated to 

occur. 

The proposed standards would limit 

emissions of SOa from steam generating 

units firing oil, coal, and fuel mixtures 

containing any of these fuels and 

emissions of PM from oil-fired steam 

generating units. The proposed 

standards would cover industrialcommercial-institutional steam 

generating units with heat input 

capacities greater than 29 MW (100 

million Btu/hour). Analyses of the 

projected new steam generating unit 

population indicate that nearly all new 

steam generating units larger than 29 

MW (100 million Btu/hour) heat input 

capacity will be industrial steam 

generating units, with only a few 

commercial and institutional steam 

generating units in this size range. The 

steam generating unit size limit of 29 

MW (100 million Btu/hour) heat input 

capacity would, therefore, include only 

the largest commercial and institutional 

steam generating units and would 

concentrate the scope of the proposed 

standards on industrial steam 

generating units. Utility steam 

generating units larger than 73 MW (250 

million Btu/hour) heat input capacity 

remain subject to Subpart Da. 

Development of NSPS limiting 

emissions of sulfur oxides, NO*, and PM 

from steam generating units with heat 

input capacities of 29 MW (100 million 

Btu/hour) or less is currently underway. 

The type of unit used, the physical 

design characteristics of these units, the 

cost impacts of emission control systems 

on steam production costs, and the 

application of steam are often different 

for smaller steam generating units than 

for larger steam generating units. 

Because these factors have been found 

to be materially different, separate study 

of smaller steam generating units is 

appropriate. This will assure that an 

adequate evaluation is conducted of the 

technical and economic factors 

associated with applying emission 

controls to smaller steam generating 

units. 

C. Selection of Best System of 

Continuous Sulfur Dioxide Emission 

Reduction 

The regulatory analyses discussed 

below are summarized and discussed in 

greater detail in the set of nine BID 

documents listed in the introduction to 

this preamble. In particular, the 

document entitled "Summary of 

Regulatory Analysis: New Source 

Performance Standards for IndustrialCommercial-Institutional Steam 

Generating Units of Greater Than 29 

MW (100 million Btu/hour) Heat Input 

Capacity" presents an overview of the 

analyses and regulatory alternatives 

considered in developing the proposed 

standards. This document is referenced 

extensively in the discussion below, and 

is referred to as "Summary of 

Regulatory Analysis" for the sake of 

brevity. 

The 1977 amendments to section 111 

of the Clean Air Act require standards 

of performance for new fossil fuel-fired 

steam generating units to include both 

an emission limit and a requirement that 

emissions be reduced by a specified 

percentage. Section 111 also requires 

that the emission limit and the 

percentage reduction requirement reflect 

the performance of the best 

technological system of continuous 

emission reduction which has been 

adequately demonstrated, taking into 

consideration the costs, energy 

requirements, and environmental 

impacts of achieving such emission 

reduction (i.e., best demonstrated 

technology). In determining the degree 

of emission reduction that has been 

demonstrated, section 111 allows 

standards of performance to distinguish 

among various classes, types, and sizes 

of steam generating units in order to 

reflect best demonstrated technology. 

In light of these Clean Air Act 

requirements, the analyses of alternative 

standards of performance examined 

various classes, types, and sizes of 

industrial-commercial-institutional 

steam generating units to determine if a 

percent reduction requirement would 

have unreasonable cost, energy, or 

environmental impacts. In addition, the 

analyses examined the incremental cost, 

energy, and environmental impacts of a 

percent reduction requirement over the 

impacts of a standard based on the use 

of low sulfur fuels. Thus, the 

requirements set forth in section 111 of 

the Clean Air Act have largely 

determined both the type and the scope 

of the analyses that have been 

performed in support of this rulemaking. 

Another point that should be noted is 

that the analyses are influenced, in 

particular, by the energy scenarios that 

have been used to bound the regulatory 

analysis. As described in "Summary of 

Regulatory Analysis" under 

"Consideration of National Impacts," 

two distinct crude oil price scenarios 

were considered in performing the 

national impact analysis. One of these 

price scenarios assumed a 1985 base 

price of $25 per barrel with only 

moderate future increases in crude oil 
P.8 

Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 22389 

es, resulting in a relatively high 

i of oil in the new industrialcon, istitutional steam 

generating unit energy market. Under 

ul penetration scenario, ihe 

model used to calculate national 

ta, the Industrial Fuel Choice 

Analysis Model (IFCAM). predicted that 

under the regulatory baseline residual 

oil and natural gas would compete 

the new steam generating unit energy 

land, with residual oil capturing 

it 65 percent, and natural gas about 

30 percent, of the 1990 energy demand. 

- scenario reflected a "best guess" as 

to future fuel use in new industrialcommercial-institutional steam 

generating units. 

In response to concerns that this 

scenario might significantly 

underestimate coal use. the other price 

scenario assumed relatively sharp 

increases in future crude oil prio 

resulting in a relatively high penetration 

of coal in the new industrialcorn I stitutional steam 

ating unit energy market. Under 

this high coal penetration scena; 

IFCAM predicted that under the 

regulatory baseline coal and natural gas 

would compete for the new steam 

generating unit energy demand, with 

capturing about 60 percent, and 

natural gas about 40 percent, of the 1990 

energy demand. 

Another point that should be noted, 

and which has significantly shaped the 

framework within which the basis of 

standards of performance for industrialcommercial-institutional steam 

generating units have been selected, is 

the relative insensitivity of cost impacts 

to the specific level of a percent 

reduction requirement. This relative 

ins* permits the selection of the 

proposed standards to be divided into a 

two-step process. The decision 

concerning the basis of the standards 

(i.e.. require a percent reduction in SOssions or permit the use of low sulfur 

fuels) can be separated from the 

decision regarding the specific 

irements to include in the standards 

(i.e.. 50. 70, 90. etc., percent reduction 

percent reduction is selected as the 

basis of the standards; or 1.7.1.2, etc.. lb 

SOa/million Btu for coal-fired steam 

generating units; or 1.6. 0.8. 0.3. etc.. lb 

SOv/million Btu for oil-fired steam 

generating units, if use of low sulfur 

fuels is selected as the basis for 

standards). 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of National Imp;: 

there is little difference in national cost 

impacts among alternative control levels 

ing various percent reductions in 

SO2 emissions. For example, under the 

high oil penetration scenario, national 

lpacts range from $3,474 million/ 

year to $3,482 million/year for the 

various alternatives considered which 

would require a percent reduction in 

emissions. Similarly, under the high coal 

penetration scenario, national cost 

impacts range from $3,754 million/year 

to $3,758 million/year for the various 

percent reduction alternatives 

considered. Differences of such small 

relative magnitude would not result in 

substantially different cost impacts on a 

national basis. Consequently, it is not 

necessary to consider numerous percent 

reduction levels in determining whether 

a standard requiring a percent reduction 

in emissions would have unreasonable 

impacts compared to a standard based 

on the use of low sulfur fuels. Rather, in 

considering whether the standards 

should require a percent reduction in 

SO2 emissions or be based on the use of 

low sulfur fuels, a single percent 

reduction level can be used as 

representative ofthe impacts associated 

with standards requiring a percent 

reduction in SOa emissions. 

For purposes of die analysis focusing 

on whether the basis of the standards 

should be percent reduction 

requirements or the use of low sulfur 

fuels, a 90 percent reduction requirement 

was selected to represent the range of 

percent reduction requirements that 

could be included in standards of 

performance. This percent reduction 

level was selected for this purpose for 

several reasons. It represents the level 

of performance which has been 

demonstrated by various FGD system 

technologies, as discussed in "Summary 

of Regulatory Analysis" under 

"Performance of Demonstrated Emission 

Control Technologies." and it is 

consistent with the intent of Section 111 

of the Clean Air Act that standards of 

performance reflect the performance of 

best demonstrated emission control 

technologies. In addition, as discussed 

in "Summary of Regulatory Analysis" 

under "Consideration of Demonstrated 

Emission Control Technology Costs." a 

90 percent reduction requirement is 

more cost effective than lower pe' 

reduction requirements, such as 50 or 70 

percent. 

As also discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of National Impacts," 

there are relatively greater differences 

in annualized costs among alternative 

control levels based on the use of low 

sulfur fuels. This is particularly true 

under the high oil penetration scenario 

where annualized costs for the more 

stringent control level (i.e.. Control Level 

II) are about $50 million/year greater 

than the costs associated with the less 

stringent control level (i.e., Control Level 

I). Consequently, in the case of low 

sulfur fuel-based standards fp 

steam generating units, two alternatives 

were used in the analysis to r 

standards based on the use of low sulfur 

oil: an emission level of 344 ng SOa/J (0.8 

lb SOa/million Btu) and an emission 

level of 688 ng SOs/J (1.6 lb SOj/milllon 

Btu) heat input. 

Under the high coal penetM 

scenario, however, the difference in 

annualized costs among alternative low 

sulfur fuel standards is less, amounting 

to under $10 million/year. Consequently, 

in evaluating the impacts of standards 

based on the use of low sulfur coal, a 

single alternative was used to represent 

standards based on the use of low sulfur 

coal: An emission level of 518 ng SOj/J 

(1.2 lb SOa/million Btu) heat input. 

In summary, several points should be 

kept in mind in reviewing the discussion 

presented below summarizing selection 

of the proposed standards. First, the 

analysis has focused on the incremental 

environmental, cost, and energy impacts 

associated with standards that include a 

percent reduction requirement ov 

those associated with standards based 

on the use of low sulfur fuels. In 

evaluating these impacts, the analysis 

has distinguished among various 

classes, types, and sizes of steam 

generating units. 

Second, impacts of various standards 

have been estimated for two widely 

different scenarios of future fuel use in 

industrial-commercial-institutional 

steam generating units. For the reasons 

mentioned above, these scenarios 

cannot be used to assess quantitatively 

the impact of various standards on 

market interactions between coal and 

oil. 

Finally, and perhaps most 

significantly, the relative insensitivity of 

cost impacts to the specific level of a 

percent reduction requirement permits 

the selection of standards of 

performance to be subdivided into a 

two-step process. First, the basis of 

standards can be considered and 

selected using a single percent reduction 

requirement to represent the full range 

of percent reduction requirements that 

could be included in standards of 

performance. AIBO. in the case of coal, a 

single emission limit, and in the case of 

oil. two emission limits, can be UM 

represent the range of emission limits 

that could be included in standards of 

performance based on the use of low 

sulfur fuels. Second, after selecting the 

basis of the proposed standards, the 

specific percent reduction requirements 
22390 Federal Register / Vol. 51. No. 118 / Thursday, June 19. 1986 / Proposed Rules 

P.9 

or the specific emission limits reflecting 

the use of low sulfur fuels which should 

be included in the proposed standards 

can be considered and selected. 

1. Basis of Standard for Coal-Fired 

Steam Generating Units 

In addition to the points outlined and 

discussed above, it should also be noted 

that the regulatory analysis examined 

the potential impacts of NSPS from three 

different perspectives: The perspective 

of overall national impacts; the 

perspective of specific industries subject 

to the standards; and the perspective of 

individual steam generating units 

subject to the standards. At the national 

level, the regulatory analysis examined 

the cost and emission impacts 

associated with both standards 

requiring a percent reduction in SO2 

emissions and standards based on the 

use of low sulfur coal. At the specific 

industry level, the analysis focused 

. more narrowly on selected industries 

considered most likely to experience 

adverse economic impacts associated 

with standards requiring a percent 

reduction in emissions. Finally, at the 

individual steam generating unit level, 

the cost and emission impacts 

associated with standards requiring a 

percent reduction in SO2 emissions and 

standards based on the use of low sulfur 

coal were examined from the 

perspective of various sizes, types, and 

geographic locations of steam generating 

units. 

National Impacts. As noted above 

and discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of National Impacts," 

the national impacts associated with 

NSPS for fossil fuel-fired steam 

generating units were analyzed through 

the use of a computer model known as , 

IFCAM. As also noted above, the high 

coal penetration scenario was used to 

assess the potential impacts of a set of 

regulatory alternatives limiting S02 

emissions from coal-fired steam 

generating units. The regulatory 

alternatives were structured to examine 

impacts as a function of steam 

generating unit size (heat input 

capacity). 

The regulatory alternatives become 

progressively more stringent by first 

requiring only steam generating units 

with heat input capacities greater than 

73 MW (250 million Btu/hour) to achieve 

a percent reduction in SO2 emissions, 

but then requiring steam generating 

units with progressively lower heat 

input capacities to achieve a percent 

reduction in SO2 emissions as well. The 

most stringent regulatory alternative 

requires all coal-fired industrialcommercial-institutional steam 

generating units with heat input 

capacities pf greater than 29 MW (100 

million Btu/hour) to achieve a percent 

reduction in SO2 emissions. The least 

stringent regulatory alternative is based 

on the use of low sulfur coal for all coalfired industrial-commercial-institutional 

steam generating units with heat input 

capacities of greater than 29 MW (100 

million Btu/hour). 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of National Impacts" 

and shown in Table 8-7, assuming a 

high coal penetration in new fossil fuelfired steam generating units, standards 

based on the use of low sulfur coal for 

all new coal-fired steam generating units 

with heat input capacities of greater 

than 29 MW (100 million Btu/hour) 

result in a projected reduction in 

national SO2 emissions of 192,000 Mg/ 

year (212,000 tons/year) over the 

regulatory baseline in the fifth year 

following proposal of standards (i.e., 

1990). In comparison, standards 

requiring all new coal-fired steam 

generating units with heat input 

capacities of greater than 29 MW (100 

million Btu/hour) to achieve a percent 

reduction in emissions result in 

projected national SO2 emission 

reductions of 281,000 Mg/year (310,000 

tons/year) over the regulatory baseline 

in 1990. 

Of the difference in projected 

reductions in national SO2 emissions 

between these two alternatives (about 

89,000 Mg/year), somewhat less than 

half (about 44,000 Mg/year) results from 

standards requiring all new coal-fired 

steam generating units with heat input 

capacities greater than 73 MW (250 

million Btu/hour) to achieve a percent 

reduction in SO2 emissions. Additional 

national SO2 emission reductions of 

15,000 Mg/year (17,000 tons/year), 

21,000 Mg/year (23,000 tons/year), and 

9,000 Mg/year (10,000 tons/year) result 

from requiring all new coal-fired steam 

generating units with heat input 

capacities of greater than 58 MW (200 

million Btu/hour), 44 MW (150 million 

Btu/hour), and 29 MW (100 million Btu/ 

hour), respectively, to achieve a percent 

reduction in SO2 emissions. 

This analysis, therefore, projects that 

standards requiring all new coal-fired 

steam generating units to achieve a 

percent reduction in SO2 emissions 

result in greater reductions in national 

SO2 emissions than standards based on 

the use of low sulfur coal. Moreover, the 

analysis also projects that standards 

requiring all new coal-fired steam 

generating units with heat input 

capacities greater than 29 MW (100 

million Btu/hour) to achieve a percent 

reduction in SOa emissions result in 

significantly greater national SOa 

emission reductions than standards 

requiring only relatively larger coal-fired 

steam generating units to achieve a 

percent reduction in emissions. 

As is also shown in Table 8-7, 

assuming a high coal penetration in new 

fossil fuel-fired steam generating units, 

NSPS based on the use of low sulfur 

coal for all new coal-fired steam ' 

generating units with heat input 

capacities of greater than 29 MW (100 

million Btu/hour) result in a projected 

national annualized cost increase of $18 

million/year over the regulatory 

baseline in 1990. This represents an 

increase of less than 1 percent in the 

total national annualized costs 

associated with operation of all new 

fossil fuel-fired steam generating units 

projected to be constructed between 

1986 and 1990. 

In comparison, standards requiring all 

new coal-fired steam generating units 

with heat input capacities of greater 

than 29 MW (100 million Btu/hour) to 

achieve a percent reduction in emissions 

result in projected national annualized 

cost increases of about $32 million/year 

over the regulatory baseline in 1990. 

This represents an increase in total 

national annualized costs of about 1 

percent. 

Of the difference in projected 

increases in total national annualized 

costs between these two alternatives 

(about $14 million/year), nearly all ($11 

million/year) results from standards 

requiring all new coal-fired steam 

generating units with heat input 

capacities greater than 44 MW (150 

million Btu/hour) to achieve a percent 

reduction in SO2 emissions. As shown in 

Table 8-7, the analysis indicates that 

regulatory alternatives requiring only 

relatively larger coal-fired steam 

generating units (i.e., those with heat 

input capacities of greater than 73 MW) 

to achieve a percent reduction in SO2 

emissions result in marginally greater 

total national annualized costs than 

alternatives requiring all new coal-fired 

steam generating units with heat input 

capacities greater than 29 MW (100 

million Btu/hour) to achieve a percent 

reduction in emissions. 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of National Impacts," 

this apparent anomaly is explained by 

the larger number of natural gas-fired 

steam generating units that are 

projected in response to increasingly 

stringent regulatory alternatives. In 

response to standards that require coalfired steam generating units with lower 

and lower heat input capacities to 
P.10 

Federal Register / Vol. 51. No. 118 / Thursday. June 19. 1986 / Proposed Rules 22391 

B percent reduction in 

emissions, an increasing number of 

tiiese steam generating units are 

projected to fire natural gas instead of 

coal to avoid the costs associated with 

ling and operating FGD systi 

As discussed in "Summary of 

'atory Analysis" under 

"Consideration of National Impacts." 

IFCAM selects the least cost alternat 

lable to comply with each 

;tory alternative examined. This 

includes the option of firing an 

alternative fuel, such as natural gas. as 

well as installation of an FGD system. 

least cost alternative is selected on 

the basis of the after-tax net present 

value associated with each option 

available to comply with the regu! 

alternative in question. The IFCAM 

projects total national annualized i 

each regulatory alternative 

examined, however, using the 

annualized costs—not the after-tax net 

present value— associated with rprojected new steam generating unit. 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of Demonstrated 

Emission Control Technology Costs" 

and shown in Table 6-19, while firing 

natural gas instead of coal may result in 

sm increase in after-tax net present 

te, it can also result in a decrease in 

annualized costs. Thus, it is possible for 

total projected national annualized costs 

••ease in response to increasingly 

stringent regulatory alternatives. 

Under the assumption of high coal 

penetration in new fossil fuel-fired 

steam generating units, therefore, this 

analysis indicates that the inc 

national annualized costs 

associated with standards requiring all 

new coal-fired steam generating units to 

achieve a percent reduction in SO.. 

emissions is small compared to the 

increase in total national annualized 

costs associated with standards ba 

on the use of low sulfur a 

Based on the projected national 

emission reductions and annualized cost 

increases described above, the national 

age cost effectiveness of NSPS 

based on the use of low sulfur coal for 

all new coal-fired steam generating units 

with heat input capacities of greater 

than 29 MW (100 million Btu/hour) is 

about $92/Mg ($85/ton) of SO., removed. 

In comparison, standards requiring all 

new coal-fired steam generating units 

with heat input capacities of greater 

than 29 MW (100 million Btu/hour) to 

achieve a percent reduction in emiss 

result in a national average i 

effectiveness of $110/Mg ($100/ton) of 

SO- removed. 

The national incremental cost 

•ness of a standard requ 

new coal-fired steam generating units 

with heat input capacities of greater 

than 29 MW (100 million Btu/hour) to 

achieve a percent reduction in emissions 

over a standard based on the use of low 

sulfur coal is about $150/Mg ($140/ton) 

of SO J removed. As discussed in 

"Summary of Regulatory Analysis" 

under "Consideration of National 

Impacts" and shown in Table 8-7. this is 

considerably less than the national 

incremental cost effectiveness (about 

$635/Mg of SO2 removed) of a standard 

requiring only new coal-fired steam 

generating units with heat input 

capacities of greater than 73 MW (250 

million Btu/hour) to achieve a percent 

reduction in SO2 emissions over a 

standard based on the use of low sulfur 

coal for all new coal-fired steam 

generating units. The national 

incremental cost effectiveness of a 

standard requiring all new coal-fired 

steam generating units to achieve a 

percent reduction in SOa emissions over 

the next most stringent regulatory 

alternative, requiring only new coalfired steam generating units with heat 

input capacities of greater than 44 MW 

(150 million Btu/hour) to achieve a 

percent reduction in SO2 emissions, is 

also less, about $330/Mg ($300/ton) of 

SOa removed. 

This apparent anomaly of decreasing 

national incremental cost effectiveness 

with increasingly stringent regulatory 

alternatives results from the larger 

number of natural gas-fired steam 

generating units that are projected under 

increasingly stringent standards. As 

mentioned above and discussed in 

"Summary of Regulatory Ana 

under "Consideration of National 

Impacts," increased firing of natural gas 

instead of coal can lead to decreased 

national annualized costs. In addition, 

increased firing of natural gas results in 

large reductions in SOj emissions. As a 

result, the national incremental cost 

effectiveness of increasingly stringent 

standards can decrease and. as shown 

in Table 8-7, can even become negai 

in some cases. 

Under the assumption of high coal 

penetration in new fossil fuel-fired 

steam generating units, therefore, this 

analysis indicates that the national 

average cost effectiveness of standards 

requiring new coal-fired steam 

generating units to achieve a percent 

reduction in SOa emissions is not 

substantially higher than the national 

average cost effectiveness of standards 

based on the use of low sulfur coal. In 

addition, this analysis indicates that the 

national incremental cost effectiveni 

of standards requiring coal-fired steam 

generating units with heat input 

capacities of greater than 29 MW (100 

million Btu/hour) to achi ent 

reduction in emissions over stand ; 

based on the use of low sulfin 

about $165/Mg ($150/ton) of SOJ 

removed. 

As also discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of National Impa. 

and shown in Table 8-7, assuming a 

high coal penetration in new fossil fuel 

fired steam generating units, NSPS 

based on the use of low sulfur coal for 

all new coal-fired steam generating units 

with heat input capacities of gre.v 

than 29 MW (100 million Btu/hour) 

result in a projected reduction in 

national coal consumption of 40 mil 

GJ/year (36 trillion Btu/year) in 1990 

compared to the regulatory baseline 

This decline in national coal use is 

projected to be offset by an equivalent 

increase in natural gas use. Stand 

requiring all new coal-fired st. 

generating units with heat input 

capacities of greater than 29 MW (100 

million Btu/hour) to achieve a pen 

reduction in SO2 emissions result in a 

projected reduction in national coal 

consumption of 140 million GJ/year (I 

trillion Btu/year) in 1990 con ; 

the regulatory baseline. This decline in 

coal use is also projected to be offse' 

an equivalent increase in natural gas 

use. 

The difference between these two 

alternatives in projected reductions in 

national coal use (about 100 trillion Btu/ 

year) in 1990 is distributed relatively 

uniformly among the intermediate 

regulatory alternatives examined. As 

increasingly smaller coal-fired steam 

generating units are required to 

a percent reduction in emissions, an 

increasingly greater number of these 

units are projected to fire natural gas 

instead of coal. The impact of this 

choice on national coal and natural gas 

markets would be negligible, however. 

As shown in Table 8-9 of "Summary of 

Regulatory Analysis," a decline in coal 

consumption of 140 million GJ/y 

trillion Btu/year) in 199n 

reduction in projected indus; 

consumption of less than 3 p and 

a reduction in projected total nati 

coal consumption of less than 1 ; 

As also shown in Table 8-9. 

disproportionate impacts on Midwestern 

coal markets were projected. Similarly. 

own in Table 8-8. projected 

national natural gas consumptic 

industrial sector would increase in 191X) 

by a maximum of about 2 percent under 

standards requiring all new c 

steam generating units with hi 

capacities of greater than 29 MW (100 

million Btu/hour) to achieve a 

reduction in SOi emissi 
P.11 

22392 Federal Register / Vol. 51, No. 118 /'Thursday, June 19, 1986 / Proposed Rules 

Assuming a high coal penetration in 

new fossil fuel-fired steam generating 

units, therefore, this analysis indicates 

that the potential impact of standards 

requiring a percent reduction in SO2 

emissions for all new coal-fired steam 

generating units with heat input 

capacities of greater than 29 MW (100 

million Btu/hour) on projected national 

coal and natural gas consumption by the 

industrial sector in 1990 is small. 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of Secondary 

Environmental Impacts," potential 

secondary environmental impacts 

associated with standards of 

performance that include a percent 

reduction requirement have also been 

analyzed. These potential secondary 

environmental impacts include liquid 

and solid waste impacts. 

As shown in Table 8-7, assuming a 

high coal penetration in new fossil fuelfired steam generating units, the amount 

of liquid waste generated increases, and 

the amount of solid waste generated 

decreases, as smaller and smaller units 

are required to achieve a percent . 

reduction in SO2 emissions. As 

discussed in "Summary of Regulatory 

Analysis" under "Consideration of 

Demonstrated Emission Control 

Technology Costs," sodium scrubbing is 

frequently the least costly FGD system 

for U3e on industrial-commercialinstitutional steam generating units. As 

a result, these impacts generally reflect 

the use of sodium scrubbing as the 

control system used to achieve a percent 

reduction in SO2 emissions. As also 

discussed in "Summary of Regulatory 

Analysis" under "Consideration of 

Secondary Environmental Impacts," 

sodium scrubbing produces the greatest 

quantity of liquid wastes of all the FGD 

systems examined. Therefore, to the 

extent that other FGD technologies 

(suchas lime spray drying) are selected 

to comply with a standard requiring a 

percent reduction in SO2 emissions, the 

amount of liquid waste would decrease 

and the amount of solid waste would 

increase. 

Most industrial-commercialinstitutional steam generating units are 

part of a manufacturing plant which 

normally generates substantial amounts 

of liquid and solid waste from the 

manufacturing process itself. The 

amount of waste generated by the 

control of SO2 emissions from these 

steam generating units, therefore, would 

represent only a small portion of the 

total wastes generated by the plant in 

most cases. In addition, the constituents 

of the FGD waste byproducts are not 

classified as toxic or hazardous under 

the Resource Conservation and 

Recovery Act (RCRA). As a result, they 

can be easily disposed of, along with the 

other plant wastes, by conventional 

methods without leading to significant 

secondary environmental impacts. 

In summary, therefore, standards 

requiring a percent reduction in SO2 

emissions would result in an increase in 

the amounts of liquid and solid waste 

generated by industrial-commercialinstitutional steam generating units. 

However, the quantities would be small 

compared to the total existing amounts 

of liquid and solid wastes generated by 

industrial plants at which these steam 

generating units are located. In addition, 

the nontoxic and nonhazardous nature 

of the FGD wastes permits their disposal 

using conventional techniques such as 

ponding, landfilling, sewerage, or direct 

discharge. 

