p.1 

OAR Box 1865 

Prepped by Charmelle Mathews 

Document Number: 

198) FR 12-6-1987 

Docket Number: 

A-83-27 

Printed 12/3/2008 3:22:25 PM Sheet 198 of 198 
P.2 

r 

A-63-Z.7 

Wednesday 

December 16, 1987 

Part II 

Environmental 

Protection Agency 

40 CFR Part 60 

Standards of Performance for New 

Stationary Sources; IndustrialCommercial-Institutional Steam 

Generating Units; Final Rule 
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* „ ~ /•> 

47826 Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[AD-FRt-3276-4] 

Standards of Performance for New 

Stationary Sources; IndustrialCommercial-Institutional Steam 

Generating Units 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: Standards of performance 

under Subpart Db of 40 CFR Part 60 

limiting emissions of sulfur dioxide 

(SO2} from coal- and oil-fired industrialcommercial-institutional steam 

generating units and particulate matter 

(PM) from oil-fired industrialcommercial-institutional steam 

generating units were proposed in the 

Federal Register on June 19,1986 (51 FR 

22384). Today's action promulgates 

these standards under Subpart Db and 

also revises emission testing procedures 

under Method 19 of 40 CFR Part 60, 

Appendix A. 

Standards of performance limiting 

emissions of nitrogen oxides (NOx) and 

PM from fossil- and nonfossil-fuel-fired 

industrial-commercial-institutional 

steam generating units were 

promulgated on November 25,1986 (51 

FR 42768). The complete text of 

Subpart Db integrating the requirements 

for SO2, NOx, and PM is included in 

today's notice. This combined text is 

provided as a convenience to the reader 

and is not a repromulgation of the 

previously promulgated standards for 

NO, and PM. An outline of the specific 

additions to Subpart Db resulting from 

today's action is provided in the 

administrative section of the preamble. 

These standards implement section 

111 of the Clean Air Act and are based 

on the Administrator's determination 

that industrial-commercial-institutional 

steam generating units cause, or 

contribute significantly to, air pollution 

which may reasonably be anticipated to 

endanger public health or welfare. The 

intended effect of these standards is to 

require all new, modified, and 

reconstructed industrial-commercialinstitutional steam generating units to 

reduce emissions of SO2 and PM to the 

levels achievable by the best 

demonstrated system of continuous 

emission reduction, considering costs, 

nonair quality health and environmental 

impacts, and energy requirements. 

EFFECTIVE DATE: December 16,1987. 

Under section 307(b)(1) of the Clean 

Air Act, judicial review of the actions 

taken by this notice is available only by 

the filing of a petition for review in the 

U.S. Court of Appeals for the District of 

Columbia Circuit within 60 days of 

today's publication of this rule. Under 

section 307(b)(2) of the Clean Air Act, 

the requirements that are the subject of 

today's notice may not be challenged 

later in civil or criminal proceedings to 

enforce these requirements. 

Incorporation by reference: The 

incorporation by reference of certain 

publications in these standards is 

approved by the Director of the Office of 

the Federal Register as of December 16, 

1987. 

ADDRESSES: Docket. Docket number A83-27, containing information used in 

development of the standards, is 

available for public inspection between 

8:00 a.m. and 3:00 p.m. Monday through 

Friday at the Central Docket Section 

(LE-131), South Conference Center, 

Room 4,401 M Street SW., Washington, 

DC 20460. A reasonable fee may be 

charged for copying. 

FOR FURTHER INFORMATION CONTACT: 

Mr. Fred Porter or Mr. Walter 

Stevenson, Standards Development 

Branch, Emission Standards and 

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

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711, telephone (919) 541-5251 or (919) 

541-5264. 

SUPPLEMENTARY INFORMATION: The 

following outline is provided to aid in 

reading the preamble to the final 

regulation. 

I. Summary of Standards 

A. Applicability 

B. Sulfur Dioxide Standards 

C. Particulate Matter Standards 

II. Summary of Changes to Proposed 

Standards 

A. Sulfur Dioxide Standards 

B. Sulfur Dioxide Compliance Provisions 

C. Particulate Matter Compliance 

Provisions 

D. Reporting Requirements 

III. Summary of Impacts from the 

Promulgated Standards 

IV. Public Participation 

V. Significant Comments and Changes to the 

Proposed Standards 

A. Applicability 

B. Basis of Standard 

C. Standard for Sulfur Dioxide 

D. National Impacts 

E. Cost of the Standard 

F. Performance/Reliability of 

Demonstrated Technologies 

G. Secondary Environmental Impacts 

H. Emission Credits 

I. Emerging Technologies 

VI. Administrative 

A. Outline of Additions to Subpart Db 

B. Revision of Method 19 

C. Relationship of Subpart Db to 

Operational Guidance and Plans to 

Develop Standards for Municipal Waste 

Combustors 

D. Docket 

E. Clean Air Act Procedural Requirements 

F. Office of Management and Budget 

Reviews 

G. Regulatory Flexibility Act Compliance 

Background Information Documents. 

Because of printing and distribution 

costs, only a limited number of the 

background information document (BID) 

for the promulgated standards were 

printed. Distribution of these documents 

to industries is being coordinated by 

industry trade associations. Companies 

wishing to review the BID should 

contact their representative trade 

association. If the trade association does 

not have access to the BID, a copy will 

be provided for the use of their 

membership. 

I. Summary of Standards 

Standards of performance for new 

sources established under section 111 of 

the Clean Air Act reflect: 

* * * application of the best technological 

system of continuous emission reduction 

which (taking into consideration the cost of 

achieving such emissions reduction, any 

nonair quality health and environmental 

impact and energy requirements) the 

Administrator determines has been 

adequately demonstrated (Section 111(a)(1)). 

For convenience, this will be referred to 

as "best demonstrated technology." 

A. Applicability 

The new source performance 

standards (NSPS) being adopted today 

apply to all new, modified, or 

reconstructed steam generating units 

with a heat input capacity greater than 

29 MW (100 million Btu/hour) for which 

construction is commenced after June 

19,1986, except for electric utility steam 

generating units covered by 40 CFR Part 

60, Subpart Da, or steam generating 

units covered under 40 CFR Part 60, 

Subpart J (Standards of performance for 

petroleum refineries). The definition of 

"steam generating unit" includes all 

devices that combust fuel and produce 

steam, hot water, or heat other fluids 

which are used as heat transfer media. 

The owner or operator of any steam 

generating unit that is capable of 

combusting greater than 29 MW (100 

million Btu/hour) of fuel must submit 

certain information as required by the 

General Provisions (40 CFR 60.11), 

including notification of the date of 

initial unit startup, and must maintain 

certain fuel use records. 

Sulfur dioxide control requirements 

are established for steam generating 

units which combust coal, oil, coal/oil 
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Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 47827 

mixtures, or coal or oil with any other 

fuels. 

Particulate matter emission limits are 

established for steam generating units 

combusting oil or mixtures of oil with 

any other fuels. The PM standard being 

adopted today for oil-fired steam 

generating units supplements PM 

emission standards adopted on 

November 25,1986, for steam generating 

units combusting coal, wood, municipal 

solid waste, or fuel mixtures containing 

any of these fuels (51 FR 42768). 

B. Sulfur Dioxide Standards 

(1) Steam generating units combusting 

coal, either alone or in combination with 

other fuels, are required to achieve a 90 

percent reduction in potential SO2 

emissions and meet an emission limit of 

520 ng/J (1.2 lb/million Btu) heat input, 

except as noted below. 

(2) Steam generating units combusting 

oil/either alone or in combination with 

other fuels, are required to achieve a 90 

percent reduction in potential SO2 

emissions and meet an emission limit of 

340 ng/J (0.8 lb/million Btu) heat input, 

except as noted below. 

(3) Steam generating units combusting 

coal, oil, or a mixture of coal and oil, 

with or without other fuels, that have a 

Federally enforceable permit limiting the 

combustion of coal and oil to 30 percent 

or less of the maximum annual steam 

generating unit heat input capacity, are 

exempt from the percentage reduction 

requirement, but must meet certain 

emission limits. Coal-fired steam 

generating units are subject to an 

emission limit of 520 ng/J (1.2 lb/million 

Btu) heat input. Oil-fired steam 

generating units are subject to an 

emission limit of 130 ng/J (0.3 lb/million 

Btu) heat input. 

(4) Steam generating units combusting 

coal and using an emerging SO2 control 

technology must achieve a 50 percent 

reduction in potential SO2 emissions and 

meet an emission limit of 260 ng/J (0.6 

lb/million Btu) heat input. 

(5) Steam generating units combusting 

oil and using an emerging SO2 control 

technology must achieve a 50 percent 

reduction in potential SO2 emissions and 

meet an emission limit of 170 ng/J (0.4 

lb/million Btu) heat input. 

(6) Steam generating units located in 

noncontinental areas (Hawaii, the 

Virgin Islands, Guam, American Samoa, 

the Commonwealth of Puerto Rico, and 

the Northern Mariana Islands) are 

exempt from the percentage reduction 

requirements but must meet certain 

emission limits. Coal-fired steam 

generating units are subject to an 

emission limit of 520 ng/J (1.2 lb/million 

Btu) heat input. Oil-fired steam 

generating units are subject to an 

emission limit of 130 ng/J (0.3 lb/million 

Btu) heat input. 

(7) Fluidized bed combustion (FBC) 

steam generating units combusting coal 

refuse must achieve an 80 percent 

reduction in potential SOj emissions and 

meet an emission limit of 520 ng/J (1.2 

lb/million Btu) heat input. 

(8) Duct burners operating as part of a 

supplementary-fired combined cycle 

system in which less than 30 percent of 

the total heat input to the steam 

generating unit is from the combustion 

of coal or oil in the duct burner are 

exempt from the percentage reduction 

requirements but must meet certain 

emission limits. Coal-fired steam 

generating units are subject to an 

emission limit of 520 ng/J (1.2 lb/million 

Btu) heat input. Oil-fired steam 

generating units are subject to an 

emission limit of 130 ng/J (0.3 lb/million 

Btu) heat input. 

(9) Steam generating units combusting 

very low sulfur content oil are exempt 

from the percentage reduction 

requirements, but are subject to an 

emission limit of 130 ng/J (0.3 lb/million 

Btu) heat input. 

(10) Continuous SO2 emission 

monitoring is required for all coal- and 

oil-fired steam generating units. The SO2 

emission data collected through 

continuous monitoring are used to 

determine compliance with the 

standards on a continuous basis through 

the use of a 30-day rolling average 

emission rate and percent reduction 

level calculated each day. All 

continuous emission monitoring systems 

(CEMS) are subject to the quality 

assurance requirements in Appendix F, 

Procedure 1 (52 FR 21003; June 4,1987). 

Method 6B stack sampling is allowed 

both as an alternative SO2 monitoring 

method and to supplement CEMS data 

to meet the minimum data requirements 

(75 percent of steam generating unit 

operating hours during a steam 

generating unit operating day). For units 

firing low sulfur coal or oil without an 

SO2 control technology, fuel sampling 

and analysis procedures are allowed as 

an alternative to CEMS or Method 6B. 

Quarterly reporting of all 30-day rolling 

average emission rates and percent 

reduction, as applicable, is also 

required. 

(11) Except as provided below, all 

coal- or oil-fired steam generating units 

must conduct an initial 30-day 

compliance test. 

(12) Steam generating units 

combusting only oil and that have a 

Federally enforceable permit limiting the 

combustion of oil to 10 percent or less of 

the maximum annual steam generating 

unit heat input capacity are not required 

to perform an initial 30-day compliance 

test but must perform an initial 24-hour 

compliance test. 

C. Particulate Matter Standards 

For steam generating units firing oil, 

either alone or in combination with 

other fuels, the particulate matter 

emission limit is 43 ng/J (0.1 lb/million 

Btu) heat input. 

The opacity limit for steam generating 

units firing oil, alone or in combination 

with other fuels, is 20 percent opacity (0-

minute average) with one 6-minute 

excursion per hour up to 27 percent 

opacity. The opacity standard applies at 

all times except during periods of 

startup, shutdown, or malfunction as 

provided by the General Provisions (40 

CFR 60.11(c)). 

Performance tests to determine 

compliance with the particulate matter 

emission limits are conducted using 

Method 5, 5B (51 FR 42839; November 26, 

1986), or 17. Method 5B is used to test 

wet scrubbing systems; otherwise 

Methods 5 and 17 are used. Method 3 is 

used for gas analysis and Method 1 for 

the selection of sampling points. 

Method 9 is used to determine 

compliance with the opacity standard. 

The steam generating unit owner or 

operator may elect to use the opacity 

monitor to determine compliance with 

the opacity standard under the General 

Provisions, as amended (52 FR 9778; 

March 26,1987). Continuous opacity 

monitoring is required for all steam 

generating units except as provided for 

by the General Provisions (§ 60.11(b)). 

Excess emissions (opacity) reports are 

required to be submitted on a 

semiannual basis. 

II. Summary of Changes to Proposed 

Standards 

A. Sulfur Dioxide Standards 

The final standards retain the 90 

percent reduction requirements for SOa 

emissions that were included in the 

proposed standards. However, based on 

comments received after proposal, 

certain situations were identified where 

the impacts of achieving a 90 percent 

reduction were judged to be 

unreasonable. Emission limits remain 

applicable in all cases. 

Under the proposed standards, SOa 

percent reduction requirements were not 

applicable to mixed-fuel-fired steam 

generating units (units firing mixtures of 

coal/wood or coal/municipal waste) 

that had an annual coal capacity factor 

of 30 percent or less. Under the final 

standards, this exemption from percent 

reduction requirements has been 

expanded to cover all low capacity 

factor steam generating units 
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47828 Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

combusting coal or oil, including both 

mixed-fuel-fired applications and fossilfuel-fired applications (units that 

combust only coal or oil). As with the 

proposed standards, to qualify for this 

exemption, the unit must have an annual 

coal and oil capacity factor of 30 percent 

or less and a Federally enforceable 

operating permit that limits annual coal 

and oil combustion to 30 or less of 

annual rated capacity. 

An exemption from the percent 

reduction requirement has also been 

included in the final standards for steam 

generating units located in 

noncontinental areas (Hawaii, the 

Virgin Islands, Guam, American Samoa, 

Puerto Rico, and the Northern Mariana 

Islands). 

Fluidized bed combustion units firing 

coal refuse are required to achieve an 80 

percent reduction in SO2 emissions. This 

less stringent provision was not 

included in the proposed standards, but 

was added to the final standards. 

The final standards also include a 

provision exempting steam generating 

units combusting very low sulfur oil 

from percent reduction requirements. 

B. Sulfur Dioxide Compliance 

Provisions 

The proposed standards required all 

steam generating units to conduct a 30-

day performance test during initial 

startup. The final standards include the 

30-day performance test requirement for 

most steam generating units, but permit 

a 24-hour performance test for oil-fired 

steam generating units that have a 

Federally enforceable permit limiting 

combustion of oil to 10 percent or less of 

the maximum annual heat input 

capacity. 

In the proposed regulation, SO2 

emission monitoring and calculation of 

30-day rolling average emission rates 

and percent reduction levels would have 

been performed in accordance with 

Method 19 and Method 19A. The final 

standard specifies only one method, 

Method 19. Method 19 has been 

modified to incorporate certain relevant 

portions of Method 19A, and is being 

republished as part of today's action. 

The revised Method 19 includes SO2, 

NO„, and PM calculation procedures 

and addresses both steam generating 

units using SO2 control devices as well 

as units combusting low sulfur 

compliance fuels. Method 19 has also 

been revised to include fuel sampling 

and analysis procedures for determining 

SO2 emissions from steam generating 

units firing compliance fuels. 

Quality assurance procedures for 

CEMS are set forth in 40 CFR Part 60, 

Appendix F, Procedure 1. Appendix F 

was promulgated on June 4,1987 (52 FR 

21003) and applies to CEMS installed 

under today's standards to monitor SO2 

emissions. 

C. Particulate Matter Compliance 

Provisions 

The particulate matter compliance 

provisions remain the same as those 

promulgated on November 25,1986 (51 

FR 42768), as amended by the addition 

of Method 5B as a compliance method 

for "wet" stacks along with Methods 5 

and 17 for "dry" stacks. Method 5B was 

promulgated on November 26,1986 (51 

FR 42839). 

D. Reporting Requirements 

The reporting requirements remain 

essentially the same as those proposed, 

with one exception. Because the 

Appendix F quality assurance 

requirements for CEMS have been 

promulgated, quarterly reports required 

under Appendix F are now required to 

be submitted as part of the quarterly 

reports submitted under this regulation 

where CEMS are used. 

III. Summary of Impacts From the 

Promulgated Standards 

The projected national impacts 

associated with the final standards are 

summarized in Table 1. 

TABLE 1.—NATIONAL IMPACTS 

Air Emission Reductions: 

Sulfur Dioxide, thousand tons/yr.... 

Particulate Matter, thousand 

tons/yr. 

Liquid and Solid Wastes Generated: 

Liquid Wastes, million cutic ft/yr.... 

Solid Wastes, thousand tons/yr...... 

Energy Impacts: 

Increase in Natural Gas Use, trillion Btu/yr. 

Cost Impacts: 

yr. 

Average Cost Effectiveness, $/ 

ton. 

Incremental Cost Effectiveness, 

$/ton. 

IFCAM 

130-360 

9-24. _ 

Negligible 

Negligible 

110-310 

5-50 

40-130 

0 „ 

Sales 

data 

140 

3 

53 

270 

0 

120 

890 

1.400 

Projected national impacts associated 

with the standards can vary 

considerably depending on the approach 

used to estimate these impacts. The 

original approach used by the Agency 

starts with estimates of the growth in 

national energy consumption projected 

by the Department of Energy. These 

projections are used to estimate energy 

consumption in new industrialcommercial-institutional steam 

generating units. These energy 

consumption estimates, along with 

projections of future fuel prices, serve as 

inputs to a computer model, known as 

the "Industrial Fuel Choice Analysis 

Model" (i.e., IFCAM). 

Based on these input assumptions, 

IFCAM projects a population of new 

steam generating units distributed by 

geographic area, unit size, and operating 

level based on historical patterns. For 

each projected new steam generating 

unit, the total cost associated with each 

type of fuel that could be fired, including 

the costs to comply with standards 

limiting S02 emissions, is calculated and 

the lowest cost alternative is selected 

for compliance. The results are then 

aggregated to yield estimates of national 

impacts associated with standards 

limiting SO2 emissions. 

Using this approach, "fuel switching" 

from coal or oil to natural gas can occur 

in response to standards limiting SO2 

emissions. For example, in the absence 

of SO2 standards, it may be less 

expensive to combust coal or oil than 

natural gas. With SO2 standards, 

however, it may be less expensive to 

combust natural gas than coal or oil. 

When fuel switching occurs, it results in 

lower costs and greater SO2 emission 

reductions. 

The type of fuel projected by IFCAM 

to be fired in each new steam generating 

unit as well as the likelihood of fuel 

switching occurring in response to 

standards, depends primarily on relative 

fuel prices. Given the uncertainty in 

projected fuel prices, a number of 

different fuel price scenarios were 

examined. The range of national impacts 

associated with those projections of fuel 

prices which are currently considered 

"most likely" is shown under the 

"IFCAM" column in Table 1. 

A number of commenters stated that 

the approach used by the Agency to 

estimate national impacts (i.e., IFCAM) 

probably underestimated the costs and 

overestimated the emission reductions 

associated with the standards. 

Commenters suggested that both the 

• amount of fuel switching projected to 

occur as well as the-number of new 

steam generating units projected to be 

built were excessive. To respond to 

these concerns, an approach based on 

historical data was also used to 

estimate national impacts (shown under 

the "SALES DATA" column in Table lj. 

This alternate approach uses annual 

steam generating unit sales statistics 

gathered by the American Boiler 

Manufacturing Association (ABMA) for 

the past five years to project a 

population of new industrialcommercial-institutional steam 

generating units expected to be built in 

the next five years. The costs and 

emission reductions associated with the 

recommended standards are estimated 

for each new coal- or oil-fired steam 

generating unit. No fuel switching is 
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Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 47®29 

assumed to occur in response to 

standards limiting SO2 emissions, and 

the relative market shares by fuel type 

are assumed to remain constant. The 

results are then aggregated to yield an 

alternative estimate of national impacts. 

As shown in Table 1 the final 

standards result in significant 

reductions in SO2 emissions from new 

industrial-commercial-institutional 

steam generating units. Table 1 shows 

the standards could, however, result in 

some increase in liquid and solid waste. 

The amount of liquid and solid waste 

generated depends on the amount of fuel 

switching that occurs. When steam 

generating units fuel switch from firing 

coal or oil to firing natural gas, the SO2 

standards would not result in any waste 

generation and the standards could, in 

fact, result in a net decrease in liquid or 

solid wastes. When fuel switching does 

not occur, the liquid or solid waste 

increase depends on the type of FGD 

system installed to control SO2 

emissions. Some systems generate only 

liquid wastes, others generate only solid 

wastes. 

Impacts on energy consumption 

associated with the recommended 

standards also depend on the extent to 

which fuel switching occurs. At most, 

the standards would result in less than 5 

percent (310 trillion Btu/yr) increase in 

the amount of natural gas consumed by 

industrial sources. Much of this 

increased natural gas consumption, 

however, would be balanced by a 

corresponding decrease in oil 

consumption. Overall, therefore, the 

final standards are viewed as having 

minimal energy impacts and are 

considered consistent with national 

energy policies directed toward reducing 

imports of oil and increasing use of 

domestic energy supplies. 

In addition to the national impacts 

summarized in Table 1, industry specific 

economic impacts were also assessed 

for six industries which were considered 

likely to experience the most severe 

impacts. For these industries, product 

prices were projected to increase by less 

than 0.01 to 1.5 percent in 1990, 

assuming "full cost pass-through" of all 

increased costs associated with 

standards requiring a percent reduction 

in S02 emissions. Assuming "full cost 

absorption," return on assets was 

projected to decrease by 0.03 to 2.8 

percentage points. 

IV. Public Participation 

Prior to proposal of the standards, 

interested parties were advised of a 

meeting of the National Air Pollution 

Control Techniques Advisory 

Committee (NAPCTAC) to discuss the 

standards under development. This 

meeting was held on May 1 and 2,1985. 

The meeting was open to the public and 

each attendee was given an opportunity 

to comment on the standards. Several 

presentations to NAPCTAC were also 

made throughout the development of the 

proposed standards to solicit the views 

of committee members and interested 

members of the public. Additional 

meetings were held with affected 

industries at several times during 

development of the standards. 

The standards were proposed on June 

19,1986 (51 FR 22384). The preamble to 

the proposed standards discussed the 

availability of the background 

information documents, which consisted 

of nine documents listed in the 

preamble. These background 

information documents described in' 

detail the regulatory alternatives 

considered and the impacts of those 

alternatives. Public comments were 

solicited at the time of proposal, and 

copies of the background information 

documents were distributed. 

To provide interested persons the 

opportunity for oral presentation of 

data, views, or arguments concerning 

the proposed standards, a public hearing 

was held on September 4,1986, at 

Research Triangle Park, North Carolina. 

The hearing was open to the public and 

each attendee was given an opportunity 

to comment on the proposed standards. 

Nineteen interested parties testified at 

the public hearing concerning issues 

relative to the proposed standards. A 

transcript of the public hearing was 

prepared and placed in Docket A-83-27. 

The public comment period was from 

June 19,1986, to October 2,1986. A total 

of 99 comment letters were received and 

placed in Docket A-83-27. The 

comments have been carefully 

considered and, where determined to be 

appropriate by the Administrator, 

changes have been made in the 

standards. 

V. Significant Comments and Changes to 

the Proposed Standards 

Comments on the proposed standards 

were received from industry, trade 

associations, Federal agencies, State 

agencies, an environmental group, and 

the general public. A number of major 

issues were raised in the following 

areas: Applicability, Basis of Standard, 

Standard for SO2, National Impacts, 

Cost, Performance/Reliability of Control 

Technology, Environmental Impacts, 

Emission Credits, and Emerging 

Technologies. Significant comments are 

discussed below. A summary of all 

comments and responses which are not 

discussed below can be found in the 

promulgation Background Information 

Document (BID), which is referred to in 

the ADDRESSES section of this preamble. 

The summary of comments and 

responses discussed below, as well us in 

the BID, serves as the basis for the 

revisions that have been made to the 

standards between proposal and 

promulgation. 

A. Applicability 

A number of commenters felt thai 

steam generating units operating at low 

capacity utilization rates for oil or coal 

should be exempted from the SO2 

standards. They indicated that not all 

low capacity factor steam generating 

units would elect to use natural gas and 

said the cost to comply with the 

standards would be unreasonable for 

low capacity factor units combusting 

coal or oil, considering the small amount 

of SO2 control obtained. Specifically, the 

commenters mentioned auxiliary steam 

generating units located at electric 

utility power plants which are used to 

start up main steam generating units, 

industrial steam generating units that 

are operated infrequently to provide 

"backup" steam or to meet seasonal 

demands (i.e., peaking units), mixedfuel-fired steam generating units burning 

small amounts of coal or oil, and 

nonfossil-fuel-fired steam generating 

units that use oil or coal as a backup 

fuel during periods of unavailability of 

the nonfossil fuel. 

Review and reconsideration of the 

initial analysis, recent steam generating 

unit sales data, and recent operations 

data from new steam generating units 

leads to the conclusion that some plants 

will install coal- or oil-fired steam 

generating units even where natural gas 

is the fuel of economic choice and 

despite promulgation of standards 

requiring a percent reduction in 

emissions from coal- and oil-fired steam 

generating units. To avoid imposing 

emission control requirements that 

could result in unreasonable impacts, 

the 30 percent annual capacity factor 

exemption in the proposed standards for 

mixed-fuel-fired units was extended in 

the final standards to include coal- and 

oil-fired units. 

The owner or operator of such 

facilities must obtain a Federally 

enforceable permit limiting the annual 

capacity factor of the unit for coal and 

oil to 30 percent or less (see "Impact of 

New Fuel Prices on the Costs and Cost 

Effectiveness of SO2 Emission Control of 

Industrial Coal- and Oil-Fired Model 

Steam Generating Units," 1987; 

"Alternative Estimates of National 

Impacts Based on Steam Generating 

Unit Sales Data," 1987). Although "low 

capacity factor" steam generating units 

are exempt from percent reduction 
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Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

1 v = 

requirements, they are required to meet 

certain emission limits. Emissions of 

SO2 from steam generating units 

operating at coal and oil annual 

capacity factors of 30 percent or less 

would be limited to 520 ng/J (1.2 lb/ 

million Btu) heat input if coal is fired 

and 130 ng/J (0.3 lb/million Btu) if oil is 

fired (see "Assumptions and Procedures 

Used to Generate Model Boiler 

Impacts," 1987; "Availability of Very 

Low Sulfur Fuel Oil," 1987). Based on 

these emission limits, the exemption 

from percent reduction requirements for 

steam generating units operating at less 

than a 30 percent coal and oil utilization 

factor will reduce the cost of the final 

standards by up to 15 percent compared 

to no exemption, but results in less than 

a 2 percent increase in SO2 emissions 

compared to no exemption. 