Industry-Specific Economic Impacts. 

The analysis discussed above of 

potential national impacts associated 

with standards of performance for new 

coal-fired steam generating units 

represents an assessment of the 

aggregate nationwide impact of 

standards requiring a percent reduction 

in SO2 emissions. Because of the 

aggregate nature of this analysis of 

national impacts, it was unable to 

assess the potential impact of standards 

requiring a percent reduction in SO2 

emissions on specific individual sectors 

within the national economy. 

Accordingly, as discussed in "Summary 

of Regulatory Analysis" under 

"Consideration of Industry-Specific 

Economic Impacts," the regulatory 

analysis also examined the potential 

economic impacts of a standard 

requiring a percent reduction in SO2 

emissions on major industrial steam 

users. 

Before discussing the analysis of 

industry-specific economic impacts, it 

should be noted that the analysis 

represents a "worse case" analysis of 

potential economic impacts. For 

example, the assessment of potential 

increases in national product prices (i.e., 

inflationary impact) and product prices 

at the manufacturing plant level 

assumes full cost pass-through of all 

increased costs to increased product 

prices. Similarly, the assessment of 

potential decreases in industry 

profitability (i.e., decreased return-onassets) assumes full cost absorption of 

all increased costs. In practice, a portion 

of the increased costs associated with 

standards of performance limiting SO2 

emissions from all new fossil fuel-fired 

industrial-commercial-institutional 

steam generating units will be "passed 

through" to product prices and the 

remainder "absorbed." Thus, the 

assessment of potential impacts 

resulting from the assumptions of full 

cost pass-through or full cost absorption 

should be viewed as "worse case" 

assessments. 

In addition, the analysis of potential 

industry-specific economic impacts also 

overlooks the possibility of fuel 

switching. The analysis assumes all new 

fossil fuel-fired stream generating units 

installed within the various industries 

examined will fire coal regardless of the 

relative economics of alternative fuels, 

such as natural gas. As discussed above, 

however, the national impact analysis 

indicates that firing natural gas instead 

of coal in response to standards 

requiring a percent reduction in SO2 

emissions is frequently less expensive 

than installation and operation of an 

FGD system. Consequently, since the 

analysis of potential industry-specific 

economic impacts assumes all new 

fossil fuel-fired steam generating units 

will fire coal and, in response to 

standards requiring a percent reduction 

in SO2 emissions, these units will install 

and operate FGD systems, these impacts 

are overstated and also represent a 

"worse case" assessment of potential 

economic impacts. 

Finally, as mentioned below and 

discussed in "Summary of Regulatory 

Analysis" under "Consideration of 

Industry-Specific Economic Impacts," 

those industries with high steam-toproduct cost ratios or low annual 

capacity utilization, such as seasonal 

industries, were selected for analysis of 

potential economic impacts at the 

manufacturing plant level. The potential 

economic impacts associated with 

standards requiring a percent reduction 

in SO2 emissions will be greater for 

these industries than other industries. 

Consequently, this aspect of the analysis 

also makes it a "worse case" analysis in 

the sense that it examined impacts only 

in those industries anticipated to 

experience the most severe economic 

impacts. 

To assess the potential impact on 

product prices at the national level (i.e., 

national inflationary impacts) 

associated with standards requiring a 

percent reduction in SOa emissions, the 

industry-specific economic analysis 

examined potential impacts on product 

price for eight steam-intensive industrial 

categories which together consume 

about 70 percent of all industrial steam 

production. As discussed in "Summary 

of Regulatory Analysis" under 

"Consideration of Industry-Specific 

Economic Impacts," the product price 

impacts on these eight major industrial 

categories ranged from 0.01 to 0.03 
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Federal Register / Vol. 51, No. 118 / Thursday. June 19. 1986 / Proposed Rules 2239.3 

percent, indicating that the potential 

impact on product prices at the national 

of standards requiring a percent 

reduction in SOz emissions is negligible. 

To assess the potential economic 

impacts of standards requiring a percent 

reduction in S03 emissions on specific 

industries at the indivii! 

Factoring plant level, several 

indi ire selected for analysis. As 

mentioned, industries with either high 

;n-to-product cost ratios or 1 

annual capacity utilization rates were 

ed to provide a "worse i 

viewp 

The if this analysis are 

summarized in Table 9-1 of "Summary 

of Regulatory Analysis." As shown, 

assuming full cost pass-through to 

product prices, the potential increase in 

product prices as a result of standards 

requiring all new coal-fired sit 

generating units to achieve a percent 

reduction in SO2 emissions could range 

from less than 0.1 percent to 1.5 percent. 

Similarly, assuming full cost absorption, 

potential increases in product value 

added range from less than 0.1 percent 

to 5.0 percent, and potential decreases 

in manufacturing plant profitability or 

return on assets range from less than 0.1 

to 2.8 percent. None of these projected 

impacts are considered unreasonable. 

,. tacts on Individual Steam 

rating Units. The analysis of 

industry-specific impacts discussed 

above examined the potential impacts of 

standards requiring a percent reduction 

in SOa emissions within specific 

industries at the manufacturing plant 

level. This analysis, however, was 

ble to assess potential impacts at the 

individual steam generating unit level. 

Consequently, the regulatory analysis 

also examined the cost and emission 

impacts associated with standards 

thing a percent reduction in SOa 

emissions and standards based on the 

use of low sulfur coal in terms of 

individual steam generating units. In this 

analysis, potential impacts were 

examined for individual steam 

generating units as a function of steam 

iting unit location, size, and 

capacity factor. As in the industryspecific economic impact analysis 

discussed above, this analysis also 

overlooks the possibility of fuel 

switching in response to a standard 

requiring a percent reduction in SOa 

emissions. Thus, for the same reasons 

mentioned above, this analysis should 

also be viewed as a "worse case" 

analysis in terms of potential impacts. 

To determine whether there were any 

significant differences associated with 

standards based on the use of low sulfur 

coal or standards requiring a percent 

iction in SO: emissions on individual 

steam generating units with differences 

in geographic location, impacts were 

ined for steam generating u: 

located in EPA Regions V and VIII. 

These regions were selected to represent 

i eastern and western geographic 

locations, respectively. Coal-fired steam 

generating units with heat input 

s of 29. 44. 73. and 117 MW 

(100.150. 250, and 400 million Btu/hour) 

operating at an annual capacity 

utilization factor of 0.6 were selected to 

represent typical coal-fired industrialcommercial-institutional steam 

generating units. The annual capacity 

utilization factor is defined as the actual 

annual heat input to the steam 

generating unit divided by the maximum 

annual heat input to the unit if it were 

operated at design capacity for 24 hours 

per day, 365 days per year (8.760 hours 

per yr 

The emission reductions achieved by 

alternative control levels or standards 

based on either the use of low sulfur 

coal or on a percent reduction in SO* 

emissions were calculated for each size 

of representative steam generating unit 

and are shown in Tables 6-11 and 6-12 

of "Summary of Regulatory Analysis" 

for a typical 44 MW (150 million Btu/ 

hour) unit. In Region V. an alternative 

control level or standard based on the 

use of low sulfur coal achieves SOa 

emission reductions of 410 Mg/year (460 

tons/year) over the regulatory baseline. 

An alternative control level or standard 

requiring a percent reduction in SO* 

emissions results in emission reductions 

of 600 Mg/year (660 tons/year) over the 

regulatory baseline. In Region VIII. an 

alternative control level or standard 

based on the use of low sulfur coal 

achieves SO* emission reductions of 410 

Mg/year (460 tons/year) over the 

regulatory baseline. An alternative 

control level or standard requiring a 

percent reduction in SOs emissions 

results in emission reductions of 800 

Mg/year (880 tons/year) over the 

regulatory baseline. Thus, the 

incremental annual emission reductions 

resulting from standards requiring a 

percent reduction in SOa emissions over 

standards based on the use of low sulfur 

coal for a typical 44 MW (150 million 

Btu/hour) heat input capacity steam 

generating unit would be 250 Mg/year 

(275 tons/year) in Region V and 390 Mg/ 

year (430 tons/year) in Region VIII. 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of Demonstrated 

Emission Control Technology Costs" 

and shown in Tables 6-13 and 6-14. the 

cost impacts associated with alternative 

control levels or standards based on the 

use of low sulfur coal, as well as 

alternative control levels or standards 

•ring a percent reduction in s 

emissions, were calculated for 

representative sizes of indivii 

generating units. Th' 

in the annualized costs of nev\ 

steam generating units over the 

regulatory baseline as a result of 

compliance with an alternative co 

level or stand.; on the uffl 

low sulfur coal is about 3 per 

Region V and about 2 percent in Ri 

V1I1 for all steam generating unit BI 

examined. The potenti.;1 in 

annualized costs as a result of 

compliance with an alternative control 

level or standard requiring a 

reduction in SO* emissions over the 

regulatory baseline ranges from 6 to 8 

percent in Region V and from H i 

percent in Region VIII. depending on 

steam generating unit s: 

incremental increase in annualize 

resulting from standards requiring a 

percent reduction in emissions 0 

standards based on the use of low 

coal wotdd be about 3 to 5 percenl in 

Region V and about 9 to 10 p< 

Region VIII, depending on steam 

generating unit size. 

On the basis of the emission 

reductions and potential annualizt 

increases noted above, the average cost 

effectiveness of standards based on the 

use of low sulfur coal in Region

 v 

between $430/Mg ($390/ton) and $470/ 

Mg ($430/ton) of SOa removed. For 

standards requiring a percent radui 

in SOa emissions, the average cost 

effectiveness in Region V ranged from 

$560/Mg ($510/ton) of SO« removed for 

a typical 117 MW (400 million Btu/hour) 

capacity unit to $930/Mg ($840/ton) of 

SOa removed for a typical 29 MW (100 

million Btu/hour) capacity unit. In 

Region VIII, the average cost 

effectiveness of standards based on the 

use of low sulfur coal is about $250/Mg 

($220/ton) of SOa removed for all steam 

generating unit sizes. For standards 

requiring a percent reduction in SOa 

emissions, the average cost 

effectiveness in Region VIII ranged from 

$670/Mg ($610/ton) of SOa removed for 

a typical 117 MW (400 million Btu/hour) 

capacity unit to $930/Mg ($840/ton) of 

SOa removed for a typical 29 MW (NX) 

million Btu/hour) capacity unit. 

In Region V. the incremental cost 

effectiveness of a standard requiring a 

percent reduction in SOa emissions over 

a standard based on the use of low 

sulfur coal ranges from $1,910/Mg 

($1.730/ton) of SOa removed for a 29 

MW (100 million Btu/hour) heat input 

capacity steam generating unit to $770/ 

Mg ($700/ton) of SOa removed for a 117 

MW (400 million Btu/hour) heat input 

capacity steam generating unit. 
P.13 

Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 

Similarly, in Region VIII the incremental 

cost effectiveness ranges from $1,820/ 

Mg to $1,210/Mg ($l,650/ton to $1,100/ 

ton) of SOa removed over the range of 

steam generating unit sizes examined. 

These results indicate that standards 

requiring a percent reduction in SO2 

emissions at typical coal-fired steam 

generating units (i.e., capacity utilization 

factors in the range of 0.6) achieve a 

significant reduction in emissions at a 

reasonable incremental cost compared 

to standards based on the use of low 

sulfur coal for all sizes of steam 

generating units examined. 

As mentioned above, the potential 

impacts of standards requiring a percent 

reduction in SO2 emissions and 

standards based on the use of low sulfur 

coal were also examined as a function 

of steam generating unit capacity 

utilization factor. In particular, impacts 

were examined for a new 44 MW (150 

million Btu/hour) heat input capacity 

coal-fired steam generating unit 

operated af an annual capacity 

utilization factor of 0.3 and also at an 

annual capacity utilization factor of 0.15. 

The emission reductions achieved by 

alternative control levels or standards 

based on either the use of low sulfur 

coal or on a percent reduction in SO2 . 

emissions were calculated for a 44 MW 

(150 million Btu/hour) unit located in 

Region V and operating at a capacity 

utilization factor of 0.30 and at a 

capacity utilization factor of 0.15. At a 

capacity utilization factor of 0.3, an 

alternative control level or standard 

based on the use of low sulfur coal 

achieves SO2 emission reductions of 205 

Mg/year (230 tons/year) over the 

regulatory baseline. An alternative 

control level or standard requiring a 

percent reduction in SO2 emissions 

results in emission reductions of 300 

Mg/year (330 tons/year) over the 

regulatory baseline. At a capacity 

utilization factor of 0.15, an alternative 

control level or standard based on the 

use of low sulfur coal achieves SO2 

emission reductions of 100 Mg/year (110 

tons/year) over the regulatory baseline. 

An alternative control level or standard 

requiring a percent reduction in SO2 

emissions results in emission reductions 

of 150 Mg/year (165 tons/year) over the 

regulatory baseline. The SO2 emission 

reductions associated with a standard 

requiring a percent reduction in SOa 

emissions are greater, therefore, than 

those associated with a standard based 

on the use of low sulfur coal. 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of Demonstrated 

Emission, Control Technology Costs" 

and shown in Tables 6-15 and 6-18, the 

potential increase over the regulatory 

baseline in annualized costs of a new 44 

MW (150 million Btu/hour) coal-fired 

steam generating unit associated with 

standards based on the use of low sulfur 

coal for steam generating units operated 

at low capacity utilization factors is 

about 2 percent or less in Region V and 

about 1 percent in Region VIII. The 

potential increase in annualized costs 

over the regulatory baseline associated 

with standards requiring a percent 

reduction in emissions is about 9 

percent in Region V and about 11 

percent or less in Region VIII. Thus, the 

incremental increase in annualized costs 

as a result of standards requiring a 

percent reduction in emissions over 

standards based on the use of low sulfur 

coal for steam generating units operating 

at low capacity utilization factors is 

about 7 to 8 percent in Region V and 

about 9 to 10 percent in Region VIII. 

The average cost effectiveness of 

standards based on the use of low sulfur 

coal remains essentially constant with 

respect to steam generating unit 

capacity utilization factor. For a 44 MW 

(150 million Btu/hour) heat input 

capacity coal-fired steam generating 

unit, the average cost effectiveness of 

standards based on the use of low sulfur 

coal is about $440/Mg ($400/ton) of SOa 

removed in Region V and about $280/ 

Mg ($250/ton) of SO2 removed in Region 

VIII. The average cost effectiveness of 

standards based on a percent reduction 

in SO2 emissions increases with 

decreasing steam generating unit 

capacity utilization factor. For a 44 MW 

(150 million Btu/hour) heat input 

capacity coal-fired steam generating 

unit located in Region V, the average 

cost effectiveness increases from $1,270/ 

Mg ($l,150/ton) of SOa removed at a 

capacity utilization factor of 0.3 to 

$2,130/Mg ($l,930/ton) of SO2 removed 

at a capacity utilization factor of 0.15. 

The incremental cost effectiveness of 

a standard requiring a percent reduction 

in SO2 emissions compared to a 

standard based on the use of low sulfur 

coal ranges from about $3,080/Mg 

($2,790/ton) of SOa removed for a new 

44 MW (150 million Btu/hour) heat input 

capacity coal-fired steam generating 

unit operating at a capacity utilization 

factor of 0.30 to about $5,ll6/Mg 

($4,640/ton) of SOa removed for this 

same size steam generating unit 

operating at a capacity utilization factor 

of 0.15 in Region V. Similarly, the 

incremental cost effectiveness ranges 

from about $2,420/Mg ($2,20O/ton) to 

about $3,950/Mg ($3,580/ton) of SOa 

removed in Region VIII. 

These results indicate that the annual 

emission reductions achieved under a 

standard requiring a percent reduction 

in SOa emissions compared to a 

standard based on the use of low sulfur 

coal decrease as steam generating unit 

capacity utilization factor decreases. 

The incremental annualized cost 

impacts increase and the incremental ' 

cost effectiveness increases significantly 

as capacity utilization factor decreases. 

As discussed above and in "Summary 

of Regulatory Analysis" under 

"Consideration of National Impacts," 

many steam generating units fire natural 

gas instead of coal in response to a 

standard requiring a percent reduction 

in SOa emissions. This fuel switching 

occurs predominantly in small steam 

generating units and in steam generating 

units operating at low capacity 

utilization factors. An examination of 

projected fuel selection as a function of 

steam generating unit capacity 

utilization factor indicates that even 

under the regulatory baseline no coalfired steam generating units are 

expected to operate at capacity 

utilization factors of less than 30 

percent. At such low capacity utilization 

factors, oil or natural gas are the fuels of 

choice even in the absence of standards 

of performance. The national impacts 

analysis, therefore, projects that little, if 

any, coal will be fired in new fossil fuelfired steam generating units operating at 

low capacity utilization factors even 

assuming a high coal penetration. 

In addition, those low capacity 

utilization factor steam generating units 

that might select coal would be most 

likely to fire natural gas instead of coal 

in response to standards requiring a 

percent reduction in SO2 emissions. As 

discussed in "Summary of Regulatory 

Analysis" under "Consideration of 

Demonstrated Emission Control 

Technology Costs" and as illustrated by 

Table 6-19, the costs and cost 

effectiveness of the emission reductions 

resulting from fuel switching are quite 

reasonable. Consequently, the analysis 

discussed above of the potential impacts 

of standards requiring a percent 

reduction in SO2 emissions on low 

capacity utilization factor steam 

generating units is considered 

misleading. As a result, the potential 

impacts of standards requiring a percent 

reduction in SOa emissions from coalfired'steam generating units, even those 

operating at low capacity utilization 

factors, are considered reasonable. 

The analyses of national impacts, 

impacts on specific industries, and 

impacts on individual steam generating 

units have shown that the impacts of a 

standard requiring a percent reduction 

in SOa emissions are reasonable when 

compared to standards based on the use 

of low sulfur coal and when compared 

to the regulatory baseline. No sizes, 
P.M 

Federal Register / Vol. 51, No. 118 / Thursday. June 19. 1986 / Proposed Rules 22-395 

types, or other categories of coal-fired 

steam generating units were 

distinguished for which a standard of 

performance including a percent 

reduction requirement would result in 

unreasonable impacts. Therefore, the 

basis of the standard for coal-fired 

industrial-commercial-institutional 

steam generating units with heat input 

capacities of greater than 29 MW (100 

million Btu/hour) is a percent reduction 

in SOa emissions. 

2. Selection of Standard for Coal-Fired 

Steam Generating Units 

A variety of technologies have been 

identified that are capable of 

continuously achieving a percent 

reduction in SOa emissions from coalfired steam generating units. As 

discussed in "Summary of Regulatory 

Analysis" under "Selection of 

Demonstrated Emission Control 

Technologies," these technologies 

include both combustion modification 

and post-combustion control. 

Combustion modification techniques 

for SOa control include coal/limestone 

pellets (CLP), limestone injection 

multistaged burners (LIMB), and 

fluidized bed combustion (FBC). As 

discussed in "Summary of Regulatory 

Analysis," CLP and LIMB are currently 

considered to be emerging rather than 

demonstrated technologies. The FBC 

system, however, is considered to be a 

demonstrated SOs control technology 

for purposes of developing NSPS. 

Post-combustion control technologies 

can be further divided into two groups: 

Wet and dry FGD. Wet FGD processes 

include lime, limestone, dual alkali, and 

sodium wet scrubbing. All wet FGD 

systems are considered demonstrated 

SOa control technologies for purposes of 

developing NSPS. Dry FGD processes 

ie electron beam irradiation, dry 

alkali injection, and lime spray drying. 

Of these, only lime spray drying is 

currently considered to be a 

demonstrated SOa control technology. 

Both short-term and long-term SOa 

emission test data were gathered to 

assess the performance of these 

demonstrated control technologies in 

reducing SOa emissions from coal-fired 

steam generating units. As discussed in 

"Summary of Regulatory Analysis" 

under "Performance of Demonstrated 

Emission Control Technologies." 

analysis of the data gathered on the 

performance of lime, limestone, dual 

alkali, and sodium FGD systems 

•-a tes that these technologies are 

pable of continuously achieving a 90 

cent reduction in SOa emissions from 

coal-fired steam generating units on a 

30-day rolling average basis. Therefore. 

a 90 percent reduction in SOa emissions 

from coal-fired steam generating units 

on a 30-day rolling average basis 

through the use of wet FGD technologies 

is considered demonstrated. 

Analysis of performance data 

gathered to assess the performance of 

FBC and lime spray drying technologies 

indicates that these technologies have 

the potential to achieve a 90 percent 

reduction in SOa emissions. Recently 

gathered long-term data from at least 

three FBC units presently operating 

indicate that FBC technologies are 

capable of continuously achieving a 90 

percent reduction in SOa emissions from 

coal-fired steam generating units on a 

30-day rolling average basis. Therefore, 

a 90 percent reduction in SOa emissions 

from coal-fired steam generating units 

on a 30-day rolling average basis 

through the use of FBC or lime spray 

drying technologies is considered 

demonstrated. 

The cost impacts associated with 

percent reduction requirements ranging 

from as low as 50 percent reduction to 

as high as 90 percent reduction were 

analyzed for coal-fired steam generating 

units at both the national level and at 

the individual steam generating unit 

level. These analyses are discussed in 

"Summary of Regulatory Analysis" 

under "Consideration of National 

Impacts" and "Consideration of 

Demonstrated Emission Control 

Technology Costs." 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of National Impacts." 

national annualized cost impacts were 

found to be relatively insensitive to 

variations in the specific level of the 

percent reduction requirement. For 

example, the national average cost 

effectiveness associated with a standard 

requiring a 50 percent reduction in SOa 

emissions is $110/Mg ($100/ton) of SOa 

removed for all new coal-fired steam 

generating units of greater than 29 MW 

(100 million Btu/hour) heat input 

capacity, compared to $120/Mg ($110/ 

ton) of SOa removed for standards 

requiring a 90 percent reduction in SOa 

emissions. However, SOa emissions 

under a 90 percent reduction 

requirement are reduced by an 

additional 13.000 Mg/year (14.000 tons/ 

year) below the emission levels 

achieved under a 50 percent reduction 

requirement. 

The cost impacts associated with a 

range of percent reduction requirements 

were also examined for a typical coalfired industrial-commercial-institutional 

steam generating unit with a heat input 

capacity of 44 MW (150 million Btu/ 

hour). As shown in Table 6-17 of 

"Summary of Regulatory Analysis," the 

annualized cost differences of operating 

an FGD system to achieve a 91 

reduction in SOa emissions versus a 50 

percent reduction in SOa emissions 

range from about $30.000/year for 

sulfur coal to about $210,000/ 

high sulfur coal. The corresponding 

incremental emission reduction* 

achieved under a 90 pert 

requirement range from 127 Mg/year 

(140 tons/year) for low sulf' 755 

Mg/year (830 tons/year) for high sulfur 

coal. The average cost effectiveness of 

operating an FGD system at 91 

reduction is $510 to $1.560/Mg ($460 to 

$1.420/ton) of SOJ re »red 

to $660 to $2.480/Mg ($600 to $2.250/!< • 

of SOa removed for an FGD systt 

operated at 50 percent re 

Both analyses, therefore, lead to 

same conclusion: a 90 percent reduction 

requirement is more 

lower percent reduction requirementsAs discussed in "Summary of 

Regulatory Analysis" un 

"Consideration of Demonstrated 

Emission Control Technology Costs," 

this result emerges because the only 

increased costs associated with 

operating an FGD system to achieve a 

relatively high percent red u .Oa 

emissions are the increased costs 

resulting from increase its and 

utilities consumption and increased 

waste disposal costs. These mere, 

costs are incremental in nature and 

relatively small. However, the increased 

reduction in SOa emissions resulting 

from operation at a high percent 

reduction level is quite significant. 

In addition, in the national 

analysis, the cost el a of a 90 

percent reduction 

to the cost effectiveness of a Iov\ 

percent reduction requirement 

influenced by fuel switching. As 

discussed in "Summary of Ri > 

Analysis" under "Con. of 

National Impacts.' Fuel 

switching from coal to natural gas in 

response to percent reduction 

requirements tends to >•• • he 

resulting cost effectiveness of SOa 

control. While the increased DOS 

associated with operating an F< 

system at a high percent i are 

relatively small, in some cases these 

increased costs are suff; tuse 

some additional steam generating units 

to fire natural gas it This 

tends to decrease further the cost 

effectiveness of SOa control associa! 

with the 90 percent I 

requirement. 

Consequently, in both the n 

impact and individual steam gr 

unit impact analyses, a 90 per 

reduction requirement emerges as more 
PAS 

22396 Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 

cost effective than lower percent 

reduction requirements. 

As discussed above, the ability of wet 

FGD technologies, lime spray drying 

systems, and FBC systems to achieve 

SO2 emission reductions of 90 percent 

on a 30-day rolling average basis is 

considered demonstrated. Thus, a 90 

percent reduction standard has been 

selected for new coal-fired steam 

generating units of greater than 29 MW 

(100 million Btu/hour) heat input 

capacity (except for units using 

emerging technologies, as discussed 

below). 

One of the objectives of the Clean Air 

Act Amendments of 1977 was to 

encourage the use of locally available 

high sulfur coals. This objective was 

taken into consideration in selecting the 

SO2 emission limit associated with the 

percent reduction requirements. 

An analysis of U.S. coal reserve data 

indicates that only about 80 percent of 

U.S. raw coal reserves could be used to 

comply with a standard requiring a 90 

percent reduction in SO2 emissions and 

an emission limit of 258 ng SO2/J (0.6 lb 

SOi/million Btu) heat input. However, 

about 98 percent of U.S. raw coal 

reserves could be used to comply with a 

standard requiring a 90 percent 

reduction in SO2 emissions and an 

emission limit of 516 ng SO2/J (1-2 lb 

SO2 /million Btu) heat input. Therefore, 

an emission limit of 516 ng SO2/J (1.2 lb 

SQj/million Btu) heat input has been 

selected as the emission limit included 

with the 90 percent reduction 

requirement for coal-fired industrialcommercial-institutional steam 

generating units. 

These standards reflect the use of the 

best technological system of continuous 

SO2 emission reduction for coal-fired 

steam generating units. It is 

questionable, however, whether these 

standards are achievable by many 

emerging technologies at their current 

state of development. The very nature of 

emerging technologies prevents any 

quantitative assessment of their 

performance or costs. As a result, the 

regulatory analysis could not consider 

the potential impacts of alternative 

standards on the continued development 

of emerging technologies. Some 

emerging SO2 control technologies, 

however, show promise of achieving 

greater emission control, or equivalent 

levels of control at substantially lower 

costs, than demonstrated technologies. 