Continuous emission monitoring (or 

fuel sampling and analysis), continuous 

compliance provisions, and quarterly 

reporting are required for all steam 

generating units, including "low 

capacity factor" units. If a decision is 

subsequently made to operate a "low 

capacity factor" steam generating unit at 

higher loads, the operating permit would 

have to be revised and compliance with 

the percent reduction requirement would 

be necessary. 

Other commenters requested that an 

exemption from the percent reduction 

requirement be granted for steam 

generating units buming anthracite coal 

or anthracite mining waste (culm), as 

was done in Subpart Da for electric 

utility steam generating units. Some 

commenters also stated that other coal 

mining and washing wastes should be 

included in this exemption. 

The exemption from the percent 

reduction requirement granted for 

anthracite in Subpart Da was provided 

to encourage reclamation of abandoned 

anthracite mines during new anthracite 

mining, resulting in environmental 

benefits such as improvement of mine 

drainage acid-water conditions, 

elimination of old mining scars on the 

topography, and eradication of 

dangerous fires in deep mines and culm 

banks. The exemption from the percent 

reduction requirement provided for 

anthracite under Subpart Da was to 

create a special local utility market for 

this fuel, and the environmental benefits 

associated with utility-scale reclamation 

were judged to outweigh environmental 

impacts from burning anthracite without 

a post-combustion SO2 control system. 

The smaller coal demand in the 

industrial-commercial-institutional 

steam generating unit market will not 

result in utility-scale mine reclamation 

even if an exemption from the percent 

reduction requirement were granted for 

anthracite (see "Electric Utility Steam 

Generating Units Background 

Information for Promulgated Emission 

Standards," 1979). Therefore, no special 

•provisions for anthracite have been 

included in the final standards. 

A different situation exists, however, 

with the firing of anthracite mining 

waste and other coal mining and 

washing wastes (collectively referred to 

as coal refuse). These wastes raise 

concerns similar to those addressed in 

the Subpart Da exemption for 

anthracite. These waste piles are not 

only unsightly, but they are responsible 

for acid-water drainage problems and 

can also lead to fires from spontaneous 

combustion. Therefore, it is important to 

encourage the use of these wastes as 

fuels in steam generating units 

(specifically fluidized bed combustion 

[FBC] steam generating units) to 

eliminate a potential environmental 

hazard. Consequently, a less stringent 

requirement of 80 percent reduction 

combined with an emission limit of 520 

ng/J (1.2 lb/million Btu) has been 

provided for FBC steam generating units 

which fire coal refuse. This action 

balances the need to minimize air 

pollution from combustion of these 

wastes against the environmental 

benefits resulting from eliminating coal 

refuse piles. 

One commenter said the final 

standards should include an exemption 

from the percent reduction requirement 

for steam generating units located in 

noncontinental areas, as was done in 

Subpart Da. The commenter said that, 

due to a lack of flexibility in fuel choice 

and the necessity of importing the 

reagent materials necessary for flue gas 

desulfurization (FGD) system operation, 

the costs associated with achieving a 

percent reduction in emissions could be 

exorbitant. 

Facilities in noncontinental areas 

(Hawaii, the Virgin Islands, Guam, 

American Samoa, Puerto Rico, and the 

Northern Mariana Islands) constitute a 

subcategory subject to unique 

environmental and economic constraints 

in complying with this NSPS. Because of 

a lack of natural gas supplies, "fuel 

switching" to natural gas is not feasible. 

In addition, the cost of importing FGD 

reagent and other materials to 

noncontinental areas would make die 

costs associated with achieving a 

percent reduction in emissions much 

higher than on the continental mainland. 

In light of these considerations, an 

exemption from the percent reduction 

requirement has been provided for 

steam generating units located in 

noncontinental areas, regardless of the 

capacity factor of the unit. Such 

facilities are, however, required to meet 

the S02 emission limitations discussed 

above for units operating at low 

capacity factors for coal or oil. These 

emission limits, as well as the fact that 

these facilities will be reviewed to 

ensure compliance with limitations 

established under the prevention of 

significant deterioration (PSD) program, 

will minimize the impact of these 

facilities on ambient air quality. 

B. Basis of Standard 

A number of commenters questioned 

the legal basis for establishing a percent 

reduction requirement as the basis of 

the standard. They said the percent 

reduction provision in section 111 of the 

Clean Air Act was intended to apply to 

utility steam generating units only, and 

is not appropriate for industrialcommercial-institutional steam 

generating units. 

The percentage reduction requirement 

was enacted by the 1977 Amendments 

to the Act. Section 111(a)(1) defines the 

term "standard of performance" as 

follows: 

(A) with respect to any air pollutant 

emitted from a category of fossil fuel fired 

stationary sources * * * a standard— 

(i) establishing allowable emission 

limitations for such category of sources, and 

(ii) requiring the achievement of a 

percentage reduction in the emissions from 

such category of sources from the emissions 

which would have resulted from the use of 

fuels which are not subjsct to treatment prior 

to combustion. 

Although the discussion of the 

percsntege reduction requirement in the 

legislative histciy sometimes refars to 

particular types of fossil-fuel-fired 

sources, the term "boilers" is used 

generally and is not limited to utility 

steam generating units. The legislative 

history specifically mentions "industrial 

sources" and "mines, processing plants, 

and factories," and indicates that the 

Agency has the authority to include a 

percentage reduction requirement in an 

NSPS for fossil-fuel-fired sources; S. 

Rep. No. 564, 95th Cong., 1st Sess. 130 

(1977); H.R. Rep. No. 294, 95th Cong., 1st 

Sess. 188 (1977) at 188-192; Accord, 

Sierra Club v. Ruckelshaus,. Civil 

Action No. 84-0325 (D.D.C. Sept. 4, 

1985), at 5. 

Some commenters asserted that the 

Agency concluded after promulgation of 

the utility steam generating unit NSPS 

that there was no obligation to revise 

the existing large industrial steam 

generating unit NSPS (Subpart D) to 

include a percent reduction requirement. 

The commenters referred to a brief filed 

by the Agency in Sierra Club v. 

Ruckelshaus in 1984. 
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Kegaste / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 6fmi 

The issue in Sierra Club was the 

scope of the nondiscretionary duties 

under section 111(b)(6). The Agency did 

not express any view in that case about 

the application of percentage reduction 

requirements under section 111(a)(1) to 

industrial-commercial-institutional 

steam generating units, but simply 

argued that section 111(b)(6) did not 

impose a nondiscretionary duty to 

promulgate revised NSPS for these 

steam generating units. Similarly, the 

utility steam generating unit NSPS 

rulemaking cited in that brief did not 

analyze the applicability of the 

percentage reduction requirement to 

non-utility steam generating units; 44 FR 

33580 (June 11,1979); 43 FR 42154 (Sept 

19,1978). 

Other commenters said that section. 

Ill gives the Agency the flexibility to 

forego a percentage-reduction where 

there is no demonstrated need for it, or 

where the costs are too high compared 

to the benefits, or where a percent 

reduction would create more problems 

than it solves. Several commenters said 

that an emission limit only, rather than a 

percent reduction requirement, should 

be established and sources should be 

allowed to achieve that limit by 

whatever means is appropriate for each 

source. 

Section 111 does provide the 

flexibility to forego the percentage 

reduction requirement if the impacts 

associated with it would be 

unreasonable and exemption from 

percent reduction has been provided in 

the final standards where impacts 

would have been unreasonable. A 

thorough analysis of the economic, 

environmental, and energy impacts 

based on the exemptions included in the 

final standards was-conducted, and no 

unreasonable impacts were identified. 

Therefore, tha final standards 

promulgated under section 111 are 

considered reasonable. 

The percent reduction requiriament 

doss not force a source to install any 

particular technological system of SO* 

emission reduction. It is simply & 

performance standard that is based on 

the performance capabilities of the "beat 

demonstrated technology." Sources arefree to use any technological system that 

is able to achieve emission reductions 

equal to or greater than that achievable 

by the "best demonstrated technology." 

C. Standard for Sulfur Dioxide 

Some commenters expressed concern, 

that a 90 percent reduction, requirement 

was too stringent to allow flexibility in 

selection of SOz control, technology. 

They felt that a lower percent reduction, 

requirement would allow the use of less . 

expensive technologies, achieve 

comparable SOi control, and foster 

increased coal use in the future. 

The issue of regulatory compliance 

flexibility of a SO percent reduction 

requirement compared to lower percent 

reduction requirements was carefully 

evaluated. While it is true that lower 

percent reduction requirements would 

allow the use of a greater number of SO3 

control technologies, this alternative 

must be evaluated in relation to the 

requirements of section 111 of the Clean 

Air Act. Section 111 requires the NSPS 

to be established at the level achievable 

by the best demonstrated technology foir 

which no unreasonable cost, 

environmental, or energy impacts have 

been identified. This "best demonstrated 

technology" is flue, gas desulfurization 

and fluidized bed combustion, both of 

which have demonstrated 90 percent 

reductions in SOs emissions. In addition, 

the impacts associated with achieving a 

90 percent reduction as required by the 

final standard are considered 

reasonable. Thus, the final standards 

require a 90 percent reduction in SOs 

emissions from coal and oil, except 

where unreasonable impacts would 

occur. In these cases, percent reduction 

is not required, but an emission limit 

based on use of low sulfur compliance 

fueLis applicable. 

To provide some flexibility and to 

encourage the development of 

alternative SO2 control technologies, a 

percent reduction requirement of 50 

percent has been established for 

emerging technologies, Thia provision, 

was discussed in the preamble to the 

proposed standards and ia retained irt 

the final standards and is discussed in 

more detail below. 

Several commenters said the 

requirements in the Subpart De electric 

utility NSPS should be the most 

stringent scenario considered for 

industrial-commercial-inatitutional 

steam generating units. They said there 

is no reason, industrial-commercialinstitutional units should bs regulated 

more stringently than utility units. 

Direct comparison of the standard for 

industrial-commercial-institu tional 

steam generating units, witii the utility 

standard promulgated in 1979 isinappropriate for several reasons. 

First, the design and. operating 

characteristics of utility steam 

generating units and emission control 

systems are different from industrialcommercial-institutionel units. Utility 

steam generating units are generally 

much larger. A typical electric utility 

unit would have a heat input capacity of 

about 1,450 MW (5,000 million Btu/ 

hour). This compares to 44 MW (150 

million Btu/hour) heat input capacity for 

a typical industrial-commarcialinstitutional unit, 0 30-fold difference in 

size. Because of their large size, utility 

steam generating units and FGD Gyutt'-ns 

are field erected and are usually cun'om 

designed for a specific sita. Long-torn: 

fuel purchase contracts for up to 22 

years are common. As c result, uii'.V.y 

ateam generating units1 and FGD nynta::o 

can be designed to optimise site- ur.ii 

fuel-specific factors. Also, tc handL: f'tc 

large quantities of flue gaa generated, 

utility FGD systems typically conoici «r 

multiple parallel FGD modules (tynica[Iy 

4 or 5 modules), with eoclt capable of 

handling part of tho total flue gas. Tu 

ensure operating reliability of tho total 

FGD system, an additional FGD moddc 

is frequently installed as c spare or 

backup module to be available during 

periods of FGD malfunction or for 

rotation during preventive maintenance) 

and servicing of other FGD moduleo. 

In contrast, industrial-commercialinstitutional steam generating units and 

FGD systems are likely to be shopassembled based on standard designs 

and have the ability to handle a wider 

range of fuels than typical utility steam 

generating units. Also, long-term fuel 

supply contracts specifying delivery of a 

fuel of well-defined quality are less 

common than in utility applications. 

Because of their smaller size, switching 

to natural gas or low sulfur oil during 

FGD system malfunctions is a viable 

alternative to installing a spare FGD 

module. 

Second, at the time Subpart Da wag 

promulgated, lime/limestone wet 

scrubbing was the predominant FGD 

technology used by utilities. Newer 

technologies, such as lime spray drying 

FGD, were still in the early stages of 

commercial application and concerno 

existed about the ability of theoo newer 

technologies to achieve high. SOa 

reductions on a reliable basis. Today, c 

number of demonstrated FGD 

technologies are available for use by 

Indus trialrcommercial-institutional 

steam generating units including sodium 

scrubbing, lime spray drying, and duo! 

alkali FGD systems, as well as fluidisnd! 

bed combustion. Based on oxperieaco 

gained with these technologies during 

the past decade, as well e& various 

technical advantages of these 

technologies over wet lime/limestone 

FGD, industrial FGD systems ara 

expected to be more efficient ei:d 

reliable than utility FGD systems wcra 

at the time Subpart Da wea adopted. 

Because of the many differencee 

between industrial-commercialinstitutional and utility steam gencrctfRQ 

units, it is inappropriate to concluda tfeal 

the standards being adopted todcy rnuafl 

mimic Subpart Da. 
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47832 Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

Some commenters said the proposed 

S02 emission limit of 86 ng/J (0.2 lb/ 

million Btu) for an oil-fired steam 

generating unit without an FGD system 

was unrealistic. They said that oil with 

this sulfur content is not commercially 

available, and suggested sulfur contents 

ranging from 130 ng/J (0.3 lb/million Btu) 

to 260 ng/J (0.6 lb/million Btu) as low 

sulfur oil compliance alternatives. 

The basis for the S02 emission limit of 

86 ng/J (0.2 lb/million Btu) in the 

proposal was to provide an alternative 

means of demonstrating compliance 

with the percent reduction requirement. 

The sulfur content of this oil was so low 

that it appeared reasonable to assume 

that refining of the original crude oil had 

resulted in a 90 percent reduction in 

potential SO2 emissions. This provision, 

therefore, was not based on an 

assessment of the availability of such 

oils, but merely an assessment of how 

low the sulfur content of an oil would 

need to be in order to reasonably ensure 

that a 90 percent reduction in its sulfur 

content had been achieved. 

As a result of these comments, the 

basis for this provision was reviewed. A 

more detailed assessment than that 

done at the time of proposal was 

undertaken to determine the means by 

which most very low sulfur oils are 

produced. This assessment concluded 

that most very low sulfur oils, even 

those as low as 86 ng/J (0.2 lb S02 / 

million Btu), are produced by distillation 

of very low sulfur content crude oils, 

and that little or no desulfurization may 

take place. The analysis also indicated 

that most desulfurized oils were not sold 

as very low sulfur content fuel oils, but 

were upgraded to gasoline or other 

higher cost products. As a result, there is 

no particular sulfur content that can 

reasonably be assumed to be the result 

of 90 percent reduction by fuel 

pretreatment (i.e., hydrodesulfurization). 

Consequently, the final standards 

contain no provisions similar to those 

proposed that provide an alternative 

means of demonstrating compliance 

with the 90 percent reduction 

requirement. 

However, the final standards do 

exempt oil-fired steam generating units 

from the percent reduction requirements 

where the impacts associated with the 

percent reduction requirements are 

considered unreasonable. These steam 

generating units, however, are subject to' 

an SO2 emission limit, which in the case 

of oil-fired units is 130 ng/J (0.3 lb S02 / 

million Btu). 

Unlike the 86 ng/J (0.2 lb/million Btu) 

emission limit provided at proposal, the 

130 ng/J (0.3 lb/million Btu) emission 

limit for steam generating units exempt 

from the percent reduction requirement 

is based on an assessment of the 

emissions, costs, and availability of 

such oils. As cited by the commenters. 

this assessment found that the lowest 

sulfur content specification placed on 

commercially available oils is generally 

130 ng/J (0.3 lb/million Btu). Oils with 

such low sulfur contents, however, are 

widely available. In some areas, these 

oils may be residual oils and in other 

areas they may be distillate oils. In 

either case, such oils are available and 

the costs associated with their use are 

considered reasonable compared to 

higher sulfur content oils. Consequently, 

where low capacity factor oil-fired 

steam generating units are exempt from 

the percent reduction requirements in 

the final standards, they are subject to 

an S02 emission limit of 130 ng/J (0.3 lb/ 

million Btu). 

In reviewing the reasonableness of 

applying percent reduction requirements 

to higher capacity oil-fired steam 

generating units, reasonable impacts 

were noted for most oil-fired units. 

Unreasonable impacts were noted, 

however, for applying percent reduction 

requirements to very low sulfur oils. 

Thus, the final standards exempt from 

percent reduction requirements steam 

generating units firing very low sulfur 

oils with S02 emission rates less than 

130 ng/J (0.3 lb/million Btu) because of 

unreasonable impacts. 

The final standards exempt from 

percent reduction requirements duct 

burners used as part of combined-cycle 

systems. This exemption is included 

because of cost-effectiveness 

considerations and is analogous to the 

exemption from percent reduction for 

mixed-fuel-fired steam generating units 

that have an annual coal and oil 

capacity factor of less than 30 percent. 

The effect of exhaust gases supplied to 

the duct burner from upstream processes 

(e.g., gas turbine, internal combustion 

engines, kilns, etc.) is similar to the 

firing of wood or municipal waste with 

coal or oil in a mixed-fuel-fired steam 

generating unit. The cost-effectiveness 

considerations associated with the 

exemption of duct burners from percent 

reduction requirements are the same as 

those for both mixed-fuel-fired and 

fossil-fuel-fired steam generating units 

with low annual coal and oil capacity 

factors. 

D. National Impacts 

Several commenters felt that the 

proposed standards conflict with a 

national energy policy of encouraging 

the use of domestic coal and encourage 

further U.S. dependence on unreliable 

foreign energy supplies. One commenter 

expressed concern about any regulation 

that discouraged coal use, unless some 

assurance could be provided that the 

exodus from coal will not be to oil. 

Another said that recent national energy 

policy recommendations should be 

considered in developing these 

standards. 

Revised fossil fuel price scenarios 

indicate that, with recent oil and gas 

prices, the costs of generating steam 

from oil and natural gas are competitive 

with those of generating steam from 

coal. In fact, based on economic factors 

alone, it is expected that natural gas 

and, to some extent, oil will claim the 

largest share of the industrialcommercial-institutional steam 

generating unit market even in the 

absence of the standards. Thus, the 

current level of oil and natural gas 

prices will have much more impact on 

coal use in industrial-commercialinstitutional steam generating units than 

will the final standards. 

In addition, the total amount of fossil 

fuel demand by industrial-commercialinstitutional steam generating units is a 

very small percentage of total U.S. 

demand, and any changes in the fuel 

mix in this sector will not cause 

significant changes in U.S. energy 

markets or threaten U.S. energy security. 

For example, the national impacts 

analysis assumes that sales of new 

industrial-commercial-institutional 

steam generating units over the next 5 

years will result in total annual fossil 

fuel consumption of 525 PJ (500 trillion 

Btu). This represents less than 2 percent 

of the total current U.S. oil market 

(about 32,500 PJ or 31,000 trillion Btu per 

year). 

A number of commenters said the fuel 

price scenarios used to evaluate the 

impacts of the proposed standards were 

out-of-date. One commenter said that a 

greater range of energy prices and a 

spectrum of possible energy scenarios 

should be considered in evaluating the 

possible energy impacts of the 

standards. In addition, this commenter 

suggested that an energy scenario in 

which oil and gas prices increase 

substantially, leading to massive fuel 

switching from oil and gas to coal, be 

considered. 

As a result of changes in fossil fuel 

prices since early 1986, the projected 

energy prices used to assess the impacts 

associated with the proposed standards 

were reviewed. This review led to 

development of revised projections of 

future energy prices. These revised 

projections reflect several different, but 

possible, energy scenarios.and, as a 

result, lead to a wide range in projected 

prices. Two scenarios concerning future 

world oil prices, for example, were 

considered. Both reflect current "low" 
P.10 

Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations A?A!3 

world oil prices, but one scenario 

assumes a gradual increase in world oil 

prices while the other assumes a rapid 

return to "high" oil prices. 

Similar to the results of the analysis 

under the projection of future energy 

prices considered most likely at 

proposal (Le., the high oil penetration 

scenario), these revised projections of 

future energy prices led the Industrial 

Fuel Choice Analysis Model (IFCAM) to 

project that new steam generating units 

will generally fire natural gas or oil. 

Very little, if any,, coat is projected to be 

fired in new units. An energy scenario 

leading, to massive, fuel switching from 

oil and natural gas ta coal,, therefore, is 

considered improbable. 

Using these revised projections of 

future energy prices, the potential 

national impacts, associated with the 

final standards were examined 

("Revised Impacts of Alternative Sulfur 

Dioxide New Source Performance 

Standards for Industrial Fossil FuelFired Boilers," February 1987). Natural 

gas consumption in new steam 

generating units is projected by IFCAM 

to increase by about 120-330 PJ/yr (110-

310 trillion Btu/yr) in 19Sa This 

represents about 1.5 to 4.5 percent of 

natural gaa consumption by all 

industrial sources- This projected 

increase in natural gas consumption, 

however, ia projected to be 

accompanied by a similar decrease in 

national oil consumption- Coal 

consumption is not projected to be 

affected since little coal consumption by 

new steam generating units is projected 

by IFCAM even in die absence of a a 

NSPS. 

The. final standards are also projected 

to reduce national SO* emissions by 

120,000 to 320,000 Mg/yr (130,000 to 

360,000 tons/yr) in 1990. The 

corresponding national annualized costs 

are projected to range from $5 to 50 

million. 

A number of commenters questioned 

whether fuel switching to natural gas 

would be as widespread as IFCAM 

projects. In response to these comments, 

the national impacts associated with the 

final standards were estimated based on 

historic steam generating unit sales data 

and the assumption that fuel switching 

from oil or coal to natural gas would not 

occur ("Estimation- of National Impacts 

Based on Steam Generating Unit Sales 

Data," 1S87). Using this approach, total 

national annual costs associated with 

the final standard are projected to be -

$120 million. Nationwide emissions of 

S02 are projected to decrease by 130,000 

Mg/yr (140,030 tons/yr), resulting in an 

average cost effectiveness of $980/Mg 

($890/ton). The national incremental 

cost effectiveness of the final standards 

relative to standards based on 

combustion of low sulfur fuel is 

projected to be about $1,600/Mg ($1,400/ 

ton) of S02 . 

Depending on the extent to which 

sources elect to fuel switch to natural 

gas, the incremental cost effectiveness 

of the emission reduction requirement 

will range from zero (in the case of the 

complete substitution projected by 

IFCAM) to $1,600/Mg ($1,400/ton) (in 

the case of no change in fuel market 

shares). EPA believes that some fuel 

switching to natural gas will occur—a 

propensity this rule may foster—and 

that the real incremental cost 

effectiveness of the final standards is 

likely to be lower than the no fuel 

switching case described above. EPA 

views all of these estimated impacts— 

zero from IFCAM, $1,600/Mg ($1,400/ 

ton) based on historical data, and some 

intermediate value based on some level 

of fuel switching—as reasonable. 

A number of commenters questioned 

the potential impact of standards on the 

installation of new steam generating 

units and the replacement of old steam 

generating units. Some felt that the 

IFCAM analysis overestimated the total 

steam generating unit population 

because replacement steam generating 

units were treated aa "new capacity." 

According to the commenters, as much 

as 60 percent of new units are installed 

as replacements for existing units. The 

commenters indicated that stringent 

standards could discourage these 

replacement projects, resulting in a 

further depression of the already 

sluggish industrial-commerciarinstitutional steam generating unit 

market and a net increase in SQs 

emissions compared to standards based 

on combustion of low sulfur fuel. 

The number of new steam generating 

unit installations used by IFCAM to 

estimate national impacts is based on 

projections of growth in energy 

consumption developed by the 

Department of Energy. The projected 

number of new unit installations using 

this approach is about double the 

estimates made by other organizations, 

such as the American Boiler 

Manufacturers Association (ABMA). As 

shown by sales statistics, annual steam 

generating unit sales have decreased 

since 1970 due to lower growth in steamr 

consuming industries and energy 

conservation efforts, but appear to have 

stabilized since 198a Thus, it is possible 

that emission reductions as well as costs 

attributed to the proposed standards 

may be overestimated to some extent. 

However; this does not significantly 

alter the overall balance between the 

costs and benefits of the standard. Even 

if fewer new steam generating units are 

built than projected, the SOa reductions 

achieved by the standard are still 

considered significant, both from 

individual units and from the source 

category as a whole. Also, while strain 

generating unit sales are lower than ;n 

1970, new units are being built and will 

continue to be built in the future. Aa 

more and more units are constructed, 

further SOa reductions will be achieved 

by the standards being adopted toduy. 

The cost, environmental, and energy 

impacts of the final standerds therefore 

are considered reasonable, even 

assuming lower population growth 

projections. 

In response to comments concerning 

the proportion of new steam generating 

units that are replacements for existing 

steam generating units, a survey wan 

conducted of steam generating units 

ordered between January 1981 and 

September 1984 ("Survey of New 

Industrial Boiler Projects—1981-1984," 

EPA-450/3-87-C08, April 1987). 

Responses were received for 16a new 

projects, encompassing a total of 229 

new steam generating units. Of these, 

151 steam generating units were in the 

regulated size category and formed the 

basis for the analysis diecuosed below. 

Comparison with steam generating unit 

sales data collected by ABMA indicated 

that these units represent almost ull of 

the industrial steam generating unitn in 

this size category sold between 1931 and 

1984. The survey indicated that ubout 50 

percent of new steam generating units, 

rather than 80 percent as suggested by 

the commenters, were for replacement 

of existing steam generating units. 

Assuming that recent declines in thu 

price of oil and natural gas result in n 

curtailment of new steam generating 

units installed for the purpose of 

switching from oil or gas to coal, the 

percentage of new steam generating 

units sold as replacements for existing 

units will be even lower than indicated 

by the survey. 

Many commenters noted that without 

an option to use low sulfur fuel, 

operating costs for new steam 

generating units will increase 

sufficiently to discourage their 

installation, thus inhibiting the 

replacement of existing units firing high 

sulfur fuels and delaying the reductions 

in SOa emissions associated with th:s 

replacement process. 

New steam generating unit purchases 

can be divided into two categories: . 

discretionary, meaning the purchase 

could be deferred if economics, 

environmental requirements, or other 

factors changed; and nondiscretionary, 

meaning a new unit must be installed. 