Therefore, it is desirable that standards 

of performance accommodate and foster 

the continued development of emerging 

technologies. 

It is quite likely that a requirement 

that all coal-fired industrialcommercial-institutional steam 

generating units with heat input 

capacities greater than 29 MW (100 

million Btu/hour) achieve a minimum 90 

percent reduction in SO2 emissions 

would discourage the continued 

development of most emerging 

technologies. Owners and operators of 

new coal-fired steam generating units 

would likely view the risks of using an 

SO2 control technology that has not' 

been fully demonstrated to consistently 

achieve a 90 percent reduction in 

emissions as too great, and would, 

therefore, employ conventional 

demonstrated control technologies. 

If, on the other hand, standards of 

performance were established that 

would allow emerging technologies to 

achieve lower percent reductions, these 

risks would be substantially reduced. 

Establishing less stringent percent 

reduction requirements for emerging 

technologies substantially increases the 

likelihood that owners and operators of 

new coal-fired industrial- commercialinstitutional steam generating units will 

install and operate emerging 

technologies. The experience gained in 

utilizing emerging technologies will, in 

turn, foster their continued development 

while simultaneously reducing the 

perceived risks associated with their 

use. 

Three alternative approaches were 

considered for accommodating the 

development and use of emerging SO2 

control technologies. The first 

alternative involved provisions for 

granting permits for less stringent 

percent reduction requirements to 

emerging technologies on a case-by-case 

basis. Under this alternative, owners or 

operators of new coal-fired steam. 

generating units wishing to use an 

emerging SOs control technology could 

apply for a permit to operate the 

technology at a percent reduction less 

than that specified in the standards. 

Emerging technology permits would 

have the advantage of enabling levels of 

performance to be specified that reflect 

the best level of performance achievable 

by each technology for which a permit is 

issued. 

Such an approach would require 

operation of conventional demonstrated 

technologies at high performance levels, 

but would permit emerging technologies 

to operate at lower performance levels. 

The major disadvantage associated with 

this alternative would be the substantial 

administrative burdens of preparing and 

reviewing applications for permits. A 

separate application would need to be 

submitted for each installation of an 

emerging technology and individual 

determinations would need to be made 

as to the most appropriate standard to 

apply in each case. The uncertainties 

inherent in case-by-case evaluations 

and the time required to apply for and 

receive a permit could effectively 

discourage the development and use of 

emerging technologies. 

Another approach for accommodating 

emerging technologies would be the 

establishment of a "sliding scale" 

percent reduction requirement for all 

SO2 control technologies, such as that 

included in the NSPS for electric utility 

steam generating units (40 CFR Part 60, 

Subpart Da). Under a sliding scale 

percent reduction requirement, an owner 

or operator could comply with either a 

standard including a relatively more 

stringent percent reduction requirement 

and a less stringent emission limit, or 

with a standard including a relatively 

less stringent percent reduction 

requirement and a more stringent 

emission limit. Such an approach would 

allow an owner or operator to fire coals 

with lower sulfur contents and comply 

with a relatively less stringent percent 

reduction requirement. Thus, emerging 

technologies could be operated at lower 

performance levels if low sulfur coal 

were fired. Without restricting a sliding 

scale percent reduction requirement to 

emerging technologies, however, this 

approach would also permit 

conventional demonstrated SO2 control 

technologies to be operated at 

considerably less than the control levels 

that these technologies have clearly 

demonstrated. 

The third alternative considered 

would allow emerging technologies to 

achieve a minimum 'designated percent 

reduction in SO2 emissions that is lower 

than that for demonstrated technologies. 

Conventional demonstrated 

technologies, however, would always be 

required to operate at the 90 percent 

reduction performance level discussed 

above. 

Designating less stringent percent 

reduction requirements for emerging SO2 

control technologies would eliminate the 

need for a case-by-case permitting 

process and the accompanying 

administrative burdens. This less 

burdensome approach would be more 

likely to encourage the development and 

use of emerging SOj control 

technologies without allowing 

conventional demonstrated technologies 

to be operated at performance levels 

less than those that have been 

demonstrated. 

After considering each of the above 

alternatives for accommodating 

emerging technologies, designating 

lower percent reduction requirements 

for emerging.technologies was selected 

as the regulatory approach best suited to 
P.16 

Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 

encouraging development and use of 

emerging technologies. 

As discussed above, CLP, LIMB, 

electron beam irradiation, and dry alkali 

injection are considered examples of 

emerging technologies. This "list" is by 

no means complete, however, and many 

other technologies for SOa control are 

under development or may be developed 

in the future. 

To encourage the continued 

development of emerging technologies, a 

percent reduction requirement should be 

set low enough to be reasonably 

attainable, but high enough to ensure 

that a minimum level of SO2 emissions 

control is achieved. Although this is a 

matter of judgment, a minimum percent 

reduction requirement of 50 percent is 

considered appropriate for this purpose. 

Therefore, the proposed standards 

would require all new, modified, or 

reconstructed coal-fired industrialcommercial-institutional steam 

generating units with heat input 

capacities of greater than 29 MW (100 

million Btu/hour) employing emerging 

SO2 control technologies to achieve a 

minimum of 50 percent reduction in SO2 

emissions on a 30-day rolling average 

basis. 

This percent reduction requirement is 

considerably less stringent than the 90 

percent reduction requirement based on 

conventional demonstrated SO2 

emission.control technologies. While it 

is considered desirable to encourage 

and foster continued development of 

emerging SO2 emission control 

technologies, the use of such 

technologies should be limited to 

combustion of low sulfur coals. This will 

minimize any increase in SO2 emissions 

at a coal-fired steam generating unit as a 

result of the use of an emerging 

technology. Therefore, an emission limit 

of 258 ng SO2/J (0.6 lb SOa/million Btu) 

has been selected as the emission limit 

associated with the percent reduction 

requirement for emerging technologies. 

Selection of this SO2 emission limit 

restricts the use of emerging 

technologies achieving the minimum 

percent reduction in SO2 emissions to 

steam generating units firing coal with a 

sulfur content of 516 ng SO2/J (1.2 lb 

S02/million Btu) heat input or less. 

However, to the extent that an emerging 

technology could achieve SO2 emission 

reductions of greater than 50 percent, 

coals with higher sulfur contents could 

be fired without exceeding this emission 

lirr.it. Because higher sulfur coals are 

generally less expensive than low sulfur 

coals, this will act as an incentive to 

achieve percent reductions of greater 

than 50 percent. 

The proposed standard, therefore, 

provides a limited "window" for use of 

emerging technologies. This window will 

be reviewed regularly during the course 

of the review process associated with all 

NSPS. As appropriate, the percent 

reduction requirements will be revised 

upwards in light of additional 

performance data available at that time 

for various emerging technologies. As a 

result of these reviews, emerging control 

technologies that do not demonstrate 

improvements in performance 

capabilities, or show no promise of 

achieving emission reductions greater 

than 50 percent, will no longer be 

considered emerging technologies and 

all subsequent installations would be 

subjected to the same requirements as 

those included in the standards for 

conventional demonstrated control 

technologies. 

3. Basis of Standard for Oil-Fired Steam 

Generating Units 

The regulatory analysis for oil-fired 

steam generating units was conducted in 

the same manner as that described 

above for coal-fired steam generating 

units. The potential impacts of NSPS on 

oil-fired steam generating units were 

examined from the perspectives of 

overall national impacts, impacts on 

specific industries subject to the 

standards, and impacts on individual 

steam generating units subject to the 

standards. Each of these perspectives is 

discussed below. 

National Impacts. As mentioned 

above and discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of National Impacts," 

the national impacts associated with 

NSPS for fossil fuel-fired steam 

generating units were analyzed through 

the use of the computer model, IFCAM. 

As also noted above, the high oil 

penetration scenario was used to assess 

the potential impacts of standards 

limiting SO2 emissions from oil-fired 

steam generating units. Similar to the 

analysis for coal-fired steam generating 

units, a set of regulatory alternatives or 

alternative standards was structured fo 

examine impacts as a function of steam 

generating unit size (heat input 

capacity). 

The-regulatory alternatives become 

progressively more stringent by first 

requiring only steam generating units 

with heat input capacities above 73 MW 

(250 million Btu/hour) to achieve a 

percent reduction in SOa emissions, but 

then requiring steam generating units 

with progressively lower heat input 

capacities to achieve a percent 

reduction in SO2 emissions as well. The 

most stringent regulatory alternative 

requires all oil-fired industrialcommercial-institutional steam 

generating units with heat input 

capacities of greater than 29 MW (1C0 

million Btu/hour) to achieve a percent 

reduction in SOa emissions. The least 

stringent regulatory alternatives are 

based on the use of low sulfur oil to 

meet emission limits of 688 and 344 ng 

SO2/J (1.6 and 0.8 lb SOa/million Btu) 

heat input, respectively, for all oil-fired 

industrial-commercial-institutional 

steam generating units with heat input 

capacities of greater than 29 MW (100 

million Btu/houi1). 

A summary of the national impacts 

associated with each regulatory 

alternative is shown in Table 8-7 of 

"Summary of Regulatory Analysis." Aa 

discussed in "Summary of Regulatory 

Analysis" under "Consideration of 

National Impacts" and assuming a high 

oil penetration in new fossil fuel-fired 

steam generating units, standards based 

on the use of low sulfur oil to meet an 

emission limit of 688 ng SOa/J (1.6 lb 

SOa/million Btu) heat input for all new 

oil-fired steam generating units with 

heat input capacities greater than 29 

MW (100 million Btu/hour) result in a 

projected reduction in SOa emissions of 

67,000 Mg/year (74,000 tons/year) over 

the regulatory baseline in the fifth year 

following proposal of standards (i.e., 

1990). Standards based on the use of low 

sulfur oil to meet an emission limit of 

344 ng SOa/J (0.8 lb SOa/million Btu) 

heat input for all new oil-fired steam 

generating units with heat input 

capacities greater than 29 MW (100 

million Btu/hour) would result in 

projected SOa emission reductions of 

157,000 Mg/year (173,000 tons/year) 

over the regulatory baseline in 1990. In 

comparison, standards requiring all new 

oil-fired steam generating units with 

heat input capacities greater than 29 

MW (100 million Btu/hour) to achievo a 

percent reduction in emissions result in 

projected SO2 emission reductions of 

239,000 Mg/year (263,000 tons/year) 

over the regulatory baseline in 19S0. 

The difference in projected national 

SOa emission reductions between 

standards based on the use of low sulfur 

oil to meet an emission limit of 344 ng 

SOa/J (0.8 lb SOa/million Btu) heat input 

and standards requiring a percent 

reduction in emissions is about 82,000 

Mg/year (90,000 tons/year). About onethird of this difference (30,000 Mg/year) 

results from standards requiring all new 

oil-fired steam generating units with 

heat input capacities greater than 73 

MW (250 million Btu/hour) to achieve a 

percent reduction in SOa emissions. 

Additional national SOa emission 

reductions of 10,000 Mg/year (11,000 

tons/year), 19,000 Mg/year (21,000 tons/ 

year), and 22,000 Mg/year (24,000 tons/ 

year) in 1990 result from requiring all 
P.17 

22398 Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 

new oil-fired steam generating units 

with heat input capacities greater than 

58 MW (200 million Btu/hour), 44 MW 

(150 million Btu/hour), and 29 MW (100 

million Btu/hour), respectively, to 

achieve a percent reduction in SOa 

emissions. 

This analysis, therefore, projects that 

standards requiring all new oil-fired 

steam generating units to achieve a 

percent reduction in SOa emissions 

achieve greater reductions in national 

SOa emissions than standards based on 

the use of low sulfur oil. Moreover, 

• standards that require all new oil-fired 

steam generating units with heat input 

capacities greater than 29 MW (100 

million Btu/hour) to achieve a percent 

reduction in SO2 emissions result in 

significantly greater national SO2 

emission reductions than standards 

requiring only relatively larger oil-fired 

steam generating units to achieve a 

percent reduction in SOa emissions. 

As is also shown in Table 8-7 of 

"Summary of Regulatory Analysis," 

assuming a high oil penetration in new 

fossil fuel-fired steam generating units, 

NSPS based on the use of low sulfur oil 

to meet an emission limit of 688 ng SO2/J 

(1.6 lb SOa/million Btu) heat input for 

new oil-fired steam generating units 

with heat input capacities greater than 

29 MW (100 million Btu/hour) result in 

projected national annualized cost 

increases of $8 million/year over the 

regulatory baseline in 1990. Standards 

based on the use of low sulfur oil to 

meet an emission limit of 344 ng SO2/J 

(0.8 lb SOa/million Btu) heat input for all 

new oil-fired steam generating units 

with heat input capacities greater than 

29 MW (100 million Btu/hour) result in 

projected annualized cost increases of 

$57 million/year over the regulatory 

baseline in 1990. These represent 

increases of about 0.2 and 1.7 percent, 

respectively, in the total national 

annualized costs associated with 

operation of all new fossil fuel-fired 

steam generating units projected to be 

constructed between 1986 and 1990. 

In comparison, standards requiring all 

new oil-fired steam generating units 

with heat input capacities greater than 

29 MW (100 million Btu/hour) to achieve 

a percent reduction in SOa emissions 

result in projected national annualized 

cost increases of about $133 million/ 

year over the regulatory baseline in 

1990. This represents an increase in total 

national annualized costs of about 4 

percent. 

The difference in projected increases 

in total national annualized costs 

between standards based on the use of 

low sulfur oil to meet an emission limit 

of 344 ng SOa/J (0.8 lb SOa/million Btu) 

and standards requiring all new oil-fired 

steam generating units with heat input 

capacities greater than 29 MW (100 

million Btu/hour) to achieve a percent 

reduction in emissions is about $76 

million/year in 1990. This represents a 

difference in total national annualized 

costs of about 2 percent. Of this, about 

half ($39 million/year) results from 

standards requiring all new oil-fired 

steam generating units with heat input 

capacities greater than 73 MW (250 

million Btu/hour) to achieve a percent 

reduction in SOa emissions. Additional 

annualized costs of $5 million/year, $14 

million/year, and $18 million/year result 

from standards requiring new oil-fired 

steam generating units with heat input 

capacities greater than 58 MW (200 

million Btu/hour), 44 MW (150 million 

Btu/hour), and 29 MW (100 million Btu/ 

hour), respectively, to achieve a percent 

reduction in SOa emissions. 

Under the assumption of high oil 

penetration in new fossil fuel-fired 

steam generating units, therefore, this 

analysis indicates that the increase in 

total national annualized costs 

associated with standards requiring all 

new oil-fired steam generating units to 

achieve a percent reduction in SOa 

emissions is small compared to the 

national annualized costs associated 

with standards based on the use of low 

sulfur oil. 

Based on the projected national 

emission reductions and annualized cost 

increases described above, the national 

average cost effectiveness of NSPS 

based on the use of low sulfur oil to 

meet an emission limit of 688 ng SO2/J 

(1.6 lb SOa/million Btu) heat input for 

new oil-fired steam generating units 

with heat input capacities greater than 

29 MW (100 million Btu/hour) is about 

$120/Mg ($110/ton) of SOa removed. The 

average cost effectiveness of standards 

based on the use of low sulfur oil to 

meet an emission limit of 344 ng SOa/J 

(0.8 lb SOa/million Btu) heat input for all 

new oil-fired steam generating units 

with heat input capacities greater than 

29 MW (100 million Btu/hour) is about 

$360/Mg ($330/ton) of SOa removed. In 

comparison, the national average cost 

effectiveness of standards requiring all 

new oil-fired steam generating units 

with heat input capacities greater than 

29 MW (100 million Btu/hour) to achieve 

a percent reduction in SOa emissions is 

about $560/Mg ($510/ ton) of SOa 

removed. 

The national incremental cost 

effectiveness of a standard based on the 

use of low sulfur oil to meet an emission 

limit of 344 ng SOa/J (0.8 lb SOa/million 

Btu) heat input for all new oil-fired 

steam generating units with heat input 

capacities greater than 29 MW (100 

million Btu/hour) over a standard based 

on the use of low sulfur oil to meet an 

emission limit of 688 ng SOa/J (1.6 lb 

SOa/million Btu) heat input for new oilfired steam generating units with heat 

input capacities greater than 29 MW 

(100 million Btu/hour) is about $550/Mg 

($500/ton) of SOa removed. 

The national incremental cost 

effectiveness of a standard requiring all 

new oil-fired steam generating units to 

achieve a percent reduction in SOa 

emissions over a standard based on the 

use of low sulfur oil to meet an emission 

limit of 344 ng SOa/J (0.8 lb SOa/million 

Btu) heat input is about $920/Mg ($840/ 

ton) of SOa removed. As discussed in 

"Summary of Regulatory Analysis" 

under "Consideration of National 

Impacts" and shown in Table 8-7, this is 

considerably less than the national 

incremental cost effectiveness (about 

$1,270/Mg of SOa removed) of a 

standard requiring only new oil-fired 

steam generating units with heat input 

capacities greater than 73 MW (250 

million Btu/hour) to achieve a percent 

reduction in emissions over a standard 

based on the use of low sulfur oil to 

meet an emission limit of 344 ng SOa/J 

(0.8 lb SOa/million Btu) heat input for all 

new oil-fired steam generating units. 

The national incremental cost 

effectiveness of a standard requiring all 

new oil-fired steam generating units 

with heat input capacities greater than 

29 MW (100 million Btu/hour) to achieve 

a percent reduction in SOa emissions 

over the next most stringent regulatory 

alternative, requiring only new oil-fired 

steam generating units with heat input 

capacities greater than 44 MW (150 

million Btu/hour) to achieve a percent 

reduction in SOa emissions, is $820/Mg 

($750/ton) of SOa removed. 

As discussed above for coal-fired 

steam-generating units, this apparent 

anomaly of decreasing national 

incremental cost effectiveness with 

increasingly stringent regulatory 

alternatives results from the larger 

number of natural gas-fired steam 

generating units that are projected under 

increasingly stringent standards. 

Although under the high oil penetration 

scenario national annualized costs 

generally increase in response to 

increasingly stringent standards, firing 

natural gas instead of oil results in 

proportionally larger reductions in SOa 

emissions. As a result, the national 

incremental cost effectiveness of 

increasingly stringent standards can 

decrease. 

Under the assumption of high oil 

penetration in new fossil fuel-fired 

steam generating units, therefore, this 

analysis indicates that the national 

average cost effectiveness of standards 
P.18 

Federal Register / Vol. 51. No. 118 / Thursday. June 19, 1986 / Proposed Rules 22399 

requiring new oil-fired steam generating 

units to achieve a percent reduction in 

SOj emissions is not substantially 

higher than the national average cost 

effectiveness of standards based on the 

use of low sulfur oil. In addition, this 

analysis also indicates that standards 

requiring all new oil-fired steam 

generating units with heat input 

capacities of greater than 29 MW (100 

million Btu/hour) to achieve a percent 

reduction in SOs emissions are as cost 

effective as alternative standards 

requiring only relatively larger units to 

achieve a percent reduction in SOs 

emissions. 

As also discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of National Impacts" 

and shown in Table 8-7, assuming a 

high oil penetration in new fossil fuelfired steam generating units, the 

regulatory alternative based on the use 

of low sulfur oil to meet an emission 

limit of 344 ng SOa/J (0.8 lb SOa/million 

Btu) heat input for all new oil-fired 

steam generating units with heat input 

capacities of greater than 29 MW (100 

million Btu/hour) results in a projected 

reduction in national oil use of about 70 

million GJ/year (66 trillion Btu/year) in 

1990 compared to the regulatory 

baseline. Under the regulatory 

alternative requiring all new oil-fired 

steam generating units with heat input 

capacities of greater than 29 MW (100 

million Btu/hour) to achieve a percent 

reduction in SOa emissions, national oil 

use is projected to decline by about 155 

million GJ/year (145 trillion Btu/year) in 

1990 compared to the regulatory 

baseline. This decline in oil use is 

projected to be offset by a nearly 

equivalent increase in natural gas use. 

Of the difference between these two 

alternatives in projected reductions in 

national oil use (about 79 trillion Btu/ 

year), about one-half (40 trillion Btu/ 

year) results from standards requiring 

oil-fired steam generating units with 

heat input capacities greater than 73 

MW (250 million Btu/hour) to achieve a 

percent reduction in emissions. 

Similarly, most of the remaining 

difference in projected reductions in 

national oil use (about 26 trillion Btu/ 

year) results from standards requiring 

all oil-fired steam generating units with 

heat input capacities greater than 29 

MW (100 million Btu/hour) to achieve a 

percent reduction in SOJ emissions. As 

discussed previously for coal-fired units, 

however, these reductions in oil use, and 

the corresponding increases in natural 

gas use. represent very small 

percentages of existing consumption of 

oil and natural gas in the industrial 

sector. 

Assuming a high oil penetration in 

new fossil fuel-fired steam generating 

units, therefore, this analysis indicates 

that the potential impact of standards 

requiring a percent reduction in SOa 

emissions for all new oil-fired steam 

generating units with heat input 

capacities of greater than 29 MW (100 

million Btu/hour) on projected national 

oil and natural gas consumption by the 

industrial sector in 1990 is small. 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of Secondary 

Environmental Impacts," potential 

secondary environmental impacts 

associated with standards of 

performance that include a percent 

reduction requirement have also been 

analyzed. These potential secondary 

environmental impacts include liquid 

and solid waste impacts. 

The impacts of various regulatory 

alternatives on the generation and 

disposal of solid and liquid wastes were 

examined at the national level. As 

shown in Table 8-7 of "Summary of 

Regulatory Analysis," assuming a high 

oil penetration in new fossil fuel-fired 

steam generating units, regulatory 

alternatives requiring a percent 

reduction in SO* emissions result in 

somewhat greater quantities of liquid 

waste compared to regulatory 

alternatives based on the use of low 

sulfur fuels. The table also indicates that 

the solid waste impacts are relatively 

small and do not differ significantly 

among the regulatory alternatives. 

As discussed previously for coal-fired 

steam generating units and in "Summary 

of Regulatory Analysis" under 

"Consideration of Secondary 

Environmental Impacts." industrialcommercial-institutional steam 

generating units are generally part of a 

manufacturing plant which generates 

substantial amounts of liquid and solid 

waste from the manufacturing process 

itself. Therefore, the amount of waste 

generated by the control of SOa 

emissions from these steam generating 

units would represent only a small 

portion of the total wastes generated by 

the plant in most cases. As discussed 

previously for coal-fired steam 

generating units, the projected liquid 

and solid waste impacts reflect the 

IFCAM assumption that sodium 

scrubbing would generally be the SOa 

control system used to achieve a percent 

reduction in SOa emissions. To the 

extent that other FGD technologies 

(such as dual alkali) are selected to 

comply with a standard requiring a 

percent reduction in SOa emissions, the 

amount of liquid waste would decrease 

and the amount of solid waste would 

increase. 

The constituents of the FCD waste 

byproducts are not classified as toxic or 

hazardous under RCRA and can ' 

easily disposed of, along with the 1 

plant wastes, by conventional methods. 

The nontoxic and nonhazardous nature 

of the FGD wastes permits their di»p< 

using conventional techniques such as 

ponding, landfilling, sewerage, or dir: 

discharge. Therefore, the use of Ft 

systems to achieve W 

in SO3 emissions would not result in 

unreasonable adverse environmental 

impacts. 

Industry-Specific Economic Inifh 

The analysis discussed above of 

potential national impacts associ 

with standards- iance for new 

oil-fired steam generating units 

represents an assessment of the 

aggregate nationwide impact of 

standards requiring a percent reduction 

in SOa emissions. Because of 

aggregate nature of this analysis of 

national impacts, it was unable to 

assess the potential impacts of 

standards requiring a percent reduct' 

in SO* emissions on spe( 

sectors within the national economy. 

Accordingly. Uie potential econoi 

impacts of a standard requiring a 

percent reduction in SO* emissions on 

major industrial steam users were also 

considered. 

As shown in Tables 6-17 and 6-29 in 

"Summary of Regulatory Analysis". 1 

annualized costs associated with 

achieving a percent reduction in SOi 

emissions from a coal-fired steam 

generating unit are greater t 

annualized costs associated with 

achieving a percent reduction in SOa 

emissions from an oil-fired steam 

generating unit. The increas 

annualized cost for a coal-fired steam 

generating unit, for example, is about 

$500.000/year for a unit firing low sulfur 

coal and about $900.000/year for a unit 

firing high sulfur coal. For an oil ' 

steam generating unit, the c 

costs range from about $380.000/yeii' 

about $575,000/year. Consequently, tl 

industry-specific economic impacts 

associated with alternative standards 

for oil-fired steam generating units 

would be smaller than those as-: 

with alternative standards > 

steam generating units. 

As discussed above for coal fi' 

steam generating units, the "woi: 

analysis of potential industry-spci 

economic impacts of stand. 

a percent reduction in SOa emissions 

indicates that the resulting increase: 

product prices could range from I 

than 0.1 percent to 1.5 percent. Bimil 
P.19 

22400 Federal Register / Vol. 51, No. 118 /Thursday, June 19, 1986 / Proposed Rules 

assuming full cost absorption, potential 

increases in product value added range 

from less than 0.1 percent to 5.0 percent, 

and potential decreases in 

manufacturing plant profitability or 

return on assets range from les9 than 0.1 

to 2.8 percentage points. 

As mentioned above, none of these 

industry-specific impacts associated 

with a standard requiring a percent 

reduction in SOa emissions from coalfired steam generating units is 

considered unreasonable. The 

annualized costs associated with 

achieving a percent reduction in SOa 

emissions from oil-fired steam 

generating units are smaller than the 

annualized costs associated with 

achieving a percent reduction in SOa 

emissions from coal-fired steam 

generating units. As a result, none of the 

industry-specific impacts associated 

with standards requiring a percent 

reduction in SO2 emissions from oil-fired 

steam generating units are considered 

unreasonable. 

Impacts on Individual Steam 

Generating Units. Finally, the regulatory 

analysis examined the cost and 

emission impacts associated with 

standards requiring a percent reduction 

in SOa. emissions and standards based 

on the use of low sulfur oil in terms of 

individual steam generating units. In this 

analysis, potential impacts were 

examined for individual steam 

generating units as a function of steam 

generating unit size and capacity factor. 

Impacts as a function of geographic 

location were not examined because the 

price differential among oils with 

varying sulfur contents was generally 

assumed to be relatively uniform 

regardless of location. 

As in the analysis discussed above for 

coal-fired steam generating units, the 

analysis of impacts on individual steam 

generating units overlooks the 

possibility of fuel switching in response 

to a standard requiring a percent 

reduction in SO2 emissions. Thus, this 

analysis should be viewed as a "worse 

case" analysis in terms of potential 

impacts. 

Oil-fired steam generating units with 

heat input capacities of 29, 44, 73, and 

117 MW (100,150, 250, and 400 million 

Btu/hour) operating at a capacity 

utilization factor of 0.55 were selected to 

represent typical oil-fired industrialcommercial-institutional steam 

generating units. 

The emission reductions achieved by 

alternative control levels or standards 

based on either the use of low sulfur oil 

or on a percent reduction in SOa 

emissions were calculated for each size 

of representative steam generating unit 

and are shown in Table 6-26 of 

"Summary of Regulatory Analysis" for a 

typical 44 MW (150 million Btu/hour) 

heat input capacity unit. As shown in 

this table, an alternative control level 

based on the use of very low sulfur oil 

(i.e., 0.3 lb SOa/million Btu heat input) 

has essentially the same impact as an 

alternative control level requiring a 

percent reduction in SOa emissions. It is 

less costly on an annual basis to install 

and operate an FGD system and burn 

high sulfur oil than it is to buy very low 

sulfur oil. Thus, for typical oil-fired 

steam generating units, the impacts 

associated with a standard based on the 

use of very low sulfur oil are essentially 

the same as the impacts associated with 

a standard requiring a percent reduction 

in SOa emissions. 

As shown in Table 6-26, an 

alternative control level or standard 

based on the use of low sulfur oil to 

meet an emission limit of 688 ng SOa/J 

(1.8 lb SOa/million Btu) heat input 

achieves an SOa emission reduction of 

450 Mg/year (500 tons/year) over the 

regulatory baseline for a typical 44 MW 

(150 million Btu/hour) heat input 

capacity steam generating unit. An 

alternative control level or standard 

based on the use of low sulfur oil to 

meet an emission limit of 344 ng SOa/J 

(0.8 lb SOa/million Btu) heat input 

achieves an SOa emission reduction of 

720 Mg/year (790 tons/year) over the 

regulatory baseline. An alternative 

control level or standard requiring a 

percent reduction in SOa emissions 

(which is equivalent to an alternative 

control level or standard based on the 

use of very low sulfur oil) results in an 

emission reduction of 890 Mg/year (950 

tons/year) over the regulatory baseline. 

The incremental annual emission 

reductions resulting from standards 

requiring a percent reduction in SOa 

emissions or standards based on the use 

of very low sulfur oil to meet an 

emission limit of 129 ng SOa/J (0.3 lb 

SOa/million Btu) heat input over 

standards based on the use of low sulfur 

oil to meet an emission limit of 344 ng 

SOa/J (0.8 lb SOa/million Btu) heat input 

for a typical 44 MW (150 million Btu/ 

hour) heat input capacity steam 

generating unit would be 170 Mg/year 

(190 tons/year). 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of Demonstrated 

Emission Control Technology Costs" 

and shown in Table 6-27* the cost 

impacts associated with alternative 

control levels or standards based on the 

use of low sulfur oil as well as with 

alternative control levels or standards 

requiring a percent reduction in SOa 

emissions were calculated for 

representative sizes of individual steam 

generating units. The potential increase 

in the annualized costs of new oil-fired 

steam generating units over the 

regulatory baseline as a result of 

compliance with an alternative control 

level or standard based on the use of 

low sulfur oil to meet an emission limit 

of 688 ng SOa/J (1.6 lb SOa/million Btu) 

heat input is about 5 percent for all 

steam generating unit sizes examined. 

The potential increase in the annualized 

costs of new oil-fired steam generating 

units over the regulatory baseline as a 

result of compliance with an alternative 

control level or standard based on the 

use of low sulfur oil to meet an emission 

limit of 344 ng SOa/J (0.8 lb SOa/million 

Btu) heat input is between 9 and 11 

percent. The potential increase in 

annualized costs as a result of 

compliance with an alternative control 

level or standard based on the use of 

very low sulfur oil to meet an emission 

limit of 129 ng SOa/J (0.3 lb SOa/million 

Btu) heat input, or an alternative control 

level or standard requiring a percent 

reduction in SOa emissions, over the 

regulatory baseline ranges from about 10 

to 12 percent, depending on steam 

generating unit size. 

The incremental increase in 

annualized costs resulting from 

standards based on the use of very low 

sulfur oil to meet an emission limit of 

129 ng SOa/J (0.3 lb SOa/million Btu) 

heat input or standards requiring a 

percent reduction in emissions over 

standards based on the use of low sulfur 

oil to meet an emission limit of 344 ng 

SOa/J (0.8 SOa/million Btu) heat input 

would be about 6 to 7 percent, 

depending on steam generating unit size. 

On the basis of the emission 

reductions and potential annualized cost 

increases noted above, the average cost 

effectiveness of standards based on the 

use of low sulfur oil to meet an emission 

limit of 688 ng SOa/J (1.6 lb SOa/million 

Btu) heat input is between $460/Mg 

($420/ton) and $480/Mg ($440/ton) of 

SOa removed. The average cost 

effectiveness of standards based on the 

use of low sulfur oil to meet an emission 

limit of 344 ng SOa/J (0.8 lb SOa/million 

Btu) heat input is between $550/Mg 

($500/ton) and $690/Mg ($630/ton) of 

SOa removed. For standards based on 

the use of very low sulfur oil to meet an 

emission limit of 129 ng SOa/J (0.3 lb 

SOa/million Btu) heat input or standards 

requiring a percent reduction in SOa 

emissions, the average cost 

effectiveness ranged from $500/Mg 

($450/ton) of SOa removed for a typical 

117 MW (400 million Btu/hour) capacity 

unit to $730/Mg ($660/ton) of SOa 

removed for a typical 29 MW (100 

million Btu/hour) capacity unit. 
P.20 

Federal Register / Vol. 51, No. 118 / Thursday. June 19. 1986 / Proposed Rules 22401 

The incremental cost effectiveness of 

standards based on the use of very low 

sulfur oil to meet an emission limit of 

129 ng SOa/J (0.3 lb SOa/million Btu) 

heat input or standards requiring a 

percent reduction in SOa emissions over 

standards based on the use of low sulfur 

oil to meet an emission limit of 344 ng 

SOa/J (0.8 lb SOa/million Btu) heat input 

ranges from $910/Mg ($830/ton) of SOa 

removed for a 29 MW (100 million Btu/ 

hour) heat input capacity steam 

generating unit to S240/Mg ($220/ton) of 

SOa removed for a 117 MW (400 million 

Btu/hour) heat input capacity steam 

generating unit. Tne incremental cost 

effectiveness of an alternative control 

level or standard based on the use of 

low sulfur oil to meet an emission limit 

of 344 ng SOj/J (0.8 lb SOa/million Btu) 

heat input over an alternative control 

level or standard based on the use of 

low sulfur oil to meet an emission limit 

of 688 ng SOa/J (1.6 lb SOa/million Btu) 

heat input ranges from $1.070/Mg to 

$680/Mg ($970/ton to $620/ton) of SOa 

removed over the range of steam 

generating unit sizes examined. 

These results indicate that standards 

based on the use of very low sulfur oil to 

meet an emission limit of 129 ng SOa/J 

(0.3 lb SOa/million Btu) heat input or 

standards requiring a percent reduction 

in SOa emissions at typical oil-fired 

steam generating units (i.e.. capacity 

utilization factors in the range of 0.55) 

achieve a significant reduction in 

emissions at a reasonable incremental 

cost compared to standards based on 

the use of low sulfur oil for all sizes of 

steam generating units examined. 

As mentioned above, the potential 

impacts of standards requiring a percent 

reduction in SOa emissions and 

standards based on the use of low sulfur 

oil were also examined as a function of 

steam generating unit capacity 

utilization factor. In particular, impacts 

were examined for a new 44 MW (150 

million Btu/hour) heat input capacity 

oil-fired steam generating unit operated 

at an annual capacity utilization factor 

of 0.3 and at an annual capacity 

utilization factor of 0.15. As discussed 

previously, it is generally less costly for 

a typical oil-fired steam generating unit 

to achieve a 90 percent reduction in SOa 

emissions on a high sulfur oil than it is 

to fire a very low sulfur oil to meet an 

emission limit of 129 ng SOa/J (0.3 lb 

SOa/million Btu) heat input, due to the 

high premium price of very low sulfur 

oil. However, for oil-fired steam 

generating units operating at low 

capacity utilization factors, it is 

generally less costly to fire a very low 

sulfur oil to meet an emission limit of 

129 ng SOa/J (0.3 lb SOa/million Btu) 

heat input. Thus, for low capacity 

utilization factor oil-fired steam 

generating units, three alternative 

control levels based on the use of low 

sulfur oil were examined for a typical 44 

MW (150 million Btu/hour) heat input 

capacity steam generating unit—688, 

344, and 129 ng SOa/J (1.6, 0.8. and 0.3 lb 

SOa/million Btu) heat input. An 

alternative control level requiring a 90 

percent reduction in SOa emissions was 

also examined. 

At a capacity utilization factor of 0.3. 

alternative control levels or standards 

based on the use of low sulfur oil to 

meet emission limits of 688 ng SOa/I (1.8 

lb SOa/million Btu) and 344 ng SOa/J (0.8 

lb SOa/million Btu) heat input achieve 

SOa emission reductions of 250 Mg/year 

(280 tons/year) and 400 Mg/year (440 

tons/year), respectively, over the 

regulatory baseline. An alternative 

standard based on the use of very low 

sulfur oil to meet an emission limit of 

129 ng SOa/J (0.3 lb SOa/million Btu) 

heat input achieves SOa emission 

reductions of 490 Mg/year (540 tons/ 

year) over the regulatory baseline. An 

alternative control level or standard 

requiring a percent reduction in SOa 

emissions results in emission reductions 

of 530 Mg/year (580 tons/year) over the 

regulatory baseline. 

Similarly, at a capacity utilization 

factor of 0.15, standards based on the 

use of low sulfur oil to meet emission 

limits of 688 ng SOa/T (1.6 lb SOa/million 

Btu) and 344 ng SOa/J (0.8 lb SOa/million 

Btu) heat input, and very low sulfur oil 

to meet an emission limit of 129 ng SOa/J 

(0.3 lb SOa/million Btu) heat input, 

achieve SOa emission reductions of 125 

Mg/year (140 tons/year), 200 Mg/year 

(220 tons/year), and 245 Mg/year (270 

tons/year), respectively, over the 

regulatory baseline. Alternative 

standards requiring a percent reduction 

in SOa emissions achieve emission 

reductions of 265 Mg/year (290 tons/ 

year) over the regulatory baseline. The 

SOa emission reductions associated with 

a standard requiring a percent reduction 

in SOa emissions are greater, therefore, 

than those associated with standards 

based on the use of low or very lowsulfur oil for oil-fired steam generating 

units operated at low capacity 

utilization factors. 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of Demonstrated 

Emission Control Technology Costs" 

and as shown in Table 6-28, the 

potential increase over the regulatory 

baseline in annualized costs of a new 44 

MW (150 million Btu/hour) heat input 

capacity oil-fired steam generating unit 

operating at low capacity utilization 

factors associated with standards based 

on the use of low sulfur oil to met 

emission limit of 688 ng SOa/J (1-6 lb 

SOa/million Btu) heat input ranges fro 

3 to 4 percent. The potential n 

over the regulatory baseline in 

annualized costs associated with a 

standard based on the use of low sulfur 

oil to meet an emission limit of 344 ng 

SOa/J (0.8 lb SOa/million Btu) h. 

ranges from about 7 to 9 percent. 1 

potential increase over the regulutory 

baseline in annualized costs of a new 44 

MW (150 million Btu/hour) heat i; 

capacity oil-fired steam generating 

associated with a standard based on 

use of very low sulfur oil to meet an 

emission limit of 129 ng SOa/J (0.3 lb 

SOa/million Btu) heat input ranges from 

about 15 to 17 percent. The poten: 

increase over the regulatory baseline in 

annualized costs of a new 44 MW 

million Btu/hour) heat input capnoil-fired steam generating unit op 

at a low capacity utilization factor 

associated with a standard requiring a 

percent reduction in SOa emissions 

ranges from about 20 to 22 percent. 

The average cost effectiveness of 

standards based on the use of low sulfur 

oil remains essentially constant with 

respect to steam generating unit 

capacity utilization factor. For a 44 MW 

(150 million Btu/hour) heat input 

capacity steam generating unit operating 

at capacity utilization factors of 0.15 to 

0.3. the average cost effectiveness of 

standards based on the use of low sulfur 

oil to meet an SOa emission limit of 688 

ng/J (1.6 lb/million Btu) heat inpii 

about $475/Mg ($435/ton) of SO, 

removed. 

The average cost effectiveness of 

standards based on the use of low sulfur 

oil to meet an SOa emission limit of 344 

ng/J (0.8 lb/million Btu) heat input is 

about $700/Mg ($635/ton) of SOa 

removed, and is about $855/Mg ($775/ 

ton) of SOa removed for an emission 

limit of 129 ng SOa/J (0.3 lb SOa/million 

Btu) heat input based on the use of very 

low sulfur oil. 

For a standard based on achieving a 

percent reduction in SOa emissions, 

average cost effectiveness increases 

with decreasing steam generating unit 

capacity factor. For a 44 MW (150 

million Btu/hour) heat input capacity 

steam generating unit, the average cost 

effectiveness of a standard requiring a 

percent reduction in SOa emissions is 

$1,100/Mg ($1,000/ton) of SOa removed 

at a capacity utilization factor of 0.3 and 

increases to $1,550/Mg ($l,410/ton) of 

SOa removed at a capacity utilization 

factor of 0.15. 

The incremental cost effectiveness of 

a standard requiring a percent reduc' 
22402 Federal Register / Vol. 51, No. 118 / Thursday, June 19. 1986 / Proposed Rules 

P.21 

in SOa emissions compared to a 

standard based on the use of very low 

sulfur oil ranges from about $4,410/Mg 

($4,000/ton) of SOa removed for a new 

44 MW (150 million Btu/hour) heat input 

capacity oil-fired steam generating unit 

operated at a capacity utilization factor 

of 0.30 to about $11,000/Mg ($10,000/ton) 

of SOa removed for this same size steam 

generating unit operated at a capacity 

utilization factor of 0.15. The 

incremental cost effectiveness of a 

standard based on the use of very low 

sulfur oil to meet an emission limit of 

129 ng SOa/J (0.3 lb SOa/million Btu) 

heat input over a standard based on the 

use of low sulfur oil to meet an emission 

limit of 344 ng SOa/J (0.8 lb SOa/million 

Btu) heat input is about $1,540/Mg 

($l,400/ton) of SOa removed for new 44 

MW (150 million Btu/hour) heat input 

capacity oil-fired steam generating units 

operating at capacity utilization factors 

of 0.15 and 0.30. The incremental cost 

effectiveness of a standard based on the 

use of low sulfur oil to meet an emission 

limit of 344 ng SOa/J (0.8 lb S02/million 

Btu) heat input over a standard based on 

the use of low sulfur oil to meet an 

emission limit of 688 ng SOj/J (1.6 lb 

SOa/million Btu) heat input is about 

$1,030 to $1,100/Mg ($940 to $l,000/ton) 

of SOa removed. 

These results indicate that the annual 

emission reductions achieved under a 

standard requiring a percent reduction 

in SOa emissions compared to a 

standard based on the use of low sulfur 

oil decrease as steam generating unit 

capacity utilization factor decreases. 

The incremental annualized cost 

impacts associated with standards 

requiring a percent reduction over 

standards based on the use of low sulfur 

oil or very low sulfur oil increase, and 

the incremental SOa removal cost 

increases significantly, as capacity 

utilization factor decreases. 

As discussed above and in "Summary, 

of Regulatory Analysis" under 

"Consideration of National Impacts," 

however, many steam generating units 

fire natural gas instead of oil in response 

to a standard based on the use of very 

low sulfur oil or a standard requiring a 

percent reduction in SOa emissions. The 

analysis discussed above of the 

potential impacts of standards requiring 

a percent reduction in SOa emissions on 

low capacity utilization factor steam 

generating units does not reflect the 

effect of fuel switching. 

The national impacts analysis, with 

its allowance for fuel switching, 

suggests that the incremental control 

costs of a percent reduction requirement 

vary inversely with capacity utilization 

factor. That is, SOa control costs for 

steam generating units operating at 

lower capacity utilization factors are 

higher than the control costs for steam 

generating units operating at higher 

capacity utilization factors. 

The national incremental cost 

effectiveness of a standard requiring a 

percent reduction in emissions for steam 

generating units operating at capacity 

utilization factors of approximately 0.5 

or more (and an emission limit based on 

the combustion of low sulfur fuel for 

steam generating units with capacity 

utilization factors below 0.5] compared 

to a standard based on the combustion 

of low sulfur fuel for all steam 

generating units is approximately $850/ 

Mg ($775/ton). 

As the applicability of percent 

reduction requirements is extended to 

include steam generating units with 

capacity utilization factors below 0.5, 

the incremental cost effectiveness of the 

standards increases. For example, the 

incremental cost effectiveness of 

requiring a percent reduction in 

emissions for all steam generating units 

with capacity utilization factors less 

than 0.5 is $1,020/Mg ($925/ton). 

Extending the applicability of percent 

reduction requirements to steam 

generating units with capacity 

utilization factors below 0.5 yields an 

emission reduction of 38,000 Mg (42,000 

tons) of SOa per year (roughly 15 percent 

of baseline emissions) at annualized 

costs of $39 million. While the Agency is 

proposing standards requiring a percent 

reduction in emissions for all oil-fired 

steam generating units, the Agency is 

interested in alternative ways of 

establishing standards that would make 

them more cost effective. As noted 

above, such approaches might include 

exempting steam generating units 

operating at lower capacity utilization 

factors. 

4. Selection of Standard for Oil-Fired 

Steam Generating Units 

As discussed above for coal-fired 

steam generating units, a number of 

technologies are capable of reducing 

emissions of SOa from oil-fired 

industrial-commercial-institutional 

steam generating units. Conventional 

wet FGD technologies, such as sodium 

scrubbing systems, have been widely 

applied to oil-fired steam generating 

units and are considered demonstrated 

for purposes of developing NSPS. 

Short- and long-term test data were 

gathered to assess the performance of 

wet FGD systems in achieving a percent 

reduction in SOa emissions from oil-fired 

steam generating units. As discussed in 

"Summary of Regulatory Analysis" 

under "Performance of Demonstrated 

Emission Control Technologies," 

analysis of the data indicates that these 

technologies are capable of continuously 

achieving a 90 percent reduction in SOa 

emissions on a 30-day rolling average 

basis. Therefore, a 90 percent reduction 

in SOa emissions on a 30-day rolling 

average basis through the use of wet 

FGD technologies is considered 

demonstrated for oil-fired steam 

generating units. 

Assessing the performance of other 

demonstrated control technologies, such 

.as FBC or lime spray drying, in 

achieving sustained SOa emission 

reductions on oil-fired steam generating 

units is not as straightforward. The FBC 

and lime spray drying technologies, for 

example, were developed primarily for 

coal firing and nearly all commercially 

operating installations of these 

technologies are on coal-fired steam 

generating units. Therefore, the 

performance of these control 

technologies in achieving sustained 

reductions in SOa emissions from oilfired steam generating units must largely 

be inferred from their performance on 

coal-fired units. While some changes in 

the design of these technologies may be 

appropriate for their use on oil-fired 

steam generating units, such as the use 

of electrostatic precipitators rather than 

fabric filters, there are no technical 

reasons to expect that the performance 

of FBC or lime spray drying when 

applied to oil-fired steam generating 

units would differ substantially from the 

performance levels demonstrated on 

coal-fired steam generating units. 

Consequently, a 90 percent reduction in 

SOa emissions on a 30-day rolling 

average basis is also considered 

demonstrated for these technologies 

when applied to oil-fired steam 

generating units. 

The cost impacts associated with 

various percent reduction requirements 

were examined and analyzed for oilfired steam generating units at both the 

national level and the individual steam 

generating unit level. These analyses are 

discussed in "Summary of Regulatory 

Analysis" under "Consideration of 

National Impacts" and "Consideration 

of Demonstrated Emission Control 

Technology Costs." 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of National Impacts" 

and shown in Table 8-5, national 

annualized cost impacts were found to 

be relatively insensitive to variations in 

the specific level of the percent 

reduction requirement. For example, the 

national average cost effectiveness 

associated with various percent 

reduction requirements ranging from 70 

percent to 90 percent varied from $600/ 

) 
P.22 

Federal Register / Vol. 51. No. 118 / Thursday. June 19, 1986 / Proposed Rules 22403 

Mg ($540/ton) of SOa removed to $560/ 

Mg ($510/ton) of SOa removed. 

However. SOa emissions under a 90 

percent reduction requirement are 

reduced by an additional 28.000 Mg/ 

31.000 tons/year) below the 

emission levels achieved under a 70 

percent reduction requirement. 

;ofore. on a national basis, a 90 

percent reduction requirement achieves 

greater SOa emission reductions at costs 

only slightly higher than those 

associated with lower percent reduction 

requirements for oil-fired steam 

generating units. 

The cost impacts associated with 

various percent reduction requirements 

niined for a typical oilfired industiial-commercial-institutional 

steam generating unit with a heat input 

capacity of 44 MW (150 million Btu/ 

As shown in Table 6-29 of 

"Summary of Regulatory Analysis." the 

annualized cost differences of operating 

an FGD system to achieve a 90 percent 

reduction versus a 50 percent reduction 

in SOz emissions ranges from about 

$30.000/year for low sulfur oil to about 

000/year for high sulfur oil. The 

sponding incremental emission 

ions achieved under a 90 percent 

reduction requirement range from 80 

Mg/year (88 tons/year) for low sulfur oil 

to 298 Mg/year (328 tons/year) for high 

sulfur oil. The average cost effectiveness 

of operating an FGD system at 90 

percent reduction is $628 to $1.500/Mg 

($570 to $1.360/ton) of SOa removed, 

compared to $750 to $2.040/Mg ($680 to 

$1.850/ton) of SOa removed for an FGD 

system operated at 50 percent reduction. 

As in the national impact and 

individual steam generating unit impact 

analyses discussed above for coal-fired 

steam generating units, the results of 

both the national impact and individual 

steam generating unit impact analyses 

fired steam generating units lead 

to the same conclusion: a 90 percent 

reduction requirement is more cost 

effective than lower percent reduction 

requirements. 

As discussed above, this result 

emerges because the only increased 

costs associated with operating an FGD 

system to achieve a high percent 

reduction in SOz emissions, rathe; 

a low percent reduction, are the 

increased costs resulting from increased 

chemicals and utilities consumption and 

increased waste disposal costs. These 

increased costs are incremental in 

nature and relatively small. However, 

the increased reduction in SOa 

ions resulting from operation at a 

high percent reduction level is quite 

significant. 

In addition, in the national impacts 

analysis, the cost effectiveness of a 90 

percent reduction requirement compared 

to the cost effectiveness of a lower 

percent reduction requirement is also 

influenced by fuel switching. As also 

discussed above, the impact of fuel 

switching in response to percent 

reduction requirements tends to improve 

the resulting cost effectiveness of SOa 

control. While the increased costs 

associated with operating an FGD 

system at a high percent reduction are 

small, in some cases these increased 

costs are sufficient to cause s. 

additional steam generating units to fire 

natural gas instead of oil. This tends to 

improve further the cost effectiveness of 

SOa control associated with the 90 

percent reduction requirement. 

Consequently, in both the national 

impact and individual steam generating unit impact analyses, a 90 percent 

reduction requirement emerges as more 

cost effective than lower percent 

reduction requirements. 

As discussed above, the ability of wet 

FGD systems, lime spray drying 

systems, and FBC systems to achieve 

this level of performance on a 30-day 

rolling average basis is considered 

demonstrated. Thus, a stanc' 

requiring a 90 percent reduction in SOa 

emissions has been selected for new oilfired steam generating units of greater 

than 29 MW (100 million Btu/hour) heat 

input capacity (except for units using 

emerging technologies, as discussed 

below). 

In selecting an SOa emission limit to 

accompany the percent reduction 

requirement for oil-fired steam 

generating units, consideration was 

given to emission levels which, when 

combined with a requirement to achieve 

a 90 percent reduction in SOa emissions, 

would not preclude the use of very high 

sulfur oils. Review of data on fuel oils 

currently produced by U.S. refineries 

indicates that the SOa content of the 

residual oils prior to 

hydrodesulfurization can be in excess of 

2,580 ng/J (6.0 lb/million Btu). However, 

residual oils produced from particularly 

heavy crude oils, or oils recovered from 

tar sands and oil shales, could have SOa 

contents of up to 3.440 ng/J (8.0 lb/ 

million Btu). Although these types of oils 

are not currently widely processed by 

U.S. refineries, they are expected to be 

processed more frequently in the future. 

Therefore, an SOa emission limit of 344 

ng/J (0.8 lb/million Btu) heat input has 

been selected as the emission limit 

included in the 90 percent reduction 

requirement for oil-fired industr: 

commercial-institutional steam 

generating units. 

As discussed above concerning coalfired steam generating units, it is 

questionable whether these standards 

for oil-fir told 

be achiev*II ^ies. 

Accommodating and ; the 

inued development of emerging 

Is considered desire: 

with c steam generating ui 

establishing less stri 

reduction requirements for emerging 

technologies ap| 

generating units would 

likelihood that owners and opt 

new alinstitutional steam generating units will 

install and operate emerging 

technologies. 

As mentioned in the introdi. 

this section, stand il 

fired steam generating units si 

conceptually similar so as to i: 

an advantage in the use of one fuel o. 

another. Therefore, the regulatory 

approach selected for accommodating 

the use of emerging technologies on 

coal-fired steam generating units was 

also selected for at 'ding the 

of emerging technologies on oil-fired 

steam generating units. 

Most emerging technologies for 

tol of SOa emia <im 

generating units are being d,< 

primarily for applit 

steam generating units. Non 

such emerging technologies as dry all 

injectipn, electron bean nd 

LIMB could be applied to o 

generating units as well. There etn 

addition, no reasons to exper 

performance of emerging tec! 

when applied to oil-fired steam 

generating units would be Al 

worse than when a: 

steam generating units. Then 

proposed standards would re 

new, modified, or reconstructed oil-f 

industrial-commercial-insfitiiti-in.il 

generating units with heat input 

capacities greater than 29 MW (100 

million Btu/hour) emploj s>ing 

SOa control technologies to achieve a 

minimum of 50 percent 

emissions on a 30-day rolling average 

basis. 