The above survey indicated that 
p.11 

47834 Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

discretionary installations accounted for 

about half of the new steam generating 

unit projects surveyed. However, the 

survey found that many of these 

discretionary installations were 

relatively insensitive to cost changes. 

Nearly three-fourths of all projects 

would have proceeded as designed if 

costs increased by up to 20 percent. In 

almost all cases, the percent reduction 

requirement would increase costs by 

less than this amount. Therefore, while 

some projects could be affected by the 

NSPS, most of the new steam generating 

unit installations would remain viable, 

and are not expected to be discouraged 

or delayed by the final NSPS. 

In response to comments suggesting 

an NSPS might actually result in 

delaying emission reductions due to a 

slowdown in new steam generating unit 

installations, data from the boiler 

replacement survey mentioned above 

were used to examine the change in 

overall S02 emissions from plants 

installing new industrial steam 

generating units. Analysis of S02 

emissions before and after installation 

of the new steam generating units found 

that, although the new coal- and oil-fired 

steam generating units generally emitted 

less S02 per million Btu of fuel fired 

than the existing (replaced) steam 

generating units, the total annual 

emissions (i.e., tons/year) emitted by 

plants installing new steam generating 

units increased by roughly 70 percent. 

This increase results from (1) 

installation of new steam generating 

capacity that is not replacing existing 

units, (2) replacement of existing units 

with new units that are significantly 

larger, (3) fuel switches from natural gas 

and oil to coal for energy independence, 

and (4) continued operation of the 

existing steam generating units which 

were "replaced" by new units. 

A large portion of the emissions 

increase was due to steam generating 

units installed either to switch base fuel 

(usually from gas or oil to coal) or to 

cogenerate electricity. Because these 

types of projects are sensitive to cost 

considerations and to provide 

conservative estimates, calculations 

were also made excluding these types of 

projects. Even without these significant 

sources of SO2 emissions, total 

emissions at plants installing new steam 

generating units increased by roughly 20 

percent after installation of new 

projects. These results indicate that 

installation of new steam generating 

units did not result in any "natural" 

decrease in overall SO2 emissions. 

Based on further analysis of the survey 

data, however, applying a 90 percent 

reduction standard to the new steam 

generating units (assuming the standard 

did not affect the fuel choice and design 

of the projects) would have resulted in 

an estimated net reduction in S02 

emissions from these plants of 25 to 30 

percent. 

Other commenters said that, by 

including replacement units in the 

analyses of new steam generating units, 

the proposal overestimated the actual 

emission reductions attributable to the 

standards. 

Emissions from all new steam 

generating units (including those that 

replaced existing steam generating 

units) were correctly included as "new" 

capacity emissions in the impacts 

analyses. The SOa emission reduction 

attributed to the NSPS is the reduction 

in emissions from new steam generating 

units under the final standards 

compared to baseline emissions that 

would occur from the same units in the 

absence of the NSPS. Because SO2 

emissions from new industrialcommercial-institutional steam 

generating units can be reduced at 

reasonable cost, regardless of whether 

they are replacement or new capacity, 

they are covered by the final standards. 

E. Cost of the Standard 

Several commenters felt that the EPA 

cost analyses associated with the 

proposed standards were deficient or 

inaccurate. Commenters specifically 

mentioned that actual data, rather than 

estimates, should have been used for 

capital cost calculations, and that EPA 

should not use utility FGD cost data to 

estimate industrial-commercialinstitutional unit FGD cost. Other 

commenters stated that the cost 

estimates did not adequately consider 

costs associated with sludge disposal, 

the need for backup S02 control during 

control system malfunction, coal 

transportation, or manufacturers' profit 

margins. 

The cost estimates used to assess the 

impacts of various alternatives were 

generated from cost algorithms 

developed from data on industrial steam 

generating units supplied by vendors 

and no utility data were used. The 

validity of the cost algorithms was 

examined by comparison with costs 

associated with actual installations. The 

agreement between these algorithms 

and actual installations was found to be 

very good and was well within the 

general criteria of ± 30 percent for an 

individual unit which is normally 

associated with "budget cost" estimates. 

Validity of the costs used in the cost 

analyses was also confirmed by 

statements from several commenters, 

including some industry trade 

associations. This does not mean that 

the cost estimates generated by the cost 

algorithms will agree in every case with 

actual installed costs. Unique design 

requirements related to site-specific 

factors may well cause actual costs to 

be higher or lower than those generated 

by the cost algorithms used in the cost 

analyses. The costs generated by the 

cost algorithms, however, are 

considered representative of the costs 

associated with installation and 

operation of steam generating units and 

emission control systems and are 

appropriate for estimating total costs. 

The cost analyses examined the costs 

associated with various emission 

control requirements for steam 

generating units as small as 29 MW (100 

million Btu/hour) heat input capacity 

and as large as 117 MW (400 million 

Btu/hour) heat input capacity. Costs 

were also assessed for units of 44, 58, 

and 73 MW (150, 200 and 250 million 

Btu/hour). The effects of "economies of 

scale," therefore, were considered in 

these cost analyses. 

Sludge disposal costs were included 

in the cost analyses. The costs reflect 

the typical costs associated with off-site 

land disposal of sludges from emission 

control systems. These costs were based 

on information provided by steam 

generating unit vendors and operators, 

and are considered representative of 

sludge disposal costs in general. They 

may, however, be lower or higher than 

actual costs experienced at specific 

locations where unique or site-specific 

requirements may apply. 

The cost analyses assumed, based on 

operating data from a number of FGD 

systems on industrial steam generating 

units, that FGD systems are capable of 

95 percent reliability with proper design, 

operation, and maintenance. The cost 

analyses, therefore, considered control 

system reliability and examined various 

approaches to reducing emissions during 

periods of control system malfunctions 

or servicing. These approaches included 

both the use of spare absorber modules 

and the firing of backup fuels such as 

natural gas. The assessment concluded 

that the costs associated with the use of 

spare absorber modules or the firing of 

very low sulfur fuels were of the same 

order of magnitude. Thus, either , 

approach could be used in the cost 

analyses to represent the additional 

costs of reducing emissions during 

periods of emission control system 

malfunction. For convenience and ease 

of calculation, the cost analyses 

assumed the firing of natural gas. The 

capital and annualized costs of spare 

equipment to fire natural gas, such as 

valves, controls, etc., were also added to 

the control costs. Consequently, the cost 
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Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 47835 

analyses considered the increased costs 

necessary to address reliability 

problems. 

The coal prices used in the cost 

analyses were also developed 

specifically for industrial-commercialinstitutional steam generating units. The 

coal transportation costs assumed single 

coal car rates to reflect the lack of 

volume discounts obtainable by utilities 

which use much greater quantities of 

fuel. 

Thus, the costs associated with the 

final standards were developed 

specifically for industrial-commercialinstitutional steam generating units, and 

these costs were carefully considered in 

developing the final standards. 

One commenter said the high 

emissions baselines used in the cost 

analysis resulted in underestimating the 

cost effectiveness of the standard. The 

baseline used in the national impacts 

analysis reflects existing State 

Implementation Plan (SIP) emission 

limits within each Air Quality Control 

Region (AQCR). The baseline used in 

the "model boiler" cost analysis was 

chosen to represent a typical SIP 

emission limit. Other baselines could 

have been selected. However, if more 

stringent baselines were used, the 

annualized costs for S02 control at the 

revised baseline would also have to be 

increased to account for the additional 

compliance costs associated with more 

stringent baseline regulations. Use of 

different baselines, however, would not 

alter the analysis of incremental 

differences in emissions and costs 

among increasingly stringent 

alternatives. Varying assumptions 

regarding the baseline have no effect on 

these incremental comparisons. As a 

result, changes or refinements in 

baseline emission levels would have 

little effect on judging the 

reasonableness of the final standard. 

Many commenters felt that the cost 

estimates associated with FGD systems 

were too low. Some said the costs of 

FGD systems are much greater for 

industrial-commercial-institutional 

steam generating units than for utility 

steam generating units due to lack of 

economies of scale, and this should be 

considered in calculating the impacts of 

the standards. Still other commenters 

said that because sodium once-through 

FGD was selected as the basis for the 

cost analysis, the costs were 

underestimated. 

The economics of FGD systems are 

different for utility and industrial steam 

generating units. Because of larger unit 

size and the higher capacity factors of 

many utility units, operating costs 

generally play a more dominant role in 

the economics of FGD systems for utility 

units than they do for industrial units. 

Thus, the typical FGD system for a 

utility steam generating unit is 

frequently one which minimizes 

operating costs, often at the expense of 

higher capital costs. In contrast, the 

most attractive FGD system for an 

industrial steam generating unit is 

frequently one which minimizes capital 

costs, often at the expense of higher 

operating costs. For example, sodium 

FGD systems are characterized by 

relatively low capital costs, but higher 

operating costs due to the use of soda 

ash as a reagent. Lime spray drying 

systems, on the other hand, have 

relatively high capital costs, but 

relatively low operating costs due to the 

use of lime as a reagent. As one might 

expect, therefore, when the economics 

of these two FGD systems are 

compared, lime spray drying is less 

expensive for utility steam generating 

units, but sodium scrubbing is less 

expensive for many industrial steam 

generating units. 

Sodium scrubbing is currently the 

most widely used FGD technology for 

reducing S02 emissions from industrialcommercial-institutional steam 

generating units. This is because sodium 

scrubbing is generally less expensive 

than other FGD technologies for many 

industrial-commercial-institutional units. 

Consequently, the sodium scrubbing 

cost algorithm was used prior to 

proposal to generate costs which were 

viewed as representative of the type of 

FGD system that would be most widely 

used to control SO2 emissions from new 

industrial-commercial-institutional 

steam generating units. 

In response to comments concerning 

the use of the sodium scrubbing cost 

algorithm in this manner, however, the 

costs of various types of FGD systems 

were reviewed and compared again. The 

cost of sodium scrubbing was generally 

found to be somewhat lower than the 

cost of other FGD systems, such as dual 

alkali and lime spray drying, as well as 

fluidized bed combustion. From the 

standpoint of overall project economics, 

the total annualized cost of the steam 

generating unit and SO2 control system 

varied by less than 10 percent for all 

technologies examined. However, when 

only the cost associated with S02 

control was considered, this variation 

was much larger, ranging from 30 to 100 

percent. Therefore, because of 

variations in project-specific factors that 

could influence the choice of SO2 control 

system, the use of any single technology 

as a "surrogate" for all types of SO2 

control systems in cost analyses was 

judged to be inappropriate. 

Consequently, "generic" FGD cost 

estimates were developed to represent 

the midpoint in the range of cost 

estimates for several types of industrial 

SO2 control systems (specifically, 

sodium scrubbing, lime spray drying, 

dual alkali, and fluidized bed 

combustion). These generic FGD cost 

estimates were then used to represent 

the cost of FGD systems for industrialcommercial-institutional steam 

generating units. This approach resulted 

in somewhat higher FGD system cost 

estimates than at proposal, but did not 

lead to any significant differences in 

conclusions. 

Two commenters said that both the 

national annualized costs and the 

individual steam generating unit costs 

associated with the standards would be 

much higher. In particular, the 

commenters said, the costs of achieving 

a percent reduction in emissions for 

steam generating units not switching to 

natural gas could be unreasonable. 

As discussed earlier, the national cost 

impacts associated with the final 

standards were reassessed based on 

revised fuel price projections. In 

addition, the cost impacts on typical or 

individual steam generating units were 

also reassessed using these revised fuel 

price projections, assuming no fuel 

switching to natural gas occurred. As 

discussed earlier, several cases were 

identified in which the cost impacts 

associated with application of a percent 

reduction requirement were considered 

unreasonable. Consequently, the final 

standard provides exemptions from the 

percent reduction requirements in these 

cases. With these exemptions, the cost 

impacts associated with the final 

standards are considered reasonable. 

Several commenters expressed 

concern that the capital costs of 

auxiliary fuel systems needed for 

startups, shutdowns, and malfunctions 

were not considered. According to the 

commenters, these costs are significant. 

In many cases, steam generating units 

will be designed and constructed with 

alternative fuel firing capability even in 

the absence of the standards to allow 

greater flexibility in fuel selection and to 

provide for steam generating unit 

startup capability. To that extent, the 

only additional costs for firing 

alternative fuels such as natural gun 

during periods of FGD startup, 

shutdown, or malfunction would be the 

difference in the price between natural 

gas and the primary fuel. However, 

because not all units are designed with 

dual fuel capability, additional capital 

costs associated with switching to firing 

an alternative fuel during periods of 

malfunction were included in the cost 

analyses. For all model steam genernting 

unit sizes analyzed (100,150, 250 and 
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47B3S Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

400 million Btu/hour), the capital cost of 

providing alternative fuel-firing 

capability to a coal-fired steam 

generating unit was about two to three 

percent of the total steam generating 

unit cost. The annualized cost of 

providing alternative fuel firing 

capability was three to four percent of 

the total annualized cost of the steam 

generating unit system. Therefore, the 

additional capital costs of providing 

very low sulfur fuel backup capability 

represent only a small percentage of the 

total steam generating unit costs while 

providing significant benefits in terms of 

additional S02 control. 