In order to minimize emissii 

oil-fired steam generating units usin«. 

emerging technology for SOa control 

subject to the 50 p 

requirement, the proposed standard 

includes an emission IL 

SOa/J (0.4 lb SOa/million ll' 

As discussed above for coal-fired steam 

generating units, this limit is one-half of 

the otherwise applicable lin 

limits the use of emerging technologies 

achieving the minimum 50 percent 

reduction in SOa emissions b 

generating units firing low gullur oil; i.e.. 

oil with a sulfur content of 344 ng SOa/J 

(0.8 lb SOa/million Btu) heat Input 
P.23 

22404 Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 

less. To the extent that emerging 

technologies may achieve SOa emission 

reductions of greater than 50 percent, 

oils with higher sulfur contents can be 

burned without exceeding the proposed 

emission limit. Because higher sulfur oils 

are generally less expensive than low ' 

sulfur oils, this will act as an incentive 

to achieve percent reductions of greater 

than 50 percent. 

As discussed above for coal-fired 

steam generating units, therefore, the 

proposed standards provide a limited 

"window" for use of emerging 

technologies on oil-fired steam 

generating units. This window will be 

reviewed regularly during the course of 

the review process associated with all 

NSPS. As appropriate, the percent 

reduction requirements will be revised 

upwards in light of additional 

performance data available at that time 

for emerging technologies. As a result of 

these reviews, emerging control 

technologies that do not demonstrate 

improvements in performance 

capabilities, or show no promise of 

achieving emission reductions greater 

than 50 percent, will no longer be 

considered emerging technologies and 

would be subjected to the same 

requirements as those included in the 

standards for conventional 

demonstrated technologies. 

5. Basis of Standard for Mixed FuelFired Steam Generating Units 

The regulatory analysis for mixed 

fuel-fired steam generating units (i.e., 

those firing mixtures of sulfur-bearing 

and nonsulfur-bearing fuels) was 

conducted in a manner parallel to that 

for steam generating units firing coal 

and oil. The analysis considered the 

impacts of alternative control levels or 

standards based on the use of low sulfur 

fuel or requiring a percent reduction in 

SOa emissions from three different 

perspectives: overall national impacts; 

specific industries subject to the 

standards; and individual steam 

generating units subject to the 

standards. 

For purposes of calculating these 

impacts, the analyses assumed that 

"emission credits" are not provided for 

mixed fuel-fired steam generating units. 

(Emission credits would permit 

"dilution" of the SOa emissions resulting 

from combustion of coal or oil with 

"clean" gases resulting from combustion 

of non-sulfur containing fuels as a 

means of reducing emissions and 

meeting standards.) As discussed in 

"Summary of Regulatory Analysis" 

under "Consideration of Demonstrated 

Emission Control Technology Costs," 

this assumption permits mixed fuel-fired 

steam generating units to be considered 

as a type of low capacity utilization 

factor fossil fuel-fired steam generating 

unit. The merits of emission credits are 

considered and discussed below under 

"Other Considerations." 

National Impacts. As discussed in 

"Summary of Regulatory Analysis" 

under "Consideration of National 

Impacts," the national impact's 

associated with NSPS were analyzed on 

the basis of projections to 1990 of new 

mixed fuel-fired steam generating units. 

The computer model used to assess the 

impacts of various standards for fossil 

fuel-fired units, IFCAM, considers only 

steam generating units firing fossil fuels. 

Consequently, this model could not be 

used in the analysis of national impacts 

on mixed fuel-fired steam generating 

units. The methodological approach 

employed in the analysis of national 

impacts on mixed fuel-fired steam 

generating units, however, was the same 

as that employed in the IFCAM model. 

Similar to the analyses of national 

impacts discussed above for coal- and 

oil-fired steam generating units, a set of 

regulatory alternatives or alternative 

standards was structured to examine 

national impacts on mixed fuel-fired 

steam generating units as a function of 

steam generating unit size. These 

alternatives are shown in Table 8-11 of 

"Summary of Regulatory Analysis." 

The regulatory alternatives become 

progressively more stringent by first 

requiring only mixed fuel-fired steam 

generating units with heat input 

capacities above 73 MW (250 million 

Btu/hour) to meet a standard based on . 

the use low sulfur fuel. The second 

alternative requires all steam generating 

units with heat input capacities greater 

than 29 MW (100 million Btu/hour) to 

meet an emission limit based on the use 

of low sulfur fuel. The third alternative 

requires only mixed fuel-fired steam 

generating units larger than 73 MW (250 

million Btu/hour) heat input capacity to 

achieve a percent reduction in SO2 

emissions, while all other steam 

generating units are required to meet an 

emission limit based on the use of low 

sulfur fuels. The fourth alternative 

requires all steam generating units 

larger than 29 MW (100 million Btu/ 

hour) heat input capacity to achieve a 

percent reduction in SOa emissions. 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of National Impacts" 

and shown in Table 8-12, standards 

based on the use of low sulfur fuel for 

all new mixed fuel-fired steam 

generating units with heat input 

capacities greater than 29 MW (100 

million Btu/hour) result in a projected 

reduction in national SOa emissions of 

42,000 Mg/year (46,000 tons/year) over 

the regulatory baseline in the fifth year 

following proposal of standards (i.e., 

1990). In comparison, standards 

requiring all new mixed fuel-fired steam 

generating units with heat input 

capacities greater than 29 MW (100 • 

million Btu/hour) to achieve a percent 

reduction in emissions result in a 

projected national SO2 emission 

reduction of 55,700 Mg/year (61,200 

tons/year) over the regulatory baseline 

in 1990. -

Of the difference in projected national 

SO2 emission reductions between these 

two alternatives (about 14,000 Mg/year), 

nearly all (about 13,500 Mg/year) results 

from standards requiring all-new mixed 

fuel-fired steam generating units with 

heat input capacities greater than 73 

MW (250 million Btu/hour) to achieve a 

percent reduction in SOa emissions. This 

occurs for two reasons: (1) Only a very 

small number of new mixed-fuel fired 

steam generating units in 1990 (i.e., 5 out 

of a total of 35) are projected to have 

heat input capacities less than 73 MW 

(250 million Btu/hour), and (2) all of the 

new mixed fuel-fired units with heat 

input capacities less than 73 MW (250 

million Btu/hour) are projected to burn 

small amounts of coal or oil (i.e., about 

20 percent) relative to the amount of 

nonsulfur-bearing fuel fired annually. 

The amount of coal or oil fired in a 

steam generating unit can be expressed 

in terms of a fossil fuel utilization factor. 

This represents the percentage of the 

rated steam generating unit heat input 

capacity that is supplied by coal or oil. 

The fossil fuel utilization factoras, 

therefore, calculated on the basis of the 

amount of coal or oil that is actually 

fired compared to the maximum amount 

of fuel that'could be fired in the steam 

generating unit. For example, a 117 MW 

(400 million Btu/hour) heat input 

capacity mixed fuel-fired steam 

generating unit operating at an annual 

capacity utilization factor of 0.6 is firing 

70 MW (240 million Btu/hour) heat input 

on an annual basis. If this unit fires 20 

percent coal and 80 percent nonsulfurbearing fuel, the heat input supplied 

• from coal is 14 MW (48 million Btu/ 

hour) on an annual basis. This 

represents 12 percent of the potential 

total annual heat input to the steam 

generating unit, or a fossil fuel 

utilization factor of 0.12. Similarly, a 

mixed fuel-fired steam generating unit 

operating at an annual capacity 

utilization factor of 0.6 and firing a 50 

percent coal/50 percent nonsulfurbearing fuel mixture would have a fossil 

fuel utilization factor of 0.3, and a unit 

firing 80 percent coal and 20 percent 
P.24 

Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 22405 

nonsulfur-bearing fuel would have a 

fossil fuel utilization factor of 0.48. 

Based on the above discussion, this 

analysis projects that standards 

requiring all new mixed fuel-fired steam 

generating units to achieve a percent 

reduction in SO2 emissions achieve 

greater reductions in national SOa 

emissions than standards based on the 

use of low sulfur fuel. 

As shown in Table 8-12 of "Summary 

of Regulatory Analysis," NSPS based on 

the use of low sulfur fuel for all new 

mixed fuel-fired steam generating units 

with heat input capacities greater than 

29 MW (100 million Btu/hour) result in a 

projected national annualized cost 

increase of $21.5 million/year over the 

regulatory baseline in 1990. This 

represents an increase of about 5 

percent in the total national annualized 

costs associated with operation of all 

new mixed fuel-fired steam generating 

units projected to be constructed 

between 1986 and 1990. In comparison, 

standards requiring all new mixed fuelfired steam generating units with heat 

input capacities greater than 29 MW 

(100 million Btu/hour) to achieve a 

percent reduction in emissions result in 

projected national annualized cost 

increases of about $42.9 million/year 

over the regulatory baseline in 1990. 

This represents an increase in total 

national annualized costs of about 10 

percent. 

Of the difference in projected 

increases in total national annualized 

costs between these two alternatives 

(about $21.4 million/year), nearly all 

($19.9 million/year) results from 

standards requiring all new mixed fuelfired steam generating units with heat 

input capacities greater than 73 MW 

(250 million Btu/hour) to achieve a 

percent reduction in SOa emissions. 

Again, this occurs as a result of both the 

small number of new mixed fuel-fired 

steam generating units projected to have 

heat input capacities less than 73 MW 

(250 million Btu/hour) and the low fossil 

fuel utilization factors projected for 

these units. 

Based on the projected national 

emission reductions and annualized cost 

increases described above, the national 

average cost effectiveness of NSPS 

based on the use of low sulfur fuel for 

all new mixed fuel-fired steam 

generating units with heat input 

capacities greater than 29 MW (100 

million Btu/hour) is about $520/Mg 

($470/ton) of SO2 removed. In 

comparison, standards requiring all new 

mixed fuel-fired steam generating units 

with heat input capacities greater than 

29 MW (100 million Btu/hour) to achieve 

a percent reduction in emissions result 

in a national average cost effectiveness 

of $770/Mg ($700/ton) of SOa removed. 

As shown in Table 8-12, however, the 

incremental cost effectiveness of a 

standard requiring all mixed fuel-fired 

steam generating units with heat input 

capacities greater than 29 MW (100 

million Btu/hour) to achieve a percent 

reduction in SOa emissions, over a 

standard requiring only mixed fuel-fired 

steam generating units with heat input 

capacities greater than 73 MW (250 

million Btu/hour) to achieve a percent 

reduction in SOa emissions, is about 

$5,800/Mg ($5,300/ton) of SOa removed. 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of National Impacts," 

this high incremental cost effectiveness 

level is not due to the relatively small 

size of steam generating units with heat 

input capacities less than 73 MW (250 

million Btu/hour), but rather results 

from the projection that all of the new 

mixed fuel-fired steam generating units 

with heat input capacities less than 73 

MW (250 million Btu/hour) will have 

low fossil fuel utilization factors. 

On an annual basis, the potential 

emission reductions obtainable from 

these mixed fuel-fired steam generating 

units with heat input capacities less 

than 73 MW (250 million Btu/hour) units 

are much less than those obtainable 

from larger units, even under a standard 

that requires a percent reduction in SOa 

emissions. Moreover, FGD systems 

installed on these mixed fuel-fired units 

would"be designed to accommodate 

firing of coal or oil at full load to provide 

maximum fuel use flexibility. Thus, the 

costs of these FGD systems would be 

similar to those installed on coal- or oilfired steam generating units or on mixed 

fuel-fired units that fire relatively large 

amounts of coal or oil relative to 

nonsulfur-bearing fuel (i.e., with high 

fossil fuel utilization factors). As a 

result, for mixed fuel-fired steam 

generating units with heat input 

capacities of less than 73 MW (250 

million Btu/hour) that have low fossil 

fuel utilization factors, the costs of 

achieving a percent reduction in SOa 

emissions are relatively high in 

proportion to the emission reductions 

achievable on an annual basis. 

In summary, this analysis indicates 

that the national average cost 

effectiveness of standards requiring all 

new mixed fuel-fired steam generating 

units to achieve a percent reduction in 

SOa emissions is not substantially 

higher than the national average cost 

effectiveness of standards based on the 

use of low sulfur fuel. This analysis also 

appears to indicate that the incremental 

cost effectiveness of a standard 

requiring all steam generating units with 

heat input capacities greater than 29 

MW (100 million Btu/hour) to achieve a 

percent reduction in SOa emissions over 

a standard that would require only 

mixed fuel-fired steam generating units v 

with heat input capacities greater than 

73 MW (250 million Btu/hour) to achieve 

a percent reduction in emissions is high. 

As discussed above, however, this high 

incremental cost effectiveness is not due 

primarily to the smaller size of these 

mixed fuel-fired steam generating units, 

but rather to the low fossil fuel 

utilization factors projected for new 

mixed fuel-fired steam generating units 

of less than 73 MW (250 million Btu/ 

hour) heat input capacity (i.e., fossil fuel 

utilization factors in the range of 0.12). 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of National Impacts" 

and shown in Table 8-12, NSPS are not 

projected to have any impact on fuel use 

in new mixed fuel-fired steam 

generating units. Under the regulatory 

baseline, the total fuel consumption in 

new mixed fuel-fired steam generating 

units is projected to be evenly divided 

between coal and nonfossil fuels. Oil 

and natural gas are not competitive with 

coal for use in mixed fuel-fired steam 

generating units under either the high oil 

penetration or high coal penetration 

energy scenarios discussed above for 

fossil fuel-fired steam generating units. 

In addition, as shown in Table 8-12, this 

fuel use pattern does not change under 

any of the regulatory alternatives or 

standards examined. Thus, this analysis 

indicates that the fuel switching 

projected to occur for fossil fuel-fired 

steam generating units in response to 

various NSPS is not projected to occur 

for mixed fuel-fired steam generating 

units. 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of Secondary 

Environmental Impacts," potential 

secondary environmental impacts 

associated with standards of 

performance that include a percent 

reduction requirement have also been 

analyzed. The impacts of various 

regulatory alternatives on the generation 

and disposal of solid and liquid wastes 

were examined at the national level, as 

shown in Table 8-12. Regulatory 

alternatives requiring a percent 

reduction in SOa emissions result in 

greater quantities of liquid waste than 

do regulatory alternatives based on the 

use of low sulfur fuels. The table abo 

indicates that the solid waste impacts 

associated with regulatory alternatives 

requiring a percent reduction in SOa 

emissions are not significantly greater 
22406 Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 

than those associated with regulatory 

alternatives based on the use of low 

sulfur fuel. 

As discussed previously for coal- and 

oil-fired steam generating units, the 

quantities of wastes generated by FGD 

systems installed on mixed fuel-fired 

steam generating units is small 

compared to the total amounts of 

existing liquid and solid wastes 

generated by industrial plants at which 

these steam generating units are located. 

In addition, the nontoxic and 

nonhazardous nature of the FGD wastes 

permits their disposal using 

conventional techniques such as 

ponding, landfilling, or direct discharge 

without leading to any unreasonable 

secondary environmental impacts. 

Industry-Specific Economic Impacts. 

The analysis discussed above of 

potential national impacts associated 

with standards of performance for new 

mixed fuel-fired steam generating units 

represents an assessment of the 

aggregate nationwide impact of 

standards requiring a percent reduction 

in SO2 emissions. Because of the 

aggregate nature of this analysis of 

national impacts, the potential impact of 

standards requiring a percent reduction 

in SOa emissions was not assessed for 

specific industrial sectors within the 

national economy. Accordingly, the 

potential economic impacts of a 

standard requiring a percent reduction 

in S02 emissions on major industrial 

steam users were also considered. 

For the same size steam generating 

unit operating at the same overall 

capacity utilization factor, the 

annualized costs associated with 

standards requiring a percent reduction 

in SO2 emissions would be somewhat 

less for a mixed fuel-fired steam 

generating unit than for a fossil fuelfired steam generating unit. In both 

cases, an FGD system would be . 

installed to comply with the percent 

reduction requirement, and this FGD 

system would be designed to handle the 

total exhaust gas volume from the steam 

generating unit. This would be 

necessary for the mixed fuel-fired steam 

generating unit, as well as the fossil 

fuel-fired steam generating unit, because 

100 percent coal or oil might have to be. 

fired on occasion in the mixed fuel-fired 

steam generating unit when nonsulfurbearing fuels were not available. As a 

result, capital costs associated with 

standards requiring a percent reduction 

in SO2 emissions would be essentially 

the same for both mixed fuel-fired and 

fossil fuel-fired steam generating units. 

Operating costs, however, would be 

somewhat lower for a mixed fuel-fired 

steam generating unit. These costs are a 

function of the amount of SO2 removed 

by the FGD system which, for steam 

generating units of the same size, 

operating at the same capacity 

utilization factor, and firing coal or oil of 

the same sulfur content, would be less 

for a mixed fuel-fired steam generating 

unit than for a fossil fuel-fired steam 

generating unit. As a result, the 

industry-specific economic impacts 

associated with alternative standards 

for mixed fuel-fired steam generating 

units would also be somewhat less than 

those associated with alternative 

standards for fossil fuel-fired steam 

generating units. 

As discussed above for coal-fired 

steam generating units, the "worse case" 

analysis of potential industry-specific 

economic impacts of standards requiring 

a percent reduction in SO2 emission's 

indicates that the increases in product 

prices as a result of such a standard 

could range from less than 0.1 percent to 

1.5 percent. Similarly, assuming full cost 

absorption, potential increases in 

product value added range from less 

than 0.1 percent to 5.0 percent, and 

potential decreases in manufacturing 

plant profitability or return on assets 

range from less than 0.1 to 2.8 percent. 

As mentioned above, none of these 

industry-specific impacts associated 

with a standard requiring a percent 

reduction in SOa emissions from coalfired steam generating units is 

considered unreasonable. The 

annualized costs associated with 

achieving a percent reduction in SOa 

emissions from mixed fuel-fired steam 

generating units are smaller than the 

annualized costs associated with 

achieving a percent reduction in SO2 

emissions from coal-fired steam 

generating units. As a result, none of the 

industry-specific impacts associated 

with standards requiring a percent 

reduction in SOa emissions from mixed 

fuel-fired steam generating units are 

considered unreasonable. 

Impacts on Individual Steam 

Generating I/nits. The analysis of 

industry-specific impacts discussed 

above examined the potential impacts of 

standards requiring a percent reduction 

in SOa emissions within specific 

industries at the manufacturing plant 

level. This analysis, however, was 

unable to assess potential impacts at the 

individual steam generating unit level. 

Consequently, the regulatory analysis 

also examined the cost and emission 

impacts associated with standards 

requiring a percent reduction in SO2 

emissions and standards based on the 

use of low sulfur coal in terms of 

individual steam generating units. 

As was discussed above and in 

"Summary of Regulatory Analysis" 

under "Consideration of Demonstrated 

Emission Control Technology Costs," 

assuming that emission credits are not 

provided, the cost impacts on mixed 

fuel-fired steam generating units of 

alternative control levels or standards 

based on the use of low sulfur fuel 

would be essentially the same as those 

for fossil fuel-fired units operating at 

low annual capacity utilization factors. 

The annual costs associated with 

alternative control levels or standards 

based on achieving a percent reduction 

in SO2 emissions would also be the 

same for mixed fuel-fired and fossil fuelfired steam generating units operating at 

low annual capacity utilization factors. 

Therefore, the cost impacts on mixed 

fuel-fired steam generating units of 

alternative control levels or standards 

can be examined by considering the cost 

analysis performed for fossil fuel-fired 

steam generating units operating at low 

annual capacity utilization factors. A 

mixed fuel-fired steam generating unit 

firing 50 percent coal or oil and 50 

percent nonsulfur-bearing fuel at an 

annual capacity utilization factor of 0.6 

(i.e., fossil fuel utilization factor of 0.3), 

for example, can be considered a fossil 

fuel-fired steam generating unit 

operating at an annual capacity 

utilization factor of 0.3 for purposes of 

analysis. 

Most nonfossil fuel-fired steam 

generating units are designed with the 

flexibility to fire fossil fuel, as well as 

nonfossil fuel. As a result, most 

nonfossil fuel-fired steam generating 

units can be considered mixed fuel-fired 

steam generating units. The flexibility to 

fire fossil fuel is generally provided to 

overcome potential flame stability, 

problems that arise with some nonfossil 

fuels and to ensure that the steam 

generating unit can continue to operate 

during periods when nonfossil fuel may 

not be available. 

The basic design of a steam 

generating unit designed to fire nonfossil 

fuel is very similar to the basic design of 

a steam generating unit designed to fire 

coal. The increase in capital costs 

necessary to provide the flexibility for a 

nonfossil fuel-fired steam generating 

unit to fire coal, therefore, are small. As 

a result, selection of the fossil fuel to fire 

in a mixed fuel-fired steam generating 

unit is primarily a consideration of the 

price of the fossil fuel. In such a 

situation, with few exceptions, coal 

normally is the less expensive fuel. 

Consequently, most mixed fuel-fired 

steam generating units fire coal, rather 

than natural gas or oil, with nonfossil 

fuels. 

The potential impacts associated with 

standards based on the use of low sulfur 

fuel and standards requirirg a percent 
Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 

reduction in SOa emissions, therefore, 

were examined by considering the 

potential impacts discussed above and 

in "Summary of Regulatory Analysis" 

under "Consideration of Demonstrated 

Emission Control Technology Costs" for 

a coal-fired steam generating unit with a 

heat input capacity of 44 MW (150 

million Btu/hour) operating at annual 

capacity utilization factors of 0.3 and 

0.15. As discussed above, annual fossil 

fuel utilization factor is calculated by 

multiplying the annual capacity 

utilization factor by the percentage of 

fossil fuel fired in the steam generating 

unit. Thus, the cost impacts for coalfired steam generating units operating at 

annual capacity utilization factors of 0.3 

and 0.15 correspond to the cost impacts 

associated with mixed fuel-fired steam 

generating units operating at an overall 

capacity utilization factor of 0.6 and 

firing a mixture of 50 percent coal/50 

percent nonsulfur-bearing fuel and 25 

percent coal/75 percent nonsulfurbearing fuel, respectively. 

An alternative control level or 

standard based on the use of low sulfur 

coal results in SOa emission reductions 

of 205 Mg/year (230 tons/year) over the 

regulatory baseline for a 44 MW (150 

million Btu/hour) heat input capacity 

mixed fuel-fired steam generating unit 

located in Region V and operating at an 

annual fossil fuel utilization factor of 

0.30. An alternative control level or 

standard requiring a percent reduction 

in SOa emissions results in emission 

reductions of 300 Mg/year (330 tons/ 

year) over the regulatory baseline. At an 

annual fossil fuel utilization factor of 

0.15, an alternative control level or 

standard based on the use of low sulfur 

coal achieves SOa emission reductions 

of 100 Mg/year (115 tons/year) over the 

regulatory baseline and an alternative 

control level or standard requiring a 

percent reduction in SOa emissions 

results in emission reductions of 150 

Mg/year^165 tons/year) over the 

regulatory baseline. The SOa emission 

reductions associated with a standard 

requiring a percent reduction in SOa 

emissions are greater, therefore, than 

those associated with a standard based 

on the use of low sulfur coal. 

As shown in Tables 6-15 and 6-16 of 

"Summary of Regulatory Analysis," the 

potential increase over the regulatory 

baseline in annualized costs of a new 44 

MW (150 million Btu/hour) heat input 

capacity mixed fuel-fired steam 

generating unit associated with 

standards based on the use of low sulfur 

coal is about 1 or 2 percent in both 

Region V and Region VIII. The potential 

increase in annualized costs over the 

regulatory baseline associated with 

standards requiring a percent reduction 

in emissions is about 8 or 9 percent in 

Region V and about 10 or 11 percent in 

Region VIII. Thus, the incremental 

increase in annualized costs as a result 

of standards requiring a percent 

reduction in emissions over standards 

based on the use of low sulfur coal for 

mixed fuel-fired steam generating units 

is about 7 to 8 percent in Region V and 9 

to 10 percent in Region VIII. 

On the basis of the emission 

reductions and potential annualized cost 

increases noted above, the average cost 

effectiveness of standards based on the 

use of low sulfur coal in Region V is 

between $440/Mg ($400/ton) and $480/ 

Mg ($440/ton) of SOa removed for 

typical mixed fuel-fired steam 

generating units with annual fossil fuel 

utilization factors between 0.3 and 0.15, 

respectively. For standards requiring a 

percent reduction in SOa emissions, the 

average cost effectiveness in Region V 

ranges from $1,250/Mg ($l,150/ton) of 

SOa removed for a mixed fuel-fired 

steam generating unit with an annual 

fossil fuel utilization factor of 0.3 to 

$2,130/Mg ($l,930/ton) of SOa removed 

for a mixed fuel-fired steam generating 

unit with an annual fossil fuel utilization 

factor of 0.15. In Region VIII, the average 

cost effectiveness of standards based on 

the use of low sulfur coal is between 

$240/Mg ($220/ton) and $300/Mg ($270/ 

ton) of SOa removed for mixed fuel-fired 

steam generating units with annual 

fossil fuel utilization factors between 0.3 

and 0.15, respectively. For standards 

requiring a percent reduction in SOa 

emissions, the average cost 

effectiveness in Region VIII ranges from 

$1,190/Mg ($1,080/ton) of SOa removed 

for a mixed fuel-fired steam generating 

unit with an annual fossil fuel utilization 

factor of 0.3 to $1,870/Mg ($l,700/ton) of 

SOa removed for a mixed fuel-fired 

steam generating unit with an annual 

fossil fuel utilization factor of 0.15. 

In Region V, the incremental cost 

effectiveness of a standard requiring a 

percent reduction in SOa emissions over 

a standard based on the use of low 

sulfur coal ranges from $3,080/Mg 

($2,790/ton) of SOa removed for a mixed 

fuel-fired steam generating unit with an 

annual fossil fuel utilization factor of 0.3 

to $5,110/Mg ($4,640/ton) of SOa 

removed for a mixed fuel-fired steam 

generating unit with an annual fossil 

fuel utilization factor of 0.15. Similarly, 

in Region VIII, the incremental cost 

effectiveness ranges from $2,420/Mg 

($2,200/ton) to $3,950/Mg ($3,580/ton) of 

SOa removed for mixed fuel-fired steam 

generating units with annual fossil fuel 

utilization factors between 0.3 and 0.15, 

respectively. 

These results indicate that both the 

average and incremental cost impacts 

associated with standards requiring a 

percent reduction in SOa emissions 

increase significantly as the fossil fuel 

utilization factor of a mixed fuel-fired 

steam generating unit decreases. 

As noted above and discussed in 

"Summary of Regulatory Analysis" 

under "Consideration of National 

Impacts," mixed fuel-fired steam 

generating units are not projected to fire 

natural gas instead of coal in response 

to a standard requiring a percent 

reduction in SOa emissions. This is true 

under both the high oil penetration and 

high coal penetration scenarios. Unlike 

fossil fuel-fired steam generating units, 

firing natural gas would not result in any 

significant reduction in steam generating 

unit capitatcosts which would partially 

offset the increased price of natural gas. 

Thus, unlike low capacity utilization 

factor fossil fuel-fired steam generating 

units which are likely to fire natural gas 

instead of coal to avoid the cost impacts 

discussed above, mixed fuel-fired steam 

generating units will likely incur the full 

cost impacts associated with standards 

requiring a percent reduction in SOa 

emissions. 

Both the analysis of impacts at the 

national level and the analysis of 

impacts at the individual steam 

generating unit level, therefore, indicate 

that the costs of a standard requiring a 

percent reduction in SOa emissions are 

disproportionate to the emission 

reductions obtained for mixed fuel-fired 

steam generating units that fire small 

amounts of coal relative to nonsulfurbearing fuel on an annual basis. 

Consequently, new mixed fuel-fired 

steam generating units with heat input 

capacities greater than 29 MW (100 

million Btu/hour) that have annual fossil 

fuel utilization factors of 0.3 or less are 

considered a category of steam 

generating units for which a percent 

reduction requirement would have 

unreasonable impacts. These analyses, 

however, also show that the impacts of 

standards containing emission limits 

only are reasonable for all sizes and 

types of mixed fuel-fired steam 

generating units. Accordingly, the basis 

of the standard for mixed fuel-fired 

industrial-commercial-institutional 

steam generating units with heat input 

capacities greater than 29 MW (100 

million Btu/hour) that operate at annual 

fossil fuel utilization factors for coal of 

30 percent (0.3) or less is an emission 

limit only. 

The analysis of national impacts, 

impacts on specific industries, and 

impacts on individual steam generating 

units have shown that the impacts of a 
P.27 

22408 Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 

standard requiring a percent reduction 

in SO2 emissions are reasonable for 

mixed fuel-fired steam generating units 

that operate at annual fossil fuel 

utilization factors greater than 0.3. These 

impacts are reasonable when compared 

to standards based on the use of low 

sulfur fuel and when compared to the 

regulatory baseline. Therefore, the basis 

of standards for mixed fuel-fired steam 

generating units with heat input 

capacities greater than 29 MW (100 

million Btu/hour) that operate at annual 

fossil fuel utilization factors for coal of 

more than 0.3 is a percent reduction in 

SO2 emissions. 

6. Selection of Standard for Mixed FuelFired Steam Generating Units 

As with coal- and oil-fired steam 

generating units, the SO2 control 

technologies which are capable of 

continuously achieving a percent 

reduction in SO2 emissions from mixed 

fuel-fired steam generating units include 

both combustion modifications and 

post-combustion controls. Combustion 

modification through the use of FBC has 

received widespread application to 

steam generating units which fire low 

quality fossil fuels and nonfossil fuels, 

including mixed fuel-fired steam 

generating units.' Wet and dry FGD 

technologies are also applicable to 

mixed fuel-fired steam generating units. 

The S02 emissions from a mixed fuelfired steam generating unit are a product 

of the sulfur content of the coal or oil in 

the fuel mixture. Consequently, the same 

technologies that are effective in 

controlling SO2 emissions from coal- or 

oil-fired steam generating units are also 

effective in controlling SO? emissions 

from steam generating units that fire 

coal or oil in combination with 

nonsulfur-bearing fuels. Further, these 

control technologies are capable of 

achieving the same level of emission 

reduction from mixed fuel-fired steam 

generating units as from coal- or oilfired steam generating units. 

As discussed in "Summary of 

Regulatory Analysis" under 

"Performance of Demonstrated Emission 

Control Technologies," analysis of data 

gathered to assess the performance of -

wet FGD technologies (sodium, lime/ 

limestone, and dual alkali), lime spray 

drying systems, and FBC systems 

indicates that these technologies are 

capable of continuously achieving a 90 

percent reduction in SOa emissions from 

coal- and oil-fired steam generating 

units. Because, as mentioned above, 

these technologies are capable of 

achieving the same level of performance 

on mixed fuel-fired steam generating 

units, a 90 percent reduction in SO2 

emissions on a 30-day rolling average 

basis through the use of these 

technologies is considered demonstrated 

for mixed fuel-fired steam generating 

units. 

The cost impacts associated with a 

range of percent reduction requirements 

were examined for coal- and oil-fired 

steam generating units. As discussed 

above, these analyses indicate that a 90 

percent reduction requirement achieves 

the greatest emission reductions at costs 

only slightly higher than those 

associated with lower percent reduction 

requirements and that a 90 percent 

reduction requirement is more cost 

effective than lower percent reduction 

requirements. Similarly, a 90 percent 

reduction requirement for mixed fuelfired steam generating units would also 

result in the greatest emission reduction 

at costs only slightly higher than those 

associated with lower percent reduction 

requirements. 

As discussed above, the analysis of 

cost impacts of percent reduction 

standards on fossil fuel-fired steam 

generating units operating at low annual 

capacity utilization factors can be used 

• to represent the impacts of percent 

reduction requirements on mixed fuelfired steam generating units. 

Consequently, as shown in Table 6-10 of 

"Summary of Regulatory Analysis," for 

a mixed fuel-fired steam generating unit 

located in EPA Region VIII and 

operating at an annual fossil fuel 

utilization factor of 0.30, the average 

cost effectiveness of a 50 percent 

reduction requirement is $1,380/Mg 

($l,250/ton) of SOa removed. For a 70 

percent reduction requirement, the 

average cost effectiveness is $1,270/Mg 

($1,150/ton) of SOa removed, and for a 

90 percent reduction requirement, the 

average cost effectiveness is $1,200/Mg 

($l,090/ton) of SOa removed. 

As discussed above, the ability of wet 

FGD systems, lime spray drying 

systems, and FBC systems to achieve a 

90 percent' reduction in SO2 emissions 

on a 30-day rolling average basis from 

mixed fuel-fired steam generating units 

is considered demonstrated. Thus, a 

standard requiring a 90 percent 

reduction in SO2 emissions has been 

selected for new mixed fuel-fired steam 

generating units of greater than 29 MW 

(100 million Btu/hour) heat input 

capacity that have an annual fossil fuel 

utilization factor of greater than 0.30 

(except for units using emerging 

technologies, as discussed below). 

Because mixed fuel-fired steam 

generating units obtain their fossil fuel 

supplies from the same market sources 

as fossil fuel-fired steam generating 

units, the same consideration was given 

to emission limits which, when 

combined with a 90 percent reduction in 

SOa emissions, would not preclude the 

use of high sulfur fuels. Therefore, 

emission limits of 516 ng/J (1.2 lb/ 

million Btu) heat input for mixed fuelfired steam generating units firing coal, 

and 344 ng/J (0.8 lb/million Btu) heat 

input for mixed fuel-fired steam 

generating units firing oil, have been 

selected as the emission limits included 

in the 90 percent reduction standard for 

new industrial-commercial-institutional 

mixed fuel-fired steam generating units. 

As discussed above for coal-fired and 

oil-fired steam generating units, it is 

questionable whether the standards 

discussed above could be achieved by 

emerging technologies. The importance 

of accommodating emerging 

technologies has also been discussed 

previously. Establishing less stringent 

percent reduction requirements for 

emerging technologies would increase 

the likelihood that owners and operators 

of new industrial-commercialinstitutional steam generating units 

firing mixed fuels will install and 

operate these systems. 

As discussed above, emerging SOa 

control technologies are being 

developed primarily for application to 

coal-fired steam generating units. 

Nonetheless, such emerging technologies 

as dry alkali injection, electron beam 

irradiation, and LIMB could be applied 

to mixed fuel firing as well. There are, in 

addition, no reasons to expect that the 

performance of emerging technologies 

when applied to mixed fuel-fired ateam 

generating units would be any better or 

worse than that for coal- or oil-fired 

steam generating units. Therefore, the 

proposed standards would require all 

new, modified, or reconstructed mixed 

fuel-fired industrial-commercialinstitutional steam generating units 

which have heat input capacities greater 

than 29 MW (100 million Btu/hour), 

which have an annual fossil fuel 

utilization factor of greater than 0.30, 

and which employ emerging SOa control 

technologies, to achieve a 50 percent 

reduction in SO2 emissions. 

In order to minimize emissions from 

mixed fuel-fired steam generating units 

using an emerging technology for SOa 

control and subject to the 50 percent 

reduction requirement, the proposed 

standard includes SOa emission limits of 

258 ng/J (0.6 lb/million Btu) and 172 ng 

SOa/J (0.4 lb SOa/million Btu) heat input 

for steam generating units firing coal 

and oil, respectively, in a fuel mixture. 

As discussed above, these emission 

limits are one-half the otherwise 

applicable SOa emission limits. As a 

result, the use of emerging technologies 

achieving the minimum percent 
P.28 

Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 22409 

reduction in SOa emissions is limited to 

mixed fuel-fired steam generating units 

firing coal with a sulfur content of 516 ng 

SOa/J (12 lb Sa/million Btu) heat input 

or less, or oil with a sulfur content of 344 

ng SOa/J (0.8 lb SOa/million Btu) heat 

input or less. However, to the extent 

that these technologies can achieve SOa 

emission reductions of greater than 50 

percent, coals or oils with higher sulfur 

contents can be burned without 

exceeding the proposed emission limit. 

Because higher sulfur fuels are generally 

less expensive than low sulfur fuels, this 

will act as an incentive to achieve 

percent reductions of greater than 50 

percent. 

The proposed standards, therefore, 

provide a limited "window" for use of 

emerging technologies. This window will 

be reviewed regularly during the course 

of the review process associated with all 

NSPS. As appropriate, the percent 

reduction requirements will be revised 

upwards in light of additional 

performance data available at that time 

for emerging technologies. As a result of 

these reviews, emerging control 

technologies that do not demonstrate 

improvements in performance 

capabilities, or show no promise of 

achieving emission reductions greater 

than 50 percent, will no longer be 

considered emerging technologies and 

would be subjected to the same 

requirements as those included in the 

standards for conventional 

demonstrated technologies. 

As discussed above, the application of 

a percent reduction requirement to 

mixed fuel-fired steam generating units 

that have an annual fossil fuel 

utilization factor of 0.30 or less is 

considered unreasonable. Consequently, 

the standard for this category of steam 

generating units is an emission limit 

only. In selecting an SOa emission limit 

for this category of mixed fuel-fired 

steam generating units, consideration 

focused on the analysis of individual 

steam generating unit costs for coalfired steam generating units which 

operate at low annual capacity 

utilization factors. 

The analysis of the costs of 

alternative control levels or standards 

centered on SOa emission limits of 731 

ng/J (1.7 lb/million Btu) heat input and 

516 ng/f (1.2 lb/million Btu) heat input. 

Analysis of a higher emission limit was 

unnecessary because a higher limit 

would be equal to the regulatory 

baseline. On the other hand, an 

emission limit lower than 516 ng/J (1.2 

lb/million Btu) was not considered 

because coals of lower sulfur content 

are not widely available throughout the 

United States. 

As discussed above, the impacts of 

alternative control levels or standards 

on mixed fuel-fired steam generating 

units may be considered by examining 

the impacts discussed above and in 

"Summary of Regulatory Analysis" 

under "Consideration of Demonstrated 

Emission Control Technologies" on coalfired steam generating units operating at 

low capacity utilization factors. 

At an annual capacity utilization 

factor of 0.3 for coal (i.e.. annual fossil 

fuel utilization factor of 0.3 for coal), an 

SOa emission limit of 731 ng/J (1.7 lb/ 

million Btu) heat input reduces SOa 

emission reductions from a 44 MW (150 

million Btu/hour) heat input capacity 

mixed fuel-fired steam generating unit 

by 115 Mg/year (130 tons/year) over the 

regulatory baseline. An emission limit of 

516 ng/J (1.2 lb/million Btu) heat input 

results in SOa emission reductions of 205 

Mg/year (230 tons/year) over the 

regulatory baseline. Thus, the 

incremental reduction in SOa emissions 

achieved by an emission limit of 516 ng 

SOa/J (1.2 lb SOa/million Btu) heat input 

over an emission limit of 731 ng SOa/J 

(1.7 lb SOa/million Btu) heat input is 90 

Mg/year (100 tons/year). 

At an annual fossil fuel utilization 

factor of 0.15 for coal, an SOa emission 

limit of 731 ng/J (1.7 lb/million Btu) heat 

input achieves SOa emission reductions 

from a 44 MW (150 million Btu/hour) 

heat input capacity mixed fuel-fired 

steam generating unit of 60 Mg/year (65 

tons/year) over the regulatory baseline. 

An emission limit of 518 ng/J (1.2 lb/ 

million Btu) heat input results in SO« 

emission reductions of 105 Mg/year (115 

tons/year) over the regulatory baseline. 

Thus, the incremental reduction in 

emissions achieved by an emission limit 

of 516 ng SOa/J (1.2 lb SOa/million Btu) 

heat input over an emission limit of 731 

ng SOa/J (1.7 lb SOa/million Btu) heat 

input is 45 Mg/year (50 tons/year). 

The potential increases in annualized 

costs associated with these alternative 

standards are shown in Tables 6-15 and 

6-16 of "Summary of Regulatory 

Analysis." The potential increase in the 

annualized costs over the regulatory 

baseline as a result of compliance with 

an alternative control level or standard 

of 731 ng SOa/J (1.7 lb SOa/million Btu) 

heat input is about 1 percent for a 44 

MW (150 million Btu/hour) heat input 

capacity mixed fuel-fired steam 

generating unit operating at annual 

fossil fuel utilization factors of 0.15 to 0.3 

in both Region V and Region VIII. The 

potential increase in annualized costs of 

a new mixed fuel-fired steam generating 

unit over the regulatory baseline as a 

result of compliance with an alternative 

control level or standard of 516 ng SOa/J 

(1.2 lb SOa/million Btu) heat inpu 

about 1 percent in Region VIII. and Irom 

1 to 2 percent in Region V. Tl 

incremental cost Inc 

with an alternative control level or 

standard of 516 ng SOa/J (1.2 lb SO./ 

million Btu) heat input over an 

alternative control l< 

731 ng SOa/J (1.7 lb SOa/million Btu) 

heat input is generally in the rang' 

percent or less for a new mi -

fired steam generating unit. 

On the basis ofthe 

reductions and potential increav 

annualized costs, .h< cost 

effectiveness of an e 

level or stand [(1.7 lb 

SOa/million Btu) heat input ranges from 

$250/Mg ($230/ton) of SOa re: 

$340/Mg ($310/ton) of SOa removed W 

a 44 MW (150 million Btu/hour) I. 

inpu! mixed fuel-fir;' 

generating unit operating an anm 

fossil fuel utilization factor for coal ot 

0.15 and 0.3, depending on region 

location. The average cost e -ss 

of an alternative control leva 

standard of 516 ng SOa/J (1.2 lb SO?/ 

million Btu) heat input ranges from 

$240/Mg ($220/ton) of SOa remov 

$480/Mg ($440/ton) of SOa remov 

Thus, the incremental i 

of an alternative control level or 

standard of 516 ng SOa (1.2 lb SOa/ 

million Btu) heat input over an 

alternative control level or standi 

731 ng SOa/J (1.7 lb SOa/million I 

heat input ranges from $110/Mg ($ 

ton) of SOa removed to $670/Mg (S 

ton) of SOa removed. 

These results indicate that u 

limiting emissions of SOJ from nu 

fuel-fired steam generating units with 

annual fossil fuel utilization factors for 

coal of 0.3 or less to 518 ng SOa/J (1 2 lb 

SOa/million Btu) heat input would 

achieve greater emissir. 

than an alternative standard of 73 

SOa/J (1.7 lb SOa/million Btu) heat input 

at reasonable costs. The 

emission limit of 518 ng SOa/J (1.2 lb 

SOa/million Btu) heat input h 

selected for mixed fuel -fired Industrial' 

commercial-institutional steam 

generating units operating at annual 

fossil fuel utilization factors for coal of 

0.3 or less. 

7. Other Considerations 

Percent Redaction Cn 

Pretreatment. Section 111(a)(1) of the 

Clean Air Act permits ; in 

emissions resulting from pretreatment of 

fuels to be credited toward satisfying 

the percent reduction 

included in standards of performs 

for fossil fuel-fired stationary sources, 

The proposed standards, thi 
P.29 

Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 

include such credits. These credits, 

however, are applied in such a way that 

the uncontrolled, or partially controlled, 

emissions from firing the pretreated fuel 

are no greater than the controlled 

emissions which would have occurred if 

the untreated fuel had been fired. 

For example, if a coal with a sulfur 

content of 1,000 ng SOa/J (2.3 lb S02/ 

million Btu) heat input was treated to 

reduce the sulfur content to 750 ng SOa/J 

(1.7 lb S02/million Btu) prior to being 

fired, a credit for this reduction in the 

sulfur content of the coal could be 

applied towards compliance with the 

percent reduction requirements included 

in the proposed standards. Without 

pretreatment, a 90 percent reduction 

requirement would require that SO2 

emissions be reduced to 100 ng SOa/J 

(0.23 lb SOa/million Btu). With 

pretreatment, SOa emissions must still 

be reduced to this same level. 

Pretreatment, therefore, effectively 

reduces the minimal percent reduction 

requirement from 90 percent to 87 

percent in this case. 

Types of coal pretreatment processes 

for which percent reduction credits 

would be given include physical coal 

cleaning and solvent refining. Crushing 

and screening to separate rock and 

other material from raw coal prior to 

processing or shipment would not be 

considered fuel pretreatment processes. 

The primary type of oil pretreatment 

process for which percent reduction 

credits would be given is 

hydrodesulfurization. The fuel 

pretreatment credit would be 

determined by the sulfur content of the 

residual oil prior to hydrodesulfurization 

compared to the sulfur content of the 

residual oil. following 

hydrodesulfurization. Distillation to 

separate oils into various fractions or 

blending of oils to meet various fuel oil 

specifications such as viscosity or sulfur 

content would not be considered fuel 

pretreatment processes. 

Credits for the reduction in SOa 

emissions resulting from fuel 

pretreatment may be applied toward 

compliance with the 90 percent 

reduction requirement included in the 

standards. However, credits for fuel 

pretreatment may not be applied toward 

compliance with the 50 percent 

reduction requirement for emerging 

technologies. The primary objective of 

the 50 percent reduction requirement is 

to stimulate and encourage the 

development and use of emerging SO2 

emission control technologies. If a credit 

were provided for the percent reduction 

achieved as a result of fuel 

pretreatment, emerging technologies 

could be operated at performance levels 

significantly below the minimum level of 

50 percent. 

The decision not to allow percent 

reduction credits for fuel pretreatment 

with the SOa standard for emerging 

technologies will not have any adverse 

impacts on the continued development 

or use of emerging or conventional fuel 

pretreatment technologies. 

Owners or operators wishing to 

receive credit for the percent reduction 

in SOa emissions achieved by fuel 

pretreatment are required to provide 

documentation that the fuel used has 

undergone pretreatment for purposes of 

reducing sulfur content. Two types of 

documentation would be required. First, 

a statement from the fuel pretreatment 

facility would be required that identifies 

the fuel sulfur content before and. after 

pretreatment". This statement must also 

outline the process(es) used to reduce 

fuel sulfur content and confirm that the 

percent sulfur removal reported was 

determined in accordance with 

Reference Method 19 or an approved 

alternative method. Second, 

documentation would be required to 

ensure that the fuel fired in the steam 

generating unit is the same fuel that has 

undergone pretreatment. This would 

include documentation tracking the 

shipment of the fuel between the 

pretreatment facility and the steam 

generating unit. 

Conventional oil pretreatment 

technologies, such as 

hydrodesulfurization, are capable of 

reducing the sulfur content of residual 

fuel oil from about 70 to more than 95 

percent. Thus, in some cases, the 

proposed standards of performance for 

oil-fired steam generating units could be 

achieved with little or no additional 

post-combustion control of SOa' 

emissions. In fact, considering the sulfur 

content of typical untreated residual fuel 

oils, in combination with the 

performance capabilities of 

hydrodesulfurization processes and FGD 

systems, achieving an SOa emission rate 

of 86 ng/J (0.2 lb/million Btu) heat input 

or less at an oil-fired steam generating 

unit generally reflects a percent 

reduction in SOa emissions of 90 percent 

or more. This holds true whether fuel 

pretreatment is used alone or in 

combination with an FGD system. 

Therefore, owners or operators of oilr 

fired steam generating units that can 

show, in accordance with procedures 

outlined in Method 19 or 19A, that SOa 

emissions have been reduced to 86 ng/J 

(0.2 lb/million Btu) heat input or less, 

are not required to provide additional 

documentation to demonstrate 

compliance with the percent reduction 

requirement of the standards. This 

serves to remove the unnecessary 

administrative burden associated with 

the documentation procedures outlined 

above to obtain percent reduction 

credits for oil-fired steam generating 

units firing very low sulfur oils [i.e., 86 

ng SOa/J (0.2 lb SOa/million Btu) heat 

input or less]. 

Conventional coal pretreatment 

technologies, such as physical coal 

cleaning, on the other hand, are 

generally only capable of reducing the 

sulfur content of coal by about 20 to 30 

percent. In all cases, therefore, coalfired steam generating units will need to 

employ an FGD system to comply with 

the proposed standards. In addition, 

documenting the percent reduction 

achieved by physical coal cleaning and 

tracking the shipment of coal from a 

coal cleaning plant to a coal-fired steam 

generating unit should prove less 

complex than for oil. Consequently, 

provisions similar to those mentioned 

above for very low sulfur oils are not 

provided for coal. 

Emission Credits for Cogeneration 

and Mixed Fuel Firing. As discussed in 

"Summary of Regulatory Analysis" 

under "Consideration of Emission 

Credits," the impacts of emission credits 

were analyzed for two general types of 

industrial-commercial-institutional 

steam generating units: cogeneration 

steam generating units and mixed fuelfired steam generating units. If emission 

credits were included in the proposed 

standards, they would permit higher SOa 

emissions from these types of steam 

generating units. In the case of a 

cogeneration steam generating unit, this 

emission credit would permit SOa 

emissions (in terms of pounds or tons 

per day, for example) to increase to the 

level that would have existed if a 

conventional, rather than a 

cogeneration, steam generating unit had 

been installed. In the case of a mixed 

fuel-fired steam generating unit, this 

emission credit would permit SOa 

emissions to increase to the same level 

that would have existed if only coal or 

oil, rather than a mixture of sulfurbearing and nonsulfur-bearing fuels, 

were fired in the steam generating unit. 

In either case, therefore, the 

environmental benefits associated with 

cogeneration or mixed fuel firing, in 

terms of decreased SOa emissions, 

would be eliminated by providing 

emission credits. 

As illustrated by Tables 10-1 and 10-4 

of "Summary of Regulatory Analysis," 

emission credits for oil- and coal-fired 

cogeneration steam generating units 

would result in very small and relatively 

insignificant cost savings. Iri contrast, 

however, annual SO2 emissions from 
P.30 

leg / Vol. 51. No. 118 / Thursday, June 19, 1986 / Proposed Rules 22411 

cogeneration steam generating units 

could increase substantially. Similarly, 

the analysis of emission credits for oiland coal-fired combined cycle steam 

generating units (see Tables 10-6 and 

10-9 of "Summary of Regulatory 

Analysis") indicates that emission 

credits would also result in very small 

cost savings, but substantial and very 

significant increases in SOa emissions. 

The incremental cost effectiveness 

associated with the incremental 

reductions in SOa emissions achieved by 

not providing emission credits for 

cogeneration and combined cycle steam 

generating units is generally less than 

$1,100/Mg ($l,000/ton) of SOa removed 

for all fuels and regional locations 

examined. This is not considered 

unreasonable and, as a result, the 

proposed standards do not include 

emission credits for steam generating 

units employed as part of cogeneration 

or combined cycle systems. 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of Emission Credits," the 

analysis of emission credits for mixed 

fuel-fired steam generating units 

indicates that emission credits for the 

heat input supplied to the steam 

generating unit from combustion of 

nonsulfur-bearing fuels, such as wood or 

municipal waste, would result in very 

small reductions in costs, but very large 

and significant increases in SOa 

emissions. The incremental cost 

effectiveness associated with the 

incremental reduction in SOa emissions 

achieved by not providing emission 

credits for mixed fuel-fired steam 

generating units is generally less than 

$460/Mg ($420/ton) of SOa removed for 

both coal- and oil-fired steam generating 

units. This is not considered 

unreasonable and, as a result, the 

proposed standards do not include 

emission credits for mixed fuel-fired 

steam generating units. 

Provisions for FGD Malfunction.. The 

General Provisions included iii 40 CFR, 

Part 60, which apply to all standards of 

performance, define a malfunction as 

". . . any sudden and unavoidable 

failure of air pollution control equipment 

. . . to operate in a normal or usual 

manner. Failures that are caused 

entirely or in part by poor maintenance, 

careless operation, or any other 

preventable upset condition or 

preventable equipment breakdown shall 

not be considered malfunctions." 

A well operated and properly 

maintained FGD system is capable of 

achieving a high degree of reliability. As 

discussed in "Summary of Regulatory 

Analysis" under "Performance of 

Demonstrated Emission Control 

Technologies," long-term reliabilities in 

excess of 95 percent have been reported 

for many FGD systems. As with any 

piece of equipment, however, there may 

be occasional instances of malfunctions 

during which control of SOa emissions 

may be limited or curtailed for short 

periods of time. 

If an FGD malfunction does occur, 

there are several methods by which 

emissions could be minimized during the 

period when the FGD system is not 

operational. These include the 

temporary use of low sulfur or 

nonsulfur-bearing fuels, such as very 

low sulfur fuel oils or natural gas; the 

use of a spare FGD absorber module; or 

even temporary shutdown of the steam 

generating unit at those sites with 

multiple steam generating units. 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of Demonstrated 

Emission Control Technology Costs," 

the costs associated with the use of each 

of these alternatives (with the exception 

of temporary shutdown of the steam 

generating unit) were examined. The 

variation in the costs among the use of 

natural gas, very low sulfur fuel oil, or a 

spare FGD module, however, is 

relatively small. For purposes of the 

analyses discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of Demonstrated 

Emission Control Technology Costs" 

and "Consideration of National 

Impacts," therefore, the use of natural 

gas was assumed during periods of FGD 

system malfunction. (The FGD system 

malfunctions were assumed to occur 5 

percent of the time on an annual basis.) 