F. Performance/Reliability of 

Demonstrated Technologies 

Many commenters said there is 

inadequate proof that there are 

demonstrated S02 control technologies 

which can meet the 90 percent removal 

requirement on a continuous basis for 

industrial-commercial-institutional 

steam generating units. They contended 

that the performance of "demonstrated" 

technologies has been assessed for 

utility steam generating units, which 

have totally different design and 

operation requirements than industrial 

units. Other commenters questioned the 

adequacy of the data base for S02 

control technologies on oil-fired steam 

generating units. 

The performance data for FGD 

systems discussed in the "Summary of 

Regulatory Analysis," "Fossil Fuel-Fired 

Industrial Boilers-Background 

Information," and "S02 Technology 

Update Report" are based on experience 

with industrial steam generating units. 

Moreover, as also discussed, for several 

types of FGD systems this experience is 

supported by experience with utility 

FGD systems. 

Sodium FGD systems are currently the 

most widely used FGD system on 

industrial steam generating units. 

Therefore, the industrial data base for 

this technology is more extensive than 

those for other FGD technologies. Both 

short- and long-term emissions data for 

45 sodium FGD systems located at 18 

different industrial sites show consistent 

S02 removal efficiencies of greater than 

90 percent, and averaged greater than 96 

percent. System reliabilities averaged 

near 98 percent. Most of the industrial 

experience with sodium FGD systems is 

on oil-fired steam generating units used 

in enhanced oil recovery which operate 

at fairly constant load. However, data 

were also gathered from sodium FGD 

systems operating on oil-fired steam 

generating units in other industrial 

applications which have more typical 

load swings. 

Dual alkali FGD systems are also used 

on industrial-commercial-institutional 

steam generating units. Tests of dual 

alkali FGD systems operating on coalfired steam generating units have shown 

short-term SO2 removal efficiencies of 

greater than 90 percent, with long-term 

efficiencies of around 92 percent. 

Although dual alkali FGD systems have 

generally not been applied on oil-fired 

steam generating units, their 

performance should be similar to 

sodium FGD systems. 

Although little long-term data are 

available to demonstrate 90 percent SO2 

removal levels with lime spray drying, 

short-term tests resulting in greater than 

90 percent SO2 removal indicate this 

process is capable of achieving these 

performance levels. Current removal 

rates as low as 70 percent reflect the 

fact that many commercial systems have 

not been required to achieve high 

removal levels, rather than any inherent 

limitation on the technology. 

Lime and limestone FGD systems, 

because of higher capital and 

maintenance costs, have had limited 

application in the industrial sector. 

However, in a long-term test at an 

industrial steam generating unit that 

operated a lime/limestone FGD system, 

the SO2 removal efficiency ranged from 

91 to 94 percent. Removal efficiencies 

were insensitive to changes in steam 

generating unit load. In addition, lime 

and limestone wet FGD systems are 

proven processes in the utility industry. 

Lime and limestone FGD systems 

account for approximately 68 percent of 

existing utility FGD systems. Although 

few, if any, lime or limestone FGD 

systems are expected to be installed on 

industrial-commercial-institutional 

steam generating units due to 

economics, there are no technical 

limitations which would make this 

technology less effective on industrial 

steam generating units than on utility 

steam generating units. 

Performance test data also 

demonstrate that FBC technology is 

capable of achieving 90 percent S02 

removal at high reliabilities. A recent 30-

day test on a bubbling bed FBC unit 

burning high sulfur coal (4000 ng SO2/J, 

9.3 lb/million Btu) showed SO2 removal 

efficiencies averaging 93.5 percent. A 

second 30-day test conducted at a 

different site and combusting a low 

sulfur coal (470 ng S02/J, 1.1 lb/million 

Btu) showed an average SO* removal of 

90 percent with greater than 99 percent 

reliability. During a 67-day period at this 

second site, the FBC unit had a 

reliability of 97 percent. In addition, 

vendors have stated that FBC units can 

be designed to achieve well over 90 

percent S02 removal at high reliability 

levels. 

Consequently, the ability of FGD and 

FBC systems to achieve a 90 percent 

SO2 reduction on industrial steam 

generating units is well demonstrated. In 

addition, experience gained by utilities 

operating similar FGD systems serves to 

confirm the ability of these technologies 

to achieve 90 percent SO2 reduction at 

high reliability levels. 

Commenters also questioned the 

adequacy of the data base for SO2 

control technologies on steam 

generating units operated under 

conditions of load swings. According to 

the commenters, the variable operating 

modes and high capacity load swings 

typical of industrial operations can 

cause severe upsets in FGD efficiency 

and reliability. 

The FGD system performance data 

base is primarily composed of data 

collected from industrial steam 

generating unit installations. These 

steam generating units were located at 

plants representative of the industrialcommercial-institutional steam 

generating unit population, including 

steam generating units operated under 

many different conditions. Steam 

generating units with average capacity 

utilization factors ranging from 5 to 100 

percent were included in the data base. 

In addition, steam generating unit loads 

were varied during tests of individual 

units to simulate load swings that might 

be experienced in some industrial 

applications. Based on these data, S02 

removal efficiency was found to be 

insensitive to changes in steam 

generating unit load over the ranges 

observed. 

The primary concern for FGD systems 

operating on steam generating units 

which experience load swings is a 

sudden increase in the S02 loading. This 

can result from an increase in either the 

flue gas flow rate or the flue gas S02 

concentration. As discussed in the "S02 

Technology Update Report," changes in 

flue gas flow rate are matched by 

corresponding changes in the scrubbing 

solution flow rate according to a set 

liquid-to-gas (L/G) ratio. In a well 

designed and operated system, a safety 

margin is maintained in the L/G ratio to 

account for delays in control loop 

response; thus, an increase in flue gas 

flow rate would be adequately handled. 

Also, FGD systems which experience 

highly variable SO2 loadings typically 

operate at high alkaline reagent 

concentrations. This provides a 

buffering capacity against large swings 

in solution pH caused by dramatic 

changes in SO2 concentration. As a 

result, sufficient excess alkaline reagent 
P.14 

Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

is present to ensure adequate S02 

removal performance during load 

swings. 

A number of commenters questioned 

the reliability of FGD systems, 

expressing concern that these systems 

cannot meet the high operational 

availability demanded by many 

industrial operations. Others said that 

utility FGD reliability experience cannot 

be extrapolated to industrial 

applications because most utilities 

install spare scrubbers to maintain high 

reliabilities and do not experience the 

radical load fluctuations typical of 

industrial operations. 

The reliability of various types of FGD 

systems for industrial applications was 

discussed in the "Background 

Information Document," the "Summary 

of Regulatory Analysis," and the "SO2 

Technology Update Report." As with the 

data on performance of S02 control 

systems, reliability data were gathered 

from a variety of industrial applications, 

with data from utility steam generating 

units used to supplement the industrial 

data. 

Reliability data were reported for over 

250 sodium FGD systems operating on 

industrial-commercial-institutional 

steam generating units firing coal and 

oil. Average long-term reliability levels 

for these units of 98-100 percent were 

reported for periods of time ranging from 

several months to several years. SCv 

removals during these periods averaged 

in excess of 90 percent. 

Reliability and availability data were 

reported for seven dual alkali systems. 

One dual alkali system operating on an 

industrial coal-fired steam generating 

unit reported an availability of over 97 

percent for a 12-month period. Other 

dual alkali systems operating on both 

industrial and utility steam generating 

units reported reliability and availability 

levels of 94 to 99 percent over similar 

lengths of time. 

For lime spray drying systems, 

reliability levels ranging from 70 to 97 

percent were reported for various sites 

surveyed. An examination of the 

reasons for the wide range in reported 

reliability levels indicated that the low 

reliability levels could have been 

improved or prevented with better 

operating and maintenance procedures. 

Although lime spray dryers today are 

typically operated at moderate 

performance levels, there is no reason to 

believe lime spray dryers cannot 

maintain high reliabilities achieving 90 

percent SG^ removal. In fact, one vendor 

of lime spray dryers is prepared to 

guarantee 95 percent reliability provided 

the operator follows a preventive 

maintenance program. This claimed 

reliability level is consistent with the 

two years of commercial operating data 

obtained from a 132 MW (450 million 

Btu/hour) coal-fired steam generating 

unit equipped with a lime spray dryer 

FGD that achieved in excess of 98 

percent reliability. 

As stated above, lime/limestone FGD 

systems have had limited application in 

the industrial sector. Therefore, most of 

the data on lime/limestone FGD system 

reliability are from utility steam 

generating units. However, during a 

long-term (85-day) performance test of a 

lime/limestone FGD system on an 

industrial steam generating unit, FGD 

system reliability was greater than 90 

percent. Data from a utility lime/ 

limestone FGD system firing coal 

indicate reliabilities close to 100 percent 

over a period of several years. 

The above discussion indicates, 

therefore, that with proper operation 

and maintenance, high reliabilities can 

be achieved and maintained on 

industrial-commercial-institutional FGD 

and FBC systems operating at high S02 

removal levels. To allow continued 

steam generating unit operation during 

periods of FGD system malfunction, 

backup FGD modules, common in the 

electric utility sector, can be installed or 

the unit can fire very low sulfur fuels, 

such as natural gas or very low sulfur 

oil. 

One commenter said that an average 

90 percent reduction using an FGD 

system is feasible only when a steam 

generating unit is using a high sulfur 

fuel, and that it is less feasible when a 

low sulfur fuel is used because of the 

lower concentration of S02 in the flue 

gas. 

The ability of an FGD system to 

achieve high SO2 removal efficiencies 

during combustion of low sulfur fuels is 

determined by the concentration of SCh 

in the flue gas exiting the FGD system. 

Test data from sodium and lime spray 

drying FGD systems and from FBC 

systems indicate SO2 emissions of less 

than 15 ppm (equal to roughly 13 ng/J or 

0.03 lb/million Btu) are achievable; in 

some tests, SO2 levels of less than 5 ppm 

(4.3 ng/J [0.01 lb/million Btu]) were 

measured. This indicates that 90 percent 

removal is achievable with flue gases 

having uncontrolled emission rates as 

low as 130 ng/J (0.3 lb S02/million Btu). 

These performance levels measured in 

operating FGD systems are supported by 

kinetic data from laboratory studies and 

by FGD vendor claims. Consequently, 

the ability to achieve a 90 percent 

reduction when firing low sulfur fuels is 

considered well demonstrated. 

G. Secondary Environmental Impacts 

Several commenters said the impacts 

of standards "based" on the use of 

sodium FGD systems were not 

evaluated in relation to other 

regulations, especially State and local 

water quality regulations. They said the 

effluent produced by sodium FGD 

systems could cause wastewater 

disposal problems in some areas. 

The limits imposed by existing 

regulation on the disposal of wastewater 

streams from sodium FGD systems were 

examined by reviewing current disposal 

practices for these types of wastes. 

Wastewater streams from sodium FGD 

systems are not considered hazardous 

wastes, even under the most stringent 

State or local regulations. In the West, 

disposal of these types of wastes is 

generally by deep well injection, above 

ground evaporation, or percolation 

ponds. In the East, disposal of these 

types of wastes is generally by direct 

discharge to a receiving water body or 

indirect discharge through a publicly 

owned treatment work (POTW). These 

streams are often treated prior to 

discharge to comply with the terms of 

applicable permits, State or local 

effluent limitations, water quality 

standards, or POTW pretreatment 

standards or limitations. Thus, while 

treatment may be necessary in some 

cases, these types of wastewater 

streams are currently being disposed of 

by several methods in compliance with 

Federal, State, and local regulations. 

The cost algorithm for sodium FGD 

systems included costs for oxidation in 

order to reflect some form of treatment 

prior to disposal. In some cases, 

however, even with treatment of the 

wastewater streams, some forms of 

disposal, such as direct or indirect 

discharge, may not be permitted. This 

could happen in areas of high industrial 

usage where maximum pollutant 

loadings for the receiving water body 01 

POTW has been reached. In addition, it 

is also possible in some cases that 

disposal by deep well injection, 

evaporation ponds, or landfill containers 

may not be permitted. This could 

happen in areas where concerns about 

possible contamination of underground 

aquifers effectively prohibit disposal of 

any liquid wastes by such means. 

For this reason, as well as other 

reasons, the standards are not "based" 

on the use of sodium FGD systems 

alone, nor for that matter do the 

standards require the use of any 

particular FGD system or SO2 control 

technology. Rather, the standards reflect 

the level of control that is achievable 

through the use of any one of several 

technologies, including sodium FGD, 

dual alkali FGD, lime/limestone FGD, 

lime spray drying FGD, and FBC. In 

addition, where an individual 
P.15 

47838 Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

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confronted with the standard may view 

the "burden" of using these control 

technologies as excessive, "fuel 

switching" can be employed. In this 

manner, the necessity of using these S02 

control technologies can be avoided. 

As discussed throughout the 

"Background Information Document," 

the "S02 Control Technology Update 

Report," and the "Summary of 

Regulatory Analysis," the environmental 

(i.e., air, water, and solid waste), energy, 

cost, and economic impacts associated 

with use of all of the above mentioned 

S02 control technologies, as well as 

those associated with fuel switching, 

were reviewed and are considered 

reasonable. Consequently, in areas 

where disposal of wastewater streams 

from sodium FGD systems, or for that 

matter wastewater streams from any 

"wet" FGD system, is found to be very 

costly or essentially prohibited by local 

regulation, steam generating units would 

be expected to select an alternative 

approach to complying with the 

standards. Such alternatives could range 

from the use of "dry" SO2 control 

systems (i.e., lime spray drying or FBC) 

to firing natural gas. 