Thus, the costs associated with this 

general approach of firing natural gas, 

very low sulfur oil, or using a spare FGD 

module to control SOa emissions during 

periods of FGD system malfunction 

were included throughout all of the 

analyses discussed above. 

The proposed standards, therefore, 

would not permit increased SOa 

emissions during periods of FGD system 

malfunction. The standards would 

require SOa emission data collected 

during periods of FGD malfunction to be 

included in calculating the 30-day rolling 

average SOa emission rate and percent 

reduction for each reporting period 

during which an FGD malfunction 

occurred. 

As discussed above, combustion of a 

very low sulfur fuel oil with a sulfur 

content of 86 ng SOa/J (0.2 lb SOa/ 

million Btu) or less would ensure 

compliance with the percent reduction 

requirements included in the proposed 

standards. Therefore, if fuel oil with a 

sulfur content of 86 ng SOa/J (0.2 lb SOa/ 

million Btu) or less is fired in a steam 

generating unit during periods of FGD 

malfunction, a percent reduction of 80 

percent may be assumed, as 

appropriate, for purposes of calculating 

30-day-rolling averages for those periods 

during which FGD malfunctions 

occurred. The SOa emission rate 

associated with firing very low sulfur oil 

during periods of FGD malfunction may 

be determined either through continuous 

emission monitoring or fuel sampling 

and analysis. 

As discussed below under 

"Performance Test Methods and 

Monitoring Requirements," periods 

during which either coal or oil is not 

fired are not included in trie steam 

generating unit operating hours for 

purposes of calculating the 30-day 

rolling averages. 

Provisions for Startup and Shutdown. 

The operation of some industrialcommercial-institutional steam 

generating units may be cyclic or 

periodic in nature. These types of units 

are often operated for only a few hours 

per day or on a sporadic or seasonal 

basis, making the occurrence of startup 

and shutdown periods for such units 

relatively frequent. Emissions during 

these periods, therefore, could be a 

significant portion of the total annual 

SO2 emissions from these steam 

generating units. 

The FGD systems do not achieve their 

peak performance levels immediately 

after a "cold" startup. Some time io 

usually required for FGD systems to 

reach their optimum operating 

temperature or to reach chemical 

equilibrium. However, a review of the 

factors affecting the performance of SOa 

control systems indicates that SOa 

removal efficiency can be maintained at 

high levels even during periods of 

startup and shutdown. Any short-term 

variability in SOa emissions that may 

result from fluctuations in control device 

performance during system startup 

would be minimized over a 30-day 

averaging period. 

Because of the potentially significant 

emissions that could occur during 

periods of startup and shutdown, and 

because techniques exist (such as firing 

natural gas or very low sulfur oil) that 

can minimize emissions during these 

periods, the proposed standards include 

a provision that emission data collected 

during periods of startup and shutdown 

be included in the calculations of all 30-

day rolling average percent reduction 

and SOa emission values. As discussed 

above for FGD malfunction, periods in 

which a nonsulfur-bearing fuel such as 

natural gas is the only fuel fired would 

not be considered steam generating unit 

operating hours for purposes of 

calculating 30-day rolling averages. 
P.31 

22412 Federal Register / Vol. 51, No, 118 / Thursday, June 19, 1986 / Proposed Rules 

D. Selection of Best System of 

Particulate Matter Emission Reduction 

Standards of performance for new 

industrial-commercial-institutional 

steam generating units were proposed 

on June 19,1984 (49 FR 25102). These 

standards of performance included PM 

emission limits for steam generating 

units firing coal, wood, municipal-type 

solid waste, and mixtures of fossil and 

nonfossil fuels. The June 19,1984 

proposal did not include PM standards 

for oil-fired industrial-commercialinstitutional steam generating units. 

As discussed above, the proposed 

standards for control of SOa emissions 

would require all coal-fired industrialcommercial-institutional steam 

generating units to achieve a percent , 

reduction in SOa emissions. In order to 

meet this requirement, owners and 

operators of coal-fired steam generating 

units are anticipated to install SOa 

control devices. These devices will 

consist primarily of wet FGD systems. 

As discussed in "Summary of 

Regulatory Analysis," wet FGD systems 

are capable of reducing emissions of PM 

as well as emissions of SOa from 

industrial-commercial-institutional 

steam generating units. Consequently, 

the proposed PM standards for coalfired steam generating units (49 FR 

25102) were reviewed to determine 

whether different standards for PM 

emissions should apply to coal-fired 

steam generating units subject to the 

proposed SOa standards. 

The proposed SOJ standards would 

also require oil-fired industrialcommercial-institutional steam 

generating units to achieve a percent 

. reduction in SOa emissions. As with 

coal-fired steam generating units, the 

use of FGD systems to reduce SOa 

emissions from oil-fired steam 

generating units can also reduce PM 

emissions. Similarly, the use of low 

sulfur/low ash oil to reduce emissions of 

SOa also reduces emissions of PM. 

Therefore, standards limiting emissions 

of PM from oil-fired steam generating 

units were also considered. 

1. Coal-Fired Steam Generating Units 

The regulatory analysis (see 

"Performance of Demonstrated Emission 

Control Technologies" in "Summary of 

Regulatory Analysis") concluded that 

wet FGD systems are capable of 

reducing PM emissions from coal-fired 

steam generating units to 43 ng/J (0.1 lb/ 

million Btu) heat input or less. The 

analysis conducted for the previously 

proposed PM standards (49 FR 25102) 

indicated that fabric filters and 

electrostatic precipitators (ESP's) can 

reduce PM emissions from these units to 

22 ng/J (0.05 lb/million Btu) heat input or 

less. 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of Demonstrated 

Emission Control Technology Costs" 

and shown in Table 6-32, the costs of an 

FGD system that is capable of 

controlling both PM and SC^ emissions 

are greater than the costs of an FGD 

system for controlling SOa emissions 

alone. For example, a sodium FGD 

system capable of reducing PM 

emissions to 43 ng/J (0.1 lb/million Btu) 

heat input or less from a typical 44 MW 

(150 million Btu/hour) heat input 

capacity steam generating unit firing 

coal would cost about $400,000/year 

more to operate than an FGD system 

designed to control SOa only. The 

annualized cost of installing and 

operating an ESP upstream of an FGD 

system used for SOa control alone would 

be about $390,000, and the annualized 

cost of operating a fabric filter upstream 

of an FGD for SOa control alone would 

be about $420,000. 

The use of an ESP or a fabric filter 

achieves incremental reductions in 

particulate emissions of about 18 Mg/ 

year (20 tons/year) over those achieved 

by the use of an FGD capable of 

controlling both PM and SO2 emissions 

for a typical 44 MW (150 million Btu/ 

hour) heat input capacity steam 

generating unit firing coal. In the case of , 

an ESP, these additional emission 

reductions are achieved at no additional 

cost above those associated with using 

an FGD system for combined control of 

SOa and PM. The incremental cost 

effectiveness of using a fabric filter 

upstream of an FGD system, compared 

to using an FGD system for combined 

control of SOa and PM, is about $1,275/ 

Mg ($l,160/ton) of particulate matter 

removed. 

The use of a fabric filter or ESP to 

reduce PM emissions in combination 

with an FGD system to reduce SOa 

emissions from coal-fired steam 

generating units, therefore, is considered 

reasonable. Consequently, the PM 

emission limit of 22 ng/J (0.05 lb/million 

Btu) heat input previously proposed for 

industrial-commercial-institutional coalfired steam generating units remains 

applicable to new coal-fired steam 

generating units subject to today's 

proposed SOa standards. 

2. Oil-Fired Steam Generating Units 

As discussed above, wet FGD systems 

installed to reduce SOa emissions from 

oil-fired steam generating units can also 

reduce PM emissions. However, unlike 

FGD systems installed on coal-fired 

steam generating units, FGD systems 

installed on oil-fired steam generating 

units for control of both SOa and PM 

emissions are no different from those 

installed for control of SOa emissions 

alone. For oil-fired steam generating 

units, therefore, PM emission reductions 

achieved by FGD systems are achieved 

at a negligible incremental cost over the 

costs associated with SOa control alone. 

As a result, the use of an FGD system is 

highly cost effective for controlling PM 

emissions from oil-fired steam 

generating units in those instances 

where these control techniques are used 

for purposes of SOa control. Therefore, 

the reductions in PM emissions achieved 

by FGD systems can be viewed as 

representing the minimum level of PM 

control that merits consideration for oilfired steam generating units. 

As discussed above, the proposed 

standards require oil-fired steam 

generating units to achieve a percent 

reduction in SOa emissions. With the 

exception, discussed above, for oil-fired 

steam generating units firing very low 

sulfur oil, this will require the use of 

FGD systems. 

The regulatory analysis (see 

"Performance of Demonstrated Emission ' 

Control Technologies" in "Summary of 

Regulatory Analysis") concluded that 

FGD systems are capable of reducing 

PM emissions from oil-fired steam 

generating units to 43 ng/J (0.10 lb/ 

million Btu) heat input or less. As also 

discussed, however, ESP's can reduce 

PM emissions from oil-fired steam 

generating units to 30 ng/J (0.07 lb/ 

million Btu) heat input or less. The use 

of an ESP upstream of an FGD system, 

therefore, would reduce PM emissions 

from oil-fired steam generating units to 

30 ng/J (0.07 lb/million Btu) heat input or 

less. 

As discussed in "Summary of 

Regulatory Analysis" under 

"Consideration of Demonstrated 

Emission Control Technology Costs" 

and shown in Table 6-31, annual PM 

emissions are reduced from about 82 

Mg/year (90 tons/year) to about 33 Mg/ 

year (36 tons/year) when an FGD 

system is installed to control emissions 

of SOa from a typical high sulfur oil-fired 

steam generating unit. The addition of 

an ESP upstream of an FGD system 

would reduce PM emissions from a 

typical 44 MW (150 million Btu/hour) 

heat input capacity steam generating 

unit from 33 Mg/year (36 tons/year) to 

23 Mg/year (25 tons/year). The 

incremental annualized cost of installing 

and operating an ESP upstream of an 

FGD system would be about $340,000. 

Therefore, the incremental cost 

effectiveness associated with adding an 

ESP to an oil-fired steam generating unit 

equipped with an FGD system would be 
P.32 

Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 22413 

about $34,O00/Mg ($31,000/ton) of PM 

removed. This is considered 

unreasonable given the small 

incremental amount of PM control 

achieved. Therefore, a PM emission limit 

of 43 ng/J (0.10 lb/million Btu) heat input 

is proposed for oil-fired industrialcommercial-institutional steam 

generating units. 

E. Modification and Reconstruction 

Provisions 

Existing steam generating units that 

are modified or reconstructed would be 

subject to the requirements in the 

General Provisions (40 CFR 60.14 and 

60.15) which apply to all NSPS. Few, if 

any, changes typically made to existing 

steam generating units would be 

expected fo bring such steam generating 

units under the proposed SOa or PM 

standards. 

A modification is any physical or 

operational change to an existing facility 

that results in an increase in emissions. 

Changes to an existing facility that do 

not result in an increase in emissions, 

either because the nature of the change 

has no effect on emissions or because 

additional emission control technology 

is employed to offset an increase in 

emissions, are not considered 

modifications. In addition, certain 

changes have been exempted under the 

General Provisions (40 CFR 60.14). 

These exemptions include: routine 

maintenance, repair, and replacement; 

production increases achieved without a 

capital expenditure as defined in § 60.2; 

production increases resulting from an 

increase in the hours of operation; 

addition or replacement of equipment 

for emission control (as long as the 

replacement does not increase 

emissions); relocation or change of 

ownership of an existing facility; and 

use of an alternative fuel or raw 

material if the existing facility was 

designed to accommodate if. In addition, 

both Section 111 of the Clean Air Act 

and 40 CFR 60.14 of the General 

Provisions exempt mandatory 

conversions to coal. 

Reconstruction of an existing facility 

would make that facility subject to an 

NSPS regardless of any change in the 

emission rate, depending on the cost of 

the replaced components and the 

feasibility of meeting the standards. 

Reconstructed steam generating units 

would become subject to the proposed 

standards under the reconstruction -

provisions, regardless of changes in 

emission rate, if the fixed capital cost of 

reconstruction exceeds 50 percent of the 

cost of an entirely new steam generating 

unit of comparable design and if it is 

technologically and economically 

feasible to meet the applicable 

standards. Costs associated with steam 

generating unit routine maintenance are 

not included in determining 

reconstruction costs. 

F. Performance Test Methods and 

Monitoring Requirements 

The performance testing and emission 

monitoring requirements included in the 

proposed regulation would apply to all 

industrial-commercial-institutional 

steam generating units subject fo the 

proposed SOa emission standards and 

oil-fired industrial-commercialinstitutional steam generating units 

subject to the proposed PM standards. 

1. Sulfur Dioxide 

The proposed regulation includes 

provisions for continuous monitoring of 

SOa emissions to demonstrate 

continuous compliance with the 

standards. This would be accomplished 

through the installation and operation of 

continuous emission monitoring systems 

(CEMS) at the inlet and outlet of the SOa 

control device. Data collected by the 

CEMS would be used to determine 

compliance with the SOa percent 

reduction requirements and emission 

limits in accordance with Reference 

Method 19 (Appendix A). As-fired fuel 

sampling and analysis at the inlet to the 

steam generating unit or emissions 

measurement in accordance with 

Reference Method 6B at the inlet or 

outlet fo the steam generating unit may 

be used in lieu of CEMS. 

Affected facilities for which an 

emission limit only has been established 

would be able to monitor SOa emissions 

using any of the procedures included in 

Method 19A (Appendix A) or other 

approved alternative procedures. These 

procedures include as-fired fuel 

sampling and analysis, stack sampling, 

or operation of a single CEMS af the 

outlet of the SOa control device. 

Methods for as-fired fuel sampling 

and analysis differ slightly for coal- and 

oil-fired steam generating units. For 

coal-fired steam generating units, a 

representative sample is collected af the 

time the coal bunker is filled and 

analyzed for sulfur content and heating 

value. These values are used fo 

calculate the SOa emission rate until the 

bunker is refilled, at which time a new 

sample is collected and analyzed. For 

oil-fired steam generating units, one 

sample is collected during each steam 

generating unit operating day af the 

pipeline inlet fo the steam generating 

unit and analyzed for heating value and 

sulfur content. 

Compliance with the SOa percent 

reduction requirements and emission 

limits would be determined as a 30-day 

rolling average based on CEMS or fuel 

sampling data collected during the 

previous 30 consecutive steam 

generating unit operating days. The first 

30-day average percent reduction and 

emission values calculated after initial 

unit startup would serve as the initial 

performance test required under § 60.8. 

Thereafter, the data would be used to 

determine 30-day rolling average 

percent reduction and SOa emission 

rates calculated as the arithmetic 

average of all hourly SOa emission 

values collected during the preceding 30 

steam generating unit operating days. A 

new 30-day rolling-average percent 

reduction and SOa emission rate are 

calculated at the end of each steam 

generating unit operating day. As 

discussed in "Summary of Regulatory 

Analysis" under "Performance of 

Demonstrated Emission Control 

Technologies," a 30-day rolling average 

has been determined to best represent 

the long-term average emission levels 

and the performance of emission control 

devices. 

When establishing standards that 

require the use of CEMS for determining 

compliance, it is necessary to consider 

that monitors undergo periods of 

downtime and, thus, are not always 

available 100 percent of the time. 

Therefore, minimum data requirements 

should be established that provide for 

downtime, but limit the amount of data 

permitted to be lost before use of an 

alternative monitoring method is 

required. These minimum data 

requirements would provide the owner 

or operator with time to maintain and 

calibrate the CEMS, correct minor 

malfunctions, and, if necessary, arrange 

for an alternative monitoring method, 

while at the same time providing 

sufficient data for compliance 

determinations. They also would 

prevent the possibility of an affected 

facility operating for unreasonably long 

periods without collecting emission 

data. 

Under the proposed standards, each 

30-day rolling average would be 

calculated using, as a minimum, data 

collected during 22 out of 30 consecutive 

steam generating unit operating days. 

Collection of this amount of data has 

been determined to be readily 

achievable using either fuel sampling 

and analysis or a well operated and 

properly maintained CEMS. If the 

specified amount of data cannot be 

captured due to unusual circumstances, 

alternative monitoring methods may be 

used fo provide sufficient data for 

calculating the 30-day rolling averages. 

If a steam generating unit periodically 

burns natural gas or other nonsulfurbearing fuels, 24-hour periods during 
P.33 

22414 Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 

which these fuels are the only fuels fired 

in the steam generating unit would not 

be considered steam generating unit 

operating days for purposes of 

determining compliance with the SOa 

standards. Rather, only those 24-hour 

periods (as defined in the proposed 

regulation) during which any fuel 

subject to the SOa emission limits under 

§ 60.42b is fired in the steam generating 

unit would constitute steam generating 

unit operating days. Twenty-four-hour 

periods during which both sulfur-bearing 

and nonsulfur-bearing fuels are fired 

will be considered steam generating unit 

operating days, but emissions data 

collection would not be required during 

those portions of the steam generating 

unit operating day when nonsulfurbearing fuels are fired. Emissions of SOa 

from the combustion of natural gas and 

other nonsulfur-bearing fuels are so low 

that including these emissions in the 30-

day rolling average calculations would 

serve only to "dilute" the reported 

emission values. 

In order to ensure that CEMS provide 

accurate data, daily calibration drift 

checks and quarterly accuracy audits 

would be required to be performed on 

each CEMS. These quality assurance 

checks would be performed in 

accordance with 40 CFR Part 60, 

Appendix F, Procedure 1, "Quality 

Assurance Requirements for Gaseous 

Continuous Emission Monitoring 

Systems Used for Compliance 

Determination." Appendix F, Procedure 

1 applies to all CEMS used for 

continuous compliance determination 

under 40 CFR Part 60, Subparts D, Da, 

and Db. 

2. Particulate Matter 

The performance test methods and 

monitoring requirements for oil-fired 

industrial-commercial-institutional 

steam generating units are identical to 

those proposed on June 19,1984 for coal-, 

wood-, and municipal-type solid wastefired steam generating units (49 FR 

25102), as amended by the addition of 

Reference Method 5B as a particulate 

matter test method (50 FR 21863, May 19, 

1985). 

G. Reporting and Recordkeeping 

Requirements 

The proposed standards would 

require owners and operators of all 

affected facilities to submit notifications 

of steam generating unit construction or 

reconstruction, date of anticipated 

startup, date of actual startup, and 

anticipated date of demonstration of the 

CEMS (if applicable), as required under 

the General Provisions (40 CFR 60.7). In 

addition, this notification would include 

a description of the fuel(s) to be fired in 

the steam generating unit. If a steam 

generating unit will fire a very low 

sulfur oil and claims full fuel 

pretreatment credit toward satisfying 

the applicable percent reduction 

requirement, this would also be stated in 

the initial notification. Mixed fuel-fired 

steam generating units not subject to the 

percent reduction requirements would 

submit a statement verifying that they 

are subject to a Federally enforceable 

State or local permit limiting the fossil 

fuel utilization factor for coal to 30 

percent (0.3) or less on an annual basis, 

a statement that the annual capacity 

utilization factor for fuels other than 

coal, oil, or natural gas is 10 percent 

(0.10) or greater, and a description of the 

types and amounts of all fuels to be 

fired in the steam generating unit. The 

annual capacity utilization factors 

would be determined on a 12-month 

rolling average basis, with a new 

average capacity utilization factor 

calculated at the end of each calendar 

month. Finally, if an emerging SOa 

control technology will be used for SOa 

control, a description of the technology 

to be used would also be included in the 

initial notification. 

After the initial performance test has 

been completed, the proposed regulation 

would require that quarterly reports be 

submitted. These reports would include 

all 30-day rolling average emission rates 

and percent reduction values calculated 

during the reporting period, as well as 

identification of any periods for which * 

data were excluded from these 

calculations. If credit toward the 

applicable percent reduction 

requirement is claimed based on fuel 

pretreatment, a statement would be 

submitted with the quarterly report 

certifying that the credit was determined 

in accordance with Method 19 and 

documenting each pretreated fuel 

shipment as discussed under "Other 

Considerations." In addition, each 

quarterly report would include the 

results of the daily CEMS drift tests and 

quarterly accuracy determinations as 

required under Appendix F, Procedure 1. 

If the applicable SOa emission limit or 

percent reduction requirement is 

exceeded by any 30-day average during 

the reporting period, the quarterly report 

would also describe the reason for the 

exceedance or failure to meet the 

percent reduction requirement and the 

corrective action taken. If the minimum 

amount of data (as discussed in 

"Performance Test Methods and 

Monitoring Requirements") was not 

obtained for any 30-day rolling average 

period, reasons for failure to obtain 

sufficient data and a description of 

corrective action taken would also be 

included, along with all information 

needed to calculate the 30-day average 

values according to Method 19, Section 

7. 

The proposed regulation would also 

require that certain types of records be 

maintained. Records to be maintained 

include all data outputs of the CEMS or 

results of fuel sampling and analysis; all 

quarterly reports submitted under this 

rulemaking; and all records required 

under Appendix F, Procedure 1. All 

required records would be maintained 

for 2 years following the date of such 

records, after which they could be 

discarded. 

The reporting and recordkeeping 

requirements in the proposed regulation 

are necessary to inform enforcement 

personnel as new steam generating units 

initiate operation. In addition, they 

would provide the data and information 

necessary to ensure continued 

compliance of these steam generating 

units with the proposed regulation. At 

the same time, these requirements 

would not impose an unreasonable 

burden on steam generating unit owners 

or operators. 

VI. Administration Requirements 

A. Public Hearing 

A public hearing will be held, if 

requested, to discuss the proposed 

standards in accordance with section 

307(d)(5) of the Clean Air Act. Persons 

wishing to make oral presentations 

should contact EPA at the address given 

in the ADDRESSES section of this 

preamble. Oral presentations should be 

limited to 15 minutes each. Any member 

of the public may file a written 

statement before, during, or within 30 

days after the hearing. Written 

statements should be mailed to the 

Central Docket Section at the address 

given in the ADDRESSES section of this 

preamble. 

A verbatim transcript of the hearing 

and written statements will be available 

for public inspection and copying during 

normal working hours at EPA's Central 

Docket Section in Washington, D.C. (see 

ADDRESSES section of this preamble). 

B. Docket 

The docket is an organized and 

complete file of all the information 

submitted to or otherwise considered in 

the development of this proposed 

rulemaking. The principal purposes of 

the docket are: (1) to allow interested 

parties to identify and locate documents 

so that they can effectively participate 

in the rulemaking process, and (2) to 

serve as the record in case of judicial 
P.34 

Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 22415 

review (except for interagency review 

materials [Section 307(d)(7)(A)]). 

C. Clean Air Act Procedural 

Requirements 

1. Administrator Listing—Section 111 

As prescribed by Section 111 of the 

Clean Air Act, as amended, 

establishment of standards of 

performance for industrial-commercialinstitutional steam generating units is 

based on the Administrator's 

determination (40 CFR 60.16, 44 FR 

49222, dated August 21,1979 and 49 FR 

25156, dated June 19,1984) that these 

sources contribute significantly to air 

pollution which may reasonably be 

anticipated to endanger public health or 

welfare. 

2. Periodic Review—Section 111 

The regulation will be reviewed 4 

years from the date of promulgation as 

required by the Clean Air Act. This 

review will include an assessment of 

such factors as the need for integration 

with other programs, the existence of 

alternative methods, enforceability, 

improvements in emission control 

technology, and reporting requirements. 

3. External Participation—Section 117 2. Executive Order 12291 Review 

D. Office of Management and Budget 

Reviews 

1. Paperwork Reduction Act 

The information collection 

requirements in this proposed rule have 

been submitted for approval to the 

Office of Management and Budget 

(OMB) under the Paperwork Reduction 

Act of 1980, 44 USC 3501 et seq. 

Comments on these requirements should 

be submitted to the Office of 

Information and Regulatory Affairs, 

OMB, 726 Jackson Place, NW., 

Washington, DC 20503 marked 

"Attention: Desk Officer for EPA." 

Copies of these comments should also 

be submitted to Central Docket Section 

(LE-131), Attention: Docket Number A83-27, U.S. Environmental Protection 

Agency, 401 M Street SW.; Washington, 

DC 20460. The final rule will respond to 

any OMB or public comments on the 

information collection requirements. 

The average annual industry-wide 

burden of the reporting and 

recordkeeping requirements associated 

with the proposed regulation would be 

75 person-years, based on an average of 

180 respondents per year. 

In accordance with section 117 of the 

Clean Air Act, publication of this 

proposal was preceded by consultation 

with appropriate advisory committees, 

independent experts, and Federal 

departments and agencies. The 

Administrator will welcome comments 

on all aspects of the proposed 

regulation, including economic and 

technological issues. 

In addition, comments are specifically 

solicited on several aspects of the 

proposed rulemaking. These issues were 

discussed previously in the 

SOLICITATION OF PUBLIC 

COMMENT section of this preamble. 

4. Economic Impact Assessment— 

Section 317 

Section 317 of the Clean Air Act 

requires the Administrator to prepare an 

economic impact assessment for any 

NSPS promulgated under section 111(b) 

of the Act. An economic impact 

assessment was prepared for the 

proposed standards and for other 

regulatory alternatives. All aspects of 

the assessment were considered in the 

formulation of the proposed standards 

to ensure that the proposed standards 

would represent the best system of 

emission reduction considering costs. 

Portions of the economic impact 

assessment are included in the 

background information documents and 

additional information is include^ in the 

Docket. 

Under Executive Order 12291, the 

Agency must judge whether a regulation 

is "major" and therefore subject to the 

requirement of a Regulatory Impact 

Analysis (RIA). This proposed 

regulation could result in industry-wide 

annualized costs in the fifth year after 

the standards would go into effect of 

more than the $100 million cutoff 

established as the first criterion for a 

major regulation in the Order. In 

accordance with the Order, an RIA has 

been prepared for the proposed 

regulation. The RIA considers the 0 

benefits, costs, and economic impacts 

associated with the regulatory 

alternatives that were considered in 

developing the proposed standards. 

The analysis of benefits derived from 

reductions in SOa emissions included 

the following benefit categories: 

Improvements in visibility due to lower 

ambient sulfate (SO4) concentrations; 

reduced morbidity, reduced residential 

materials damages, and reduced 

agricultural damage due to lower 

ambient SOa concentrations; and 

reduced morbidity and reduced 

household soiling due to lower ambient 

PM concentrations. However, coverage 

of these benefit categories is in some 

cases incomplete. For example, 

estimates of visibility improvements due 

to SO4 reductions include visibility 

improvements in only the 31 eastern 

States (east of the Mississippi River). 

Likewise, benefits from reductions in 

PM are estimated only for the 31 eastern 

States. In addition, the S02 benefit 

estimates include reductions in 

residential materials damage, but no 

estimates are included for reductions in 

materials damage for commercial, 

industrial, or institutional facilities. 

It is also important to note that a 

number of benefit categories were not 

included in the analysis. For example, 

potentially significant benefits from 

reductions in acid deposition are 

omitted, and reduced health effects due 

to lower SO4 concentrations are not 

included. On the other hand, these 

estimates may also overstate, in some 

respects, the benefit categories. 

Results of the analysis indicate that 

the recommended standards would 

result in annualized benefits of the same 

magnitude as the annualized costs. A 

copy of the RIA has been placed in 

Docket A-83-27 and is available for 

public review. The Agency solicits 

comments on the RIA and its potential 

role in this rulemaking. 

This regulation was submitted to the 

OMB for review as required by 

Executive Order 12291. Any written 

comments from OMB and any responses 

to those comments will be included in 

Docket A-83-27. This docket is 

available for public inspection at EPA's 

Central Docket Section, which is listed 

under the ADDRESSES section of this 

notice. 

E. Regulatory Flexibility Act 

Compliance 

The Regulatory Flexibility Act 

requires consideration of the impacts of 

proposed regulations on small entities 

including small businesses, 

organizations, and jurisdictions. A small 

business is defined as any business 

concern which is independently owned 

and operated and not dominant in its 

field as defined by the Small Business 

Administration regulations under 

Section 3 of the Small Business Act. 

Similarly, a small organization is 

defined by the Small Business 

Administration as a not-for-profit 

enterprise, independently owned and 

operated, and not dominant in its field. 

A small jurisdiction is defined as any 

government district with a population of 

less than 50,000 people. 

Pursuant to the provisions of 5 U.S.C. 

605(b), I hereby certify that this rule, if 

promulgated, will not have a significant 

economic impact on a substantial 

number of small business entities 

because the number of small entities 

that would be affected, if any, is not 

substantial. 
P.35 

22416 Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 

List of Subjects in 40 CFR Part 60 

Air pollution control, Incorporation by 

reference, Intergovernmental relations, 

Reporting and recordkeeping, Fossil 

fuel-fired steam generating units. 

Dated: May 3,1986. 

Lee M. Thomas, 

Administrator. 

PART 60—STANDARDS OF 

PERFORMANCE FOR NEW 

STATIONARY SOURCES 

For reasons set out in the preamble, 40 

CFR Part 60 Subpart Db as proposed on 

June 19,1984 (49 FR 25102) is proposed 

to be amended as follows: 

1. The authority citation for Part 60 

continues to read as follows: 

Authority: 42 U.S.C. 7411, 7414, and 7601(a). 

2. Section 60.40b as proposed on June 

19,1984 (49 FR 25102) is amended by 

revising paragraphs (a), (b), and (c) to 

read as follows: 

§ 60.40b Applicability and definition of 

affected facility. 

(a) The affected facility to which this 

subpart applies is each industrialcommercial-institutional steam 

generating unit for which construction, 

modification, or reconstruction is 

commenced after June 19,1984 and 

which has a heat input capacity from 

fuels combusted in the steam generating 

unit of more than 29 MW (100 million 

Btu/hour). 

(b) Except as provided in paragraphs 

(d) and (e) of this section, any affected 

facility meeting the applicability 

requirements under paragraph (a) of this 

section and for which construction, 

modification, or reconstruction is 

commenced after June 19,1986 is subject 

to the standards for particulate matter 

(PM), nitrogen oxides (NOJ, and sulfur 

dioxide (SOa) under this subpart. 

(c) Except as provided in paragraphs 

(d) and (e) of this section, any affected 

facility meeting the applicability 

requirements under paragraph (a) of this 

section and for which construction, 

modification, or reconstruction is 

commenced before June 19,1986 is 

subject to the following standards: 

(1) Coal-fired industrial-commercialinstitutional steam generating units are 

subject to the PM and NOx standards 

under this subpart. Coal-fired industrialcommercial-institutional steam 

generating units meeting the 

applicability requirements under 

Subpart D (Standards of performance 

forfossil fuel-fired steam generators; 

§ 60.40) are also subject to the SOa 

standards under Subpart D (§ 60.43). 

(2) Oil-fired industrial-commercialinstitutional steam generating units are 

subject to the NOx standards under this 

subpart. Oil-fired industrial-commercialinstitutional steam generating units 

meeting the applicability requirements 

under Subpart D (Standards of 

performance for fossil fuel-fired steam 

generators; § 60.40) are also subject to 

the PM and SOa standards under 

Subpart D (§ 60.42 and § 60.43). 

**** * 

3i Section 60.41b as proposed on June 

19,1984 (49 FR 25102) is amended by 

revising the definition of "steam 

generating unit operating day" and 

adding in alphabetical order definitions 

as follows: 

§ 60.41b Definitions. 

**** * 

"Cogeneration steam generating unit" 

means a steam generating unit that 

simultaneously produces both electrical 

(or mechanical) and thermal energy 

from the same primary energy source. 

**** * 

"Conventional technology" means 

SOa control technologies that include 

wet flue gas desulfurization technology, 

fluidized bed combustion technology, or 

lime spray drying technology. 

**** * 

"Emerging technologies" means any 

flue gas desulfurization system or 

combustion modification technology 

which is not a conventional technology, 

as determined by the Administrator 

pursuant to § 60.49b(a)(4). 

"Flue gas desulfurization" means a 

system which uses an alkaline reagent 

to remove SOa from flue gases. 

**** * 

"Fluidized bed combustion 

technology" means a device wherein 

fuel and solid sorbent are distributed 

onto a bed, or series of beds, of 

aggregate for combustion and these 

materials together with solid products of 

combustion are forced upward in the 

device by the flow of combustion air. 

and the gaseous products of combustion. 

"Fossil fuel utilization factor" means 

the percentage of the rated steam 

generating unit heat input capacity that 

is supplied by fossil fuel. 

"Fuel pretreatment" means the 

process by which a portion of the 

pollutant concentration of a fuel is 

removed prior to its combustion in a 

steam generating unit. 

**** * 

"Lime spray drying" means a dry flue 

gas desulfurization system in which the 

flue gases from a steam generating unit 

are sprayed with a finely atomized lime 

slurry in a spray dryer. 

**** * 

"Potential SOa emission rate" means 

the theoretical emissions (ng/J, lb/ 

million Btu heat input) that would result 

from the combustion of a fuel in an 

uncleaned state without emission 

control systems. 

**** * 

"Steam generating unit operating day" 

means a 24-hour period between 12:00 

midnight and the following midnight 

during which any fuel is combusted at 

any time in the steam generating unit. It 

is not necessary for fuel to be 

combusted continuously for the entire 

24-hour period. 

"Wet flue gas desulfurization 

technology" means a flue gas 

desulfurization system which removes 

sulfur oxides from a gas by contacting 

the gas with an aqueous, liquid reagent. 

The products of this contact are a gas 

with decreased amounts of sulfur oxides 

and an aqueous, liquid material with 

increased amounts of sulfur compounds. 

This definition shall apply to a device 

even if the aqueous, liquid material 

product of this contact is subsequently 

converted into a solid material by 

further processing by equipment integral 

to, or separate from, the device. Wet flue 

gas desulfurization technology includes 

lime, limestone, dual alkali, and sodium 

wet scrubbing. 

**** * 

4. Section 60.42b is redesignated as 

§ 60.43b and paragraph (a)(4) is added 

as follows: 

§ 60.43b Standard for particulate matter. 

(a) * * * 

Steam generating unit/fuel type 

Particulate matter 

emission limit 

nanograms per 

joule neat input 

(lb/mlllion Btu 

heat input) 

(4) Oil.. 43 (0.10) 

5. A new § 60.42b is added as follows: 

§ 60.42b Standard for sulfur dioxide. 

(a) Except as provided in paragraphs 

(b), (c), or (d) of this section, on and 

after the date on which § 60.8 requires a 

performance test to be completed, no 

owner or operator of an affected facility 

that combusts coal or oil, either alone or 

in combination with any other fuel, shall 

cause to be discharged into the 

atmosphere any gases which contain 

SOa in excess of 10 percent of the 

potential SOa emission rate (90 percent 

reduction) and which contain SOa in 

excess of the emission limit determined 

according to the following formula: 

Esoa=(516H„+344H1))/Ht [£^=(1.211.+ 

0.8H„}/H,] 

where: 
P.36 

Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 22417 

*-so2 is the S02 emission limit, expressed in 

nanograms per joule (ng/J) or lb/million 

Btu heat input, 

H„ is the heat input from the combustion of 

coal, in joules (million Btu), 

Hb is the heat input from the combustion of 

oil, in joules (million Btu), and 

Ht is the total heat input from the combustion 

of coal and oil, in joules (million Btu). (Ht 

includes only the heat input supplied to 

the steam generating unit from the 

combustion of coal and oil and not the 

heat input from the combustion of 

natural gas, wood, solid waste, or other 

fuels.) 

(b) On and after the date on which 

§ 60.8 requires a performance test to be 

completed, no owner or operator of an 

affected facility that combusts coal or 

oil, either alone or in combination with 

any other fuel, and that uses an 

emerging technology for the control of 

SOa emissions, shall cause to be 

discharged into the atmosphere any 

gases which contain SOa in excess of 50 

percent of the potential SOa emission 

rate (50 percent reduction) and which 

contain SOa in excess of the emission 

limit determined according to the 

following formula: 

ES02 = {256Hc+172d)/Ht [ESO2 = (0.6Hc+ 

0.4d)/HU 

where: 

ESO is the SO: emission limit, expressed in 

n

g/J (lb/million Btu) heat input, 

Hc is the heat input from the combustion of 

coal, in joules (million Btu), 

Hi is the heat input from the combustion of 

oil, in joules (million Btu), and 

H, is the total heat input from the 

combustion of coal and oil in joules 

(million Btu). (H, includes only the heat 

input supplied to the steam generating 

unit from the combustion of coal and 

oil and not the heat input from the 

combustion of natural gas, wood, solid 

waste, or other fuels.) 

(c)(1) The requirement(s) to reduce 

emissions to a certain percentage of the 

potential SOa emission rate included in 

paragraphs (a) and (b) of this section do 

not apply to an affected facility that 

combusts coal in combination with any 

other fuel, except oil or natural gas, 

provided the affected facility: 

(i) Has an annual fossil fuel utilization 

factor for coal of 30 percent (0.30) or 

less; 

(ii) Has an annual capacity utilization 

factor of 10 percent (0.10) or more for 

fuel(s) other than coal, oil, or natural 

gas; and 

(iii) Is subject to a Federal, State, or 

local permit limiting operation of the 

affected facility to conditions (i) and (ii) 

above. 

(2) The SOa emission limit(s) 

determined according to the applicable 

formula in paragraph (a) of this section 

continue to apply to facilities meeting 

the criteria in paragraph (c)(1) of this 

section. 

(d) Compliance with the emission 

limit(s) and percent reduction 

requirements under this section are both 

determined on a 30-day rolling average 

basis. 

6. Section 60.43b is redesignated as 

§ 60.44b. 

7. Section 60.45b is redesignated as 

§ 60.48b, and a new § 60.45b is added as 

follows: 

§ 60.45b Compliance and performance 

testing for sulfur dioxide. 

(a) The SOa emission standards under 

§ 60.42b apply at all times including 

periods of startup, shutdown, and 

malfunction. 

(b) Compliance with the SOa emission 

standards under § 60.42b shall be 

determined through performance testing 

as described in paragraph (c) of this 

section. 

(c) The following procedures are used 

in performance testing to determine the 

SOa emission rate and the percent of 

potential SOa emission rate discharged 

to the atmosphere. 

(1) The SOa emission rate discharged 

to the atmosphere shall be determined 

using the following formula: 

Eso^E^./x^ 

where: 

Eso2 is the S02 emission rate in ng/J (lb/ 

million Btu) heat input. 

Eso2o is the arithmetic average of all hourly 

outlet emission rates for 30 successive 

steam generating unit operating days, as 

determined by Method 19 or Method 

19A, in ng/J (lb/million Btu] heat input. 

Xk is the fraction of total heat input for 30 

successive steam generating unit 

operating days derived from coal, oil, or 

coal and oil as determined by Method 19 

or Method 19A. (Xh=1.0 if only coal, only 

oil, or mixtures of only coal and oil 

together are combusted.) 

(2) The percent of potential SOa 

emission rate (% PER) discharged to the 

atmosphere shall be determined as 

follows: 

(i) The percent reduction achieved by 

any fuel pretreatment shall be 

- determined using the procedures in 

Method 19, Section 2 (Appendix A). 

(ii) The percent reduction achieved by 

any SOa control system shall be 

determined by comparing the arithmetic 

average of all hourly emission rates 

measured at the inlet to the control 

system to the arithmetic average of all 

hourly emission rates measured at the 

outlet to the control system for 30 

successive steam generating unit 

operating days, following the procedures 

in Method 19, Section 3. An "as fired" 

fuel sampling system may be used to 

determine the SOa input rate at the inlet 

to the SOa control device as described in 

Method 19, Section 3. When an "as 

fired" fuel sampling system is used, the 

percent reduction is calculated using the 

arithmetic average of all hourly 

emission rates from the SOa control 

device and the arithmetic average of all 

24-hour or daily SOa input rates from the 

"as fired" fuel analysis for 30 successive 

steam generating unit operating days. 

(iii) The overall percent reduction 

shall be determined using the result 

obtained in paragraphs (e)(1) (i) and (ii) 

of this section following the procedures 

in Method 19, Section 4 (Appendix A). 

(iv) The percent of potential SOa 

emission rate emitted to the atmosphere 

shall be determined using the following 

formula: 

% PER = 100 - % Ro 

where % Ro is the overall percent reduction 

as determined in subparagraph (iii) of 

this section. 

(d) For the initial performance test 

required under § 60.8, compliance with 

the SOa emission limits and percent 

reduction requirements under § 60.42b is 

based on the average emission rates and 

the average percent reduction for SOa 

for the first 30 consecutive steam 

generating unit operating days. The 

initial performance test is the only test 

for which at least 30 days prior notice is 

required unless otherwise specified by 

the Administrator. The initial 

performance test is to be scheduled so 

that the first steam generating unit 

operating day of the 30 successive steam 

generating unit operating days is 

completed within 30 days after 

achieving the maximum production rate 

at which the affected facility will be 

operated, but not later than 150 days 

after initial startup of the facility. 

(e) After the initial performance test 

required under § 60.8, compliance with 

the SOa emission limits and percent 

reduction requirements under § 60.42b is 

based on the average emission rates and 

the average percent reduction for SOa 

for 30 successive steam generating unit 

operating days. A separate performance 

test is completed at the end of each 

steam generating unit operating day 

after the initial performance test, and a 

new 30-day average emission rate and 

percent reduction for SOa are calculated 

to show compliance with the standard. 

(f) Emissions of 86 ng/J (0.2 lb/million 

Btu) heat input or less from steam 

generating units combusting oil 

constitute compliance with the 

requirement to reduce emissions to a 

certain percentage of the potential SOa 

emission rate under § 60.42b. 

(g) If the owner or operator of an 

affected facility has not obtained the 

minimum quantity of emission data as 

required under § 60.46b, compliance 
P.37 

22418 Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 

with the emission limits and the percent 

reduction requirements under § 60.42b 

for the day on which the 30-day period 

ends may be determined by the 

Administrator by following the 

applicable procedures in Method 19, 

Section 7 Appendix A). 

8. Section 60.44b as proposed on June 

19,1984 (49 FR 25102) is redesignated as 

§ 60.46b. 

9. A new § 60.47b is added as follows: 

§ 60.471) Emission monitoring for sulfur 

dioxide. 

(a) Except as provided in paragraph 

(b) of this section, the owner or operator 

of an affected facility subject to the SOa 

standards under § 60.42b shall install, 

calibrate, maintain, and operate 

continuous emission monitoring systems 

(CEMS) for measuring SOa 

concentrations and either oxygen or 

carbon dioxide concentrations and shall 

record the output of the systems. Sulfur 

dioxide and either oxygen or carbon 

dioxide concentrations shall both be 

monitored at the inlet and outlet of the 

SOa control device. 

(b) As an alternative to operating 

CEMS as required under paragraph (a) 

of this section, an owner or operator 

may elect to determine the average SOj 

emissions and percent reduction by: 

(1) Collecting fuel samples in an asfired condition at the inlet to the steam 

generating unit analyzing for sulfur and 

heat content according to Method 19A 

(Appendix A). Section 2 of Method 19A 

provides procedures for converting these 

measurements into the format to be used 

in calculating the average SC*a input 

rate. 

(2) Measuring SOa according to 

Reference Method 6B at the inlet or 

outlet to the SOa control system. 

(c) The CEMS required under 

paragraph (a) of this section shall be 

operated and data recorded during all 

periods of operation of the affected 

facility, including periods of startup, 

shutdown, or malfunction, except for 

CEMS breakdowns, repairs, calibration 

checks, and zero and span adjustments. 

(d) The 1-hour average SOa emission 

rates measured by the CEMS required 

by paragraph (a) of this section and 

required under § 60.13(h) shall be 

expressed in ng/J or lb/million Btu heat 

input and shall be used to calculate the 

average emission rates under § 60.42b. 

At least 2 data points must be used to 

calculate each 1-hour average. 

(e) The procedures under § 60.13 shall 

be followed for installation, evaluation, 

and operation of the CEMS. 

(1) All CEMS shall be operated in 

accordance with the applicable 

procedures under Performance 

Specifications 1, 2, and 3 (Appendix B). 

(2) Quarterly accuracy determinations 

and daily calibration drift tests shall be 

performed in accordance with Procedure, 

1 (Appendix F). 

(3) For affected facilities burning coal 

or oil, alone or in combination with 

other fuels, the span value of the SOa 

CEMS at the inlet to the SOa control 

device is 125 percent of the maximum 

estimated hourly potential SOa 

emissions of the fuel fired, and the span 

value of the CEMS at the outlet to the 

SC^ control device is 50 percent of the 

maximum estimated hourly potential 

SCfe emissions of the fuel fired. 

(f) When SOa emission data are not 

obtained because of CEMS breakdowns, 

repairs, calibration checks and zero and 

span adjustments, emission data will be 

obtained by using other monitoring 

systems as approved by the 

Administrator or the reference methods 

as described in paragraph (h) of this 

section to provide emission data for a 

minimum of 75 percent of the operating 

hours in at least 22 out of 30 successive 

steam generating unit operating days. 

(g) If a steam generating unit 

periodically combusts natural gas, 

wood, or solid waste, or any other 

nonsulfur-bearing fuels, 24-hour periods 

during which these nonsulfur-bearing 

fuels are the only fuels combusted in the 

steam generating unit during the entire 

24-hour period from midnight to the 

following midnight shall not be 

considered steam generating unit 

operating days for purposes of 

determining compliance with the SOa 

standard under § 60.42b. For periods 

during which both sulfur-bearing and 

nonsulfur-bearing fuels are combusted 

in the steam generating unit, only those 

hours during which any sulfur-bearing 

fuel is combusted shall be considered 

steam generating unit operating hours. 

(h) Reference methods used to 

supplement CEMS data to meet the 

minimum data requirements in 

paragraph (f) of this section will be used 

as specified below or otherwise 

approved by the Administrator. 

(1) Reference Methods 3 and 6 or 6B, 

as applicable, are used. The sampling 

location(s) for Reference Methods 3 and 

6 are the same as those used for the 

CEMS. 

(2) For Method 6, the minimum 

sampling time is 20 minutes and the 

minimum sampling volume is 0.02 dsm3 

(0.71 dsf

 3) for each sample. Samples are 

taken at approximately 60 minute 

intervals. Each sample represents a 1-

hour average. 

(3) For Method 3, the oxygen or 

carbon dioxide sample is to be taken for 

each hour when continuous SOa data 

are collected or when Method 6 is used. 

Each sample shall be taken for a 

minimum of 30 minutes in each hour 

using the integrated bag method 

specified in Method 3. Each sample 

represents a 1-hour average. 

(4) For each 1-hour average, the 

emissions expressed in ng/J (lb/million 

Btu) heat input are determined and used 

as needed to achieve the minimum data 

requirements of paragraph (f) of this 

section. 

10. Section 60.46b as proposed on June 

19,1984 (49 FR 25102) is redesignated as 

§ 60.49b and amended by revising 

paragraphs (b) and (i); and adding 

paragraphs (a)(3), (a)(4), (j), (k), (1), and 

(m) as follows: 

§ 60.49b Reporting and recordkeeping 

requirements. 

(a) * * * 

(3) the design heat input capacity and 

the annual capacity factor at which the 

owner or operator anticipates operating 

the facility, and, if applicable, a copy of 

any Federal or Federally enforceable 

State or local permit which limits the 

annual fossil fuel utilization factor for 

coal to 30 percent (0.30) or less and 

limits the annual capacity factor for 

fuels other than coal, oil, or natural gas 

to 10 percent (0.10) or greater for 

affected facilities regulated under 

§ 60.42b(c). The annual fossil fuel 

utilization factor and the annual 

capacity utilization factor shall be 

determined on a 12-month rolling 

average basis, with a new average 

calculated at the end of each calendar 

month. 

(4) identification and description of 

any emerging technologies used for 

controlling emissions of SOa under 

§ 60.42b. Upon receiving notification 

from the owner or operator of an 

affected facility that an emerging 

technology will be used for controlling 

emissions of SOa, the Administrator will 

examine the description of the emerging 

technology proposed to be used and will 

determine whether this technology 

qualifies as an emerging technology. In 

making this determination, the 

Administrator may require the owner or 

operator of the affected facility to 

submit additional information 

concerning the control device. The 

determination of the Administrator shall 

be communicated to the owner or 

operator of the affected facility within 

30 working days of receipt of 

notification from the owner or operator. 

(b) For facilities subject to the SOa, 

PM, and NO, emission limits under 

§ 60.42b, § 60.43b, and § 60.44b, the 

performance test data from the initial 

performance test and the performance 

evaluation of the CEMS using the 

applicable performance specifications in 
P.38 

Federal Register / Vol. 51, No. 118 / Thursday, June 19, 1986 / Proposed Rules 22419 

Appendix B shall be submitted to the 

Administrator by the owner or operator 

of the affected facility. 

* * * * * • 

(i) The owner or operator of any 

affected facility subject to the S02 

standards under § 60.42b shall submit 

written reports to the Administrator for 

every calendar quarter. All quarterly 

reports shall be postmarked by the 30th 

day following the end of each calendar 

quarter. 

(j) For each affected facility subject to 

the reporting requirement in paragraph 

(i) of this section, the following 

information shall be reported to the 

Administrator: 

(1) Calendar dates covered in the 

reporting period. 

(2) Each 30-day average S02 emission 

rate measured during the reporting 

period, ending with the last 30-day 

period in the quarter; reasons for 

noncompliance with the emission 

standards; and a description of 

corrective actions taken. 

(3) Each 30-day average percent 

reduction in SOa emissions calculated 

during the reporting period, ending with 

the last 30-day period in the quarter; 

reasons for noncompliance with the 

emission standards; and a description of 

corrective actions taken. 

(4) Identification of the steam 

generating unit operating days for which 

S02 or diluent (oxygen or carbon 

dioxide) data have not been obtained by 

an approved method for at least 75 

percent of the operating hours; 

justification for not obtaining sufficient 

data; and description of corrective 

action taken. 

(5) Identification of the times when 

emissions data have been excluded from 

the calculation of average emission 

rates; justification for excluding data; 

and description of corrective action 

taken if data have been excluded for 

periods other than those during which 

nonsulfur-bearing fuels were combusted 

in the steam generating unit. 

(6) Identification of "F" factor used for 

calculations, method of determination, 

and type of fuel combusted. 

(7) Identification of times when hourly 

averages have been obtained based on 

manual sampling methods. 

(8) Identification of the times when 

the pollutant concentration exceeded 

full span of the CEMS. 

(9) Description of any modifications to 

the CEMS which could affect the ability 

of the CEMS to comply with 

Performance Specifications 2 or 3. 

(10) Results of daily CEMS drift tests 

and quarterly accuracy assessments as 

required under Appendix F, Procedure 1. 

(k) For each affected facility subject to 

the SOa standards under § 60.42b for 

which the minimum amount of data 

required under § 60.47b(f) were not 

obtained during a calendar quarter, the 

following information is reported to the 

Administrator in addition to that 

required under paragraph (j) of this 

section: 

(l).The number of hourly averages 

available for outlet emission rates and 

inlet emission rates. 

(2) The standard deviation of hourly 

averages for outlet emission rates and 

inlet emission rates, as determined in 

Method 19, Section 6. 

(3) The lower confidence limit for the 

mean outlet emission rate and the upper 

confidence limit for the mean inlet 

emission rate, as calculated in Method 

19, Section 6. 

(4) The applicable potential SOa 

emission rate(s). a 

(5) The ratio of the lower confidence 

limit for the mean outlet emission rate 

and the allowable emission rate, as 

determined in Method 19, Section 7. 

(1) If fuel pretreatment credit toward 

the S02 emission standard under 

§ 60.42b is claimed, the owner or 

operator of the affected facility shall 

submit a signed statement with the 

quarterly report: 

(1) Indicating what percentage fuel 

pretreatment credit was taken for the 

calendar quarter; 

(2) Listing the quantity, heat content, 

and date each pretreated fuel shipment 

was received during the previous 

calendar quarter; the name and location 

of the fuel pretreatment facility; and the 

total quantity and total heat content of 

all fuels received at the affected facility 

during the previous calendar quarter; 

(3) Certifying that the emission credit 

was determined in accordance with the 

provisions of § 60.45b and Method 19 

(Appendix A); and 

(4) Documenting the transport of the 

fuel from the fuel pretreatment facility to 

the steam generating unit. 

(m) All records required under this 

section shall be maintained by the 

owner or operator of the affected facility 

for a period of 2 years following the date 

of such record. 

[FR Doc.86-13263 Filed 6-18-88; 8:45 am) 

BILLING CODE 6530-50-M