Other commenters expressed concern 

about ths availability of adequate 

landfill capacity to dispose of FGD 

system waste. One added that State and 

local solid waste disposal regulations 

are forcing the closure of many existing 

landfills, making the siting of proximal 

landfills difficult and driving up disposal 

costs. Another said that, according to 

the proposal, the use of FGD systems 

could generate up to 15 times as much 

waste as the use of low sulfur coal, and 

there is no evidence in the record of 

landfill capacity sufficient to handle this 

large increase in waste. 

Steam generating units do not 

generally operate as independent 

entities, but are most often part of an 

industrial plant which produces other 

wastes requiring disposal. In addition, 

coal-fired steam generating units 

generate fly ash which also requires 

disposal. Thus, use of an FGD system to 

control SO2 emissions generally does 

not create a new problem (i.e., a need to 

dispose of wastes where no such need 

existed before). 

As discussed in the "Summary of 

Regulatory Analysis," the quantity of 

solid waste generated by FGD 

technologies depends on the sulfur 

content of the fuel. In general, however, 

FGD technologies double to triple the 

quantity of solid waste generated 

compared to existing standards, rather 

than a fifteen-fold increase as suggested 

by the commenters. For example, a 

typical 44 MW (150 million Btu/hour] 

steam generating unit firing low sulfur 

coal without FGD generates about 3,200 

Mg/year (3,500 tons/year) of solid waste 

(mainly steam generating unit 

blowdown and ash from PM control). 

The use of a dual alkali or lime spray 

drying FGD system to achieve 90 

percent reduction in SO2 emissions from 

the same steam generating unit firing the 

same low sulfur coal would generate an 

additional 1,200-2,100 Mg/year (1,300-

2,300 tons/year) of solid waste in the 

form of FGD sludge. If a high sulfur coal 

were fired in this unit, the quantity of 

solid waste generated would increase 

by 6,600-6,800 Mg/year (7,300-7,500 

tons/year). 

In most cases, disposal of wastes 

generated by FGD systems presents no 

more of a problem than disposal of plant 

wastes or steam generating unit fly ash. 

As a result, FGD system wastes may 

generally be disposed of by the same 

means as these wastes. In fact, since the 

wastes from some industrial plants are 

considered toxic or hazardous and FGD 

system wastes are not, disposal of 

wastes from FGD systems may present 

less of a problem than disposal of other 

plant wastes. 

Consequently, in those specific 

locations where landfill capacity may be 

limited, disposal of other plant wastes is 

likely to present as many problems— 

and in some cases more problems—as 

disposal of wastes from FGD systems. 

For individual plants, such constraints 

may necessitate substantial changes to 

the manufacturing process in order to 

minimize the wastes generated or to 

alter their characteristics. For the steam 

generating unit and S02 control system, 

this may necessitate selection of one 

type of control system over another (i.e., 

a "dry" system over a "wet" system, for 

example) or selection of an alternative 

fuel that generates little or no waste 

products. 

H. Emission Credits 

A number of commenters felt that 

emission credits should be granted for 

steam generating units firing waste 

materials, saying that the 

environmentally beneficial and cost 

effective use of waste fuels should be 

encouraged. Other commenters said the 

standard should credit the heat input 

from natural gas fired in combination 

with coal or oil when calculating SO2 

emission rates rather than requiring coal 

or oil to meet their respective emission 

limits without dilution credits. 

Emission credits would allow a plant 

operator firing a sulfur-free fuel such as 

wood or natural gas in conjunction with 

coal or oil to emit SO2 at the same 

overall rate as a steam generating unit 

firing only coal or oil. Stated another 

way, a steam generating unit firing a 50/ 

50 mixture of coal and wood, or coal and 

natural gas, could have twice the SO2 

emissions with an emission credit as it 

could without an emission credit. As a 

result, emission credits deprive the 

public of the air quality benefits, in 

terms of reduced S02 emissions, 

associated with the combustion of 

nonsulfur-bearing fuels. 

The effects of encouraging waste fuel 

use through emission credits were 

thoroughly examined and discussed in 

"Summary of Regulatory Analysis," "An 

Analysis of the Costs and Cost 

Effectiveness of S02 Control for Mixed 

Fuel-Fired Steam Generating Units," and 

"Impacts of New Fuel Prices on S02 

Emission Credits for Cogeneration 

Systems and Mixed Fuel-Fired Steam 

Generating Units." These analyses show 

that granting emission credits for mixedfuel-fired steam generating units results 

in very small reductions in costs while 

allowing significant increases in S02 

emissions. As a result, the incremental 

cost effectiveness of the additional 

reduction in SO2 emissions achieved by 

not providing emission credits is low, 

generally in the range of $220-330/Mg 

($200-300/ton). These costs are 

considered reasonable. Consequently, 

the standards do not include emission 

credits for mixed-fuel-fired steam 

generating units firing waste fuels or 

natural gas in combination with coal or 

oil. 

Firing waste fuels is economically 

attractive in'many cases and results in 

reduced fuel costs for the plant operator. 

The absence of provisions for emission 

credits should not discourage the use of 

these wastes as steam generating unit 

fuels. In many cases, the disposal of 

such wastes in this manner would 

represent the most cost effective method 

of disposal regardless of the NSPS. In 

addition, the final standards include an 

exemption from the percent reduction 

requirement for steam generating units 

obtaining 30 percent or less of their 

rated annual heat input capacity from 

coal or oil. This provides substantial 

incentive to use wastes in order to 

reduce the amount of oil or coal burned 

in the steam generating unit. 

Other commenters stated that 

emission credits should be allowed for 

cogeneration systems in recognition of 

the increased efficiency achieved by 

these systems over separate systems for 

steam and power generation. 

Emission credits for cogeneration 

systems were also thoroughly examined 

and discussed in the "Summary of 

Regulatory Analysis," "An Analysis of 

the Costs and Cost Effectiveness of 

Allowing SO2 Emission Credits for 

Cogeneration Systems," and "Impact of 
P. 16 

:er / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations £7033 

New Fuel Prices on SOs Emission 

Credits for Cogeneration Systems and 

Mixed Fuel-Fired Steam Generating 

Units " As with mixed-fuel-fired steam 

generating units, these analyses 

concluded that granting an emission 

credit for cogeneration steam generating 

units results in very small reductions in 

costs while allowing significant 

increases in SO-t emissions. Therefore, 

the incremental cost effectiveness of the 

additional reductions in emissions 

achieved by not providing emission 

credits for cogeneration steam 

generating units is low,, generally in the 

range of $220-6S0/Mg ($200-600/ton). 

These costs are considered reasonable. 

Strong economic incentives exist for 

use of cogeneration. The absence of 

emission credits for cogenerationsystems will not significantly offset 

these incentives. Consequently, the final 

standards do not include provisions for 

emission credits for cogeneration 

systems. 

Some commenters stated that 

imposing a percentage reduction 

requirement on cogeneration steam 

generating units could severely affect 

the economics of cogeneration projects. 

According to the commenters, impacts 

on cogeneration systems would be more 

severe than on other industrial sectors 

because the increased costs cannot be 

"passed through" to the consumer. 

The final standards will increase the 

cost of coal- and oil-fired cogeneration 

steam generating units. This could 

preclude some smaller, less profitable 

cogeneration projects. However, most 

coal- and oil-fired cogeneration steam 

generating units covered by the 

standards will not be severely affected. 

A cost analysis of the impact of 

standards on a typical coal-fired 

cogeneration steam generating unit 

showed that a percent reduction 

requirement increased total annualized 

costs by about 11 percent. The "Survey 

of New Industrial Boiler Projects" 

indicates that more than 80 percent of 

the cogeneration projects completed in 

1981 through 1984 would have gone 

forward as designed even if cost's 

increased by IQ percent^ and more than 

60 percent of the cogeneration projects 

would have gone forward as designed if 

costs increased by 20 percent. 

In addition, many cogeneration 

projects will not be subject to final SO2 

standards at all. Given current fuel price 

projections,, many new cogeneration. 

projects are- expected to be based on 

firing natural gas (in both gas turbine 

cogeneration systems; and steam turbine 

cogeneration systems) or firing 

municipal solid waste Cogeneration. 

projects firing these fuels1 are not 

affected by the final standards.. 

Finally, new coal-fired cogeneration 

steam generating units compete with 

new coal-fired electric utility steam 

generating units that are subject to 

percent reduction requirements under 

Subpart Da. Thus, application of percent 

reduction to coal-fired cogeneration 

steam generating units under Subpart • 

Db could bs viewed as a "neutral" 

position which treats both utility steam 

generating units and industrialcommercial-institutional cogeneration 

steam generating units in a similar 

manner. Consequently, the final 

standards treat coal-fired cogeneration 

steam generating units just like any 

other coal-fired steam generating unit. 

/. Emerging Technologies 

Several commenters said that, 

because emerging technologies have not 

been "adequately demonstrated" as 

required by the Clean Air Act, a 

standard for emerging technologies 

cannot be established under section 111. 

Others expressed concern that 

establishing standards for emerging 

technologies could inhibit development 

and commercial demonstration of these 

technologies. Still other commenters 

stated that new or emerging 

technologies should be required to 

achieve the same performance levels 

that existing technologies are capable of 

achieving and that the standards should 

not include any special provisions for 

new or emerging technologies. 

NSPS should be set so as to avoid 

unreasonable costs or other impacts; 

Essex Chemical Corp. v.. Ruckelshaus, 

486 F. 2d 42 (D. C. Cir. 1973). Standards 

requiring a high level of performance, 

such as 90 percent reduction, without a 

provision for emerging technologies, 

might discourage continued 

development of some new technologies. 

Owners and operators of new steam 

generating units could simply view the 

risks of using a new and untried 

emission control technology to achieve a 

SO percent reduction in emissions as too 

great. Thus, to encourage the continued 

development of emission control 

technologies that show promise of 

achieving levels of performance 

comparable to those of existing 

technologies, but at lower cost or with 

other offsetting environmental or energy 

benefits, special provisions are needed 

which encourage the development and 

use of new technologies, while ensuring 

that SO2 emissions will be minimized. 

The final standard requiring a 50 

percent reduction in S02 emissions 

while limiting emissions to 170 and 260 

ng/J [0A and 0.0 lb/million Btu) heat 

input for oil and coal, respectively, 

appears to achieve this objective. The 

minimum percent reduction requirement 

of 50 percent should effectively 

eliminate the risk of failure for any 

technology which has the potential to 

achieve higher performance levels and, 

when combined with emission limits of 

170 and 230 ng/J (0.4 and 0.6 lb/million 

Btu), minimize S02 emissions by limiting 

allowable emission rates to less than 

half the level that would result from the 

use of low sulfur fuel. The emission 

limits also encourage improvements in 

these technologies by requiring greater 

SO2 reductions when firing higher sulfur 

fuels. For example, a technology may be 

initially tested at 50 percent SOa 

reduction on a steam generating unit 

firing low sulfur coal (less than 520 ng/J, 

1.2 lb/million Btu), and then, based on 

the information gathered from these 

tests, improved to achieve increased 

percent reductions on higher sulfur coals 

in order to comply with the emission 

limit. For example, the 260 ng/J (0.6 lb/ 

million Btu) emission limit for coal-fired 

units applying emerging technology will 

require units firing an 860 ng/J (2.0 lb/ 

million Btu) coal to achieve 70 percent 

SO2 reduction and units firing a 1700 ng/ 

J (4.0 lb/million Btu] coal to achieve an 

85 percent SO2 reduction. Thus, the 

emerging technology provisions with 

both a 50 percent reduction requirement 

and emission limits of 170 and 280 ng/J 

(0.4 and 0.6 lb/million Btu) for oil and 

coal will encourage technology 

demonstrations while minimizing SOa 

emissions. 

Several commenters said 

disallowance of credit for 

precombustion cleaning of fuel toward 

the percent reduction requirement for 

emerging technologies is inappropriate 

and counter to the philosophy of 

preferring the cleanup of fuels prior to 

combustion, rather than postcombustion cleanup. 

While the allowance of fuel 

pretreatment credits toward the 80 

percent reduction roquiremen. io 

considered appropriate and is allowed 

in the final standards, allowing fuel 

pretreatment credits for emerging 

technologies is ill-suited to tho purpose 

of the emerging technology provisions. 

The primary objective 0? the emerging 

technology provisions io to otimulcto 

and encourage the development end use 

of emerging SOa control technologies 

which show promise 0? achieving 

significant emission reductions in the 

future. Fuel pretreatment credits are 

unwarranted for ths intended purpose of 

demonstration of emerging technologies. 

The final standard, therefore, does not 

allow fuel pretreatment to be applied as 

credit against the percent reduction 

requirement for emerging technologies. 

However, the final standard has been 
47840 Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

amended to allow consideration of fuel 

pretreatment as an emerging technology 

if all of the required 50 percent 

reduction and the 170 and 260 ng/J (0.4 

and 0.6 lb/million Btu) emission limit is 

achieved by the fuel pretreatment 

technology. This will serve to encourage 

the development of fuel pretreatment 

technologies that show promise of 

achieving significant SO2 reductions. 

One commenter suggested that the 

Agency should consider how it plans to 

limit the emerging technology provision 

to: (1) New technologies or processes 

which are unique relative to 

demonstrated technologies rather than 

simply modified versions of currently 

demonstrated technologies, and (2) 

those which are likely to be able to meet 

90 percent removal after a reasonable 

demonstration and development time. 

As in the proposed standards, the 

final standards include definitions of 

conventional technologies. In some 

cases, these definitions have been 

revised in response to the commenter's 

concerns. Technologies considered as 

nothing more than modified versions of 

existing demonstrated technologies will 

not be viewed as emerging technologies 

and will not be approved for installation 

or operation. Current examples of 

emerging technologies include injection 

of dry sorbents into the furnace of a 

steam generating unit (a.k.a., LIMB) and 

the use of electrons to enhance SO2 or 

NOx reactivity (E-beam). The definition 

of conventional "dry flue gas 

desulfurization technology" in the 

regulation has been revised to make it 

clear that it only includes processes that 

inject an alkaline slurry into the flue gas. 

It does not include processes that inject 

dry sorbent. The Agency recognizes that 

demonstration of an emerging 

technology may require installation and 

testing at several different steam 

generating units before it is considered 

demonstrated and intends to allow 

several installations of an emerging 

technology. 

The emerging technology provisions 

will be reviewed regularly during the 

course of the review process associated 

with all NSPS. As a result of these 

reviews, emerging control technologies 

that have been demonstrated will be 

reclassified as conventional 

technologies and would be subjected to 

the same requirements as other 

conventional control technologies. 

As with all NSPS, steam generating 

units subject to the final standards must 

notify the Agency within 30 days of the 

date of commencement of construction 

of the affected facility. If the owner or 

operator of the steam generating unit 

plans to use an emerging technology, 

and thereby operate under a 50 percent 

reduction requirement, a full and 

complete description of this technology 

must be submitted to the Agency along 

with a discussion of how or why this 

technology does not meet any of the 

definitions of conventional technologies. 

Technologies not considered emerging 

by the Agency will be treated as 

conventional technologies, and the 

steam generating unit owner or operator 

will be so notified. To ensure consistent 

application of the special provisions for 

emerging technologies, these provisions 

will not be delegated to the States and 

will remain with the Agency. 

In summary, a 50 percent reduction 

requirement and a 260 ng/J (0.6 lb/ 

million Btu) emission limit are 

applicable to emerging technologies 

applied to coal-fired steam generating 

units. A 50 percent reduction 

requirement and a 170 hg/J (0.4 lb/ 

million Btu) emission limit are 

applicable to emerging technologies 

applied to oil-fired steam generating 

units. As specified in the final 

standards, emerging technologies are 

those that are not conventional 

techniques; and approval must be 

obtained from the Agency for 

application of an emerging technology. 

Review of emerging technology 

applications will be made only by the 

Agency and this authority will not be 

delegated. The Agency will not approve 

for emerging technology application (1) 

control technologies that are in fact only 

a minor variation of a conventional 

technology, or (2) technologies that do 

not promise at least a 50 percent SO2 

removal potential and an emission rate 

less than 260 ng/J or 170 ng/J (0.4 or 0.6 

lb/million Btu) for coal and oil, 

respectively. 

VI. Administrative 

A. Outline of Additions to Subpart Db 

Subpart Db, as published in today's 

Federal Register, includes both the 

provisions for NO, and PM promulgated 

on November 25,1986 (51 FR 42768) and . 

the provisions for SO2 and PM from oilfired steam generating units 

promulgated today. The following list is 

provided as an aid to the reader in 

identifying the sections of Subpart Db 

that are being added or substantively 

revised by today's action. 

Section 60.40b: Revised paragraphs (b) and 

. (c), added paragraph (g). 

Section 60.41b: Revised and added new 

definitions. 

Section 60.42b: Added entire section. 

Section 60.43b: Added paragraph (b). 

Section 60.44b: No substantive changes. 

Section 60.45b: Added entire section. 

Section 60.46b: No substantive changes. 

Section 60.47b: Added entire section. 

Section 60.48b: No substantive changes. 

Section 60.49b: Revised paragraph (b), added 

paragraphs (a)(3). (a)(4). (j). (k). (I), (m). 

and (n). 

B. Revision of Method 19 ' 

Today's action also promulgates 

revisions to Method 19 of 40 CFR Part 

60, Appendix A. These revisions include 

updating, reorganizing, and combining 

the existing Method 19 and the proposed 

Method 19A into the new Method 19. At 

the time of proposal of standards of 

performance for S02 on June 19,1986 (51 

FR 22384), Method 19 was applicable to 

determining S02 emissions and percent 

reduction for FGD-equipped steam 

generating units, and the proposed 

Method 19A was applicable to 

determining S02 emissions from steam 

generating units firing low sulfur content 

fuels without FGD controls. Method 19A 

included three alternatives for 

measuring SO2 emissions: Continuous 

emissions monitoring systems (CEMS), 

Method 6B (stack testing), and fuel 

sampling and analysis procedures. 

Method 19 was originally adopted in 

1979 as a method for determining 

compliance with the S02 emission limits 

and percent reduction requirements for 

electric utility steam generating units 

subject to 40 CFR Part 60, Subpart Da. 

Method 19A was proposed in 1983, but 

has not been promulgated. 

The final S02 standards reference 

only the revised Method 19. Method 19 

is now applicable to: (1) SO*., NOx. and 

PM emission calculations, (2) S02 

percent reduction calculations for postcombustion control, (3) S02 percent 

reduction calculations for fuel 

pretreatment, and (4) fuel sampling and 

analysis procedures for compliance fuelfired steam generating units. 

Additionally, Method 19 has been 

updated to incorporate new American 

Society of Testing and Materials 

(ASTM) procedures for analyzing the 

sulfur content in petroleum products 

(ASTM Method D1552-83) and in coal 

and coke (ASTM Method D4239-85). 

Additional information on Method 19 is 

available in Docket A-81-15. 

C. Relationship of Subpart Db to 

Operational Guidance and Plans to 

Develop Standards for Municipal Waste 

Combustors 

Today's action completes the 

rulemaking for Subpart Db. As such. 

Subpart Db now limits emissions of 

particulate matter, nitrogen oxides, and 

sulfur dioxide from the combustion of 

coal, oil, natural gas, wood, municipal 

solid waste, and mixtures of these fuels 

with other fuels in new, modified, or 

reconstructed industrial-commercialinstitutional steam generating units. 
P.18 

Federal Register / Vol. 52, No, 241 / Wednesday, December 16, 1987 / Rules and Regulations GTMl 

Subpart Db includes standards 

limiting emissions, of particulate matter 

from the combustion of municipal solid 

waste. In addition, Subpart Db includes 

standards limiting emissions of nitrogen 

oxides, if the steam generating unit 

combusts coal, oil, or natural gas with 

municipal solid waste. Similarly, 

Subpart Db includes standards limiting 

emissions of sulfur dioxide, if the steam 

generating unit combusts coal or oil with 

municipal solid waste. 

In response to concerns regarding 

emissions from the combustion of 

municipal solid waste which are beyond 

those considered during the 

development of Subpart Db, the Agency 

issued operational guidance to States 

and Regional offices on June 26,1987 

regarding control technology applicable 

to municipal waste combustors. This 

guidance is for use in all ongoing 

prevention of.significant deterioration 

(PSD) and nonattainment new source 

review (NSR) proceedings, as well as to 

all new permit applications. 

Although Subpart Db limits emissions 

from combustion of municipal solid 

waste, Subpart Db should not be viewed 

as superseding the June 26,1987, 

operational guidance on control 

technology for municipal solid waste 

combustors. This guidance will continue 

to be used by the Agency as the 

reference point in its oversight of all 

PSD and nonattainment NSR 

proceedings, as well as all new permit 

applications for municipal waste 

combustors. 

The Agency also has announced its 

intention to develop new source 

performance standards limiting 

emissions from new, modified, or 

reconstructed municipal waste 

combustors under section 111 of the 

Clean Air Act (52 FR 25389). Depending 

on the nature of the final standards, they 

may supersede or complement those 

under Subpart Db. The Agency also 

intends to develop standards limiting 

emissions of one or more designated 

pollutants (pollutants not regulated 

under sections 108 to 110 or 112) in 

addition to developing standards 

limiting emissions of criteria pollutants 

under section 111. This will invoke 

section 111(d) and require the Agency to 

issue guidance for control of emissions 

from existing municipal waste 

combustors which, in turn, will require 

States to develop specific emission 

standards for existing municipal waste 

combustors. 

D. Docket 

The docket is an organized and 

complete file of all the information 

considered in the development of this . 

rulemaking. The docket is a dynamic 

file, since material is added throughout 

the rulemaking process. The docketing 

system is intended to allow members of 

the public and affected industries to 

identify and locate documents readily so 

they can participate effectively in the 

rulemaking process. The statements of 

basis and purpose of the proposed and 

promulgated standards, the responses to 

significant comments, and the other 

contents of the docket (except for 

interagency review materials) will serve 

as the record in case of judicial review 

(section 307(d)(7)(A)). 

E. Clean Air Act Procedural 

Requirements 

The effective date of this regulation is 

December 16,1987. Section 111 of ths 

Clean Air Act provides that standards of 

performance or revisions thereof 

become effective on promulgation and 

apply to affected facilities for which 

construction, modification, or 

reconstruction was commenced after the 

date of proposal (51 FR 22384, June 19, 

1986). 

As prescribed by section 111, the 

promulgation of these standards is 

based on the Administrator's 

determination that industrialcommercial-institutional steam 

generating units contribute significantly 

to air pollution that may reasonably be 

anticipated to endanger public health or 

welfare. In accordance with section 117 

of the Act, publication of these 

promulgated standards was preceded by 

consultation with appropriate advisory 

committees, independent experts, and 

Federal departments and agencies. 

This regulation will be reviewed not 

later than 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. 

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 this 

regulation and for other regulatory 

alternatives. All aspects of the 

assessment were considered in the 

formulation of the standards to ensure 

that cost was carefully considered in 

determining the best demonstrated 

technology. Portions of the economic 

impact assessment are included in the 

background information documents for 

the proposed standards, and additional 

information is included in Docket A-83-

27. 

F. Office of Management andBudyt 

Reviews 

The information collection 

requirements associated with this 

regulation (those included in 40 C7R 

Part 60, Subpart A and Subpart Db) have 

been approved by the Office of 

Management and Budget (OMB) under 

the provisions of the Paperwork 

Reduction Act of 1980, 44 U.S.C. 3301 at 

seq. and have been assigned OMB 

Control Number 2030-0072. 

Under Executive Order 12291, the 

Administrator is required to judge 

whether a regulation is a "major rule" 

and therefore subject to the 

requirements for preparation of a 

Regulatory Impact Analysis (RiA). At 

the time of proposal, it was expected 

that this regulation could result in 

industry-wide annualized coots ia thti 

fifth year after the standard.! go into 

effect of more than the $1C0 million 

cutoff estabhshed as ths first criterion 

for a "major rule" in tiie Order. In 

accordance with the Order, nn RIA WHO 

prepared for this regulation. The RIA 

reviews the benefits, costs, and 

economic impacts associated with the 

regulatory alternatives thut were 

considered. This rule waa cubmiUad tn 

OMB for review under Executive Order 

12291. 

G. Regulatorv Flexibility Act 

Compliance 

The Regulatory Flexibility Act cf lPl'.O 

requires the identification of potentially 

adverse impacts of Federal regutalionr. 

upon small business entities. The Act 

specifically requires the completion of n 

Regulatory Flexibility Analysis in those 

instances where small business impnetn 

are possible. Because these standards 

impose no adverse economic impacts on 

small businesses, a Regulatory 

Flexibility Analysis has not been 

conducted. 

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

605(b), I hereby certify that thin 

regulation will not have a significunt 

economic impact on a substantial 

number of small entities. 

List of Subjects in 40 CFR Part SO 

Air pollution control, 

Intergovernmental relations, Reporting 

and recordkeeping requirements, 

Incorporation by reference, Enduetrialcommercial-institutional steam 

generating units. 

Date: December 1,1987. 

Lee M. Thomas, 

Administrator. 

For the reasons set out in the 

preamble, Title 40, Chapter I of the Coda 
47842 Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules'an d Regulations 

P.19 

of Federal Regulations, is amended as 

set forth below. 

PART 60—STANDARDS OF 

PERFORMANCE FOR NEW 

STATIONARY SOURCES 

1. The authority citation for Part 60 

continues to read as follows: 

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

2. Section 60.17 is amended by 

revising paragraphs (a)(1), (a)(3), (a)(7), 

(a)(8), (a)(9), (a)(10), (a)(24), (a){25), 

(a)(26), (a)(27), (a)(28), and (a)(47); and 

by adding paragraphs (a)(48), (a)(49), 

(a)(50), (a)(51), (a)(52), and (a)(53) to 

read as follows: 

§ 60.17 Incorporation by reference. 

**** * 

(a) * * * 

. (1) ASTM D388-77, Standard 

Specification for Classification of Coals 

by Rank, incorporation by reference 

(IBR) approved January 27,1983, for 

§§ 60.41(f); 60.45(f)(4) (i), (ii), (vi); 60.41a; 

60.41b; 60.251 (b), (c). 

**** * 

(3) ASTM D3176-74, Standard Method 

for Ultimate Analysis of Coal and Coke, 

IBR approved January 27,1983, for 

§ 60.45(f)(5)(i); Appendix A to Part 60, 

Method 19. 

**** * 

(7) ASTM D2015-77, Standard Test 

Method for Gross Calorific Value of 

Solid Fuel by the Adiabatic Bomb 

Calorimeter, IBR approved January 27, 

1983 for § 60.45(f)(5)(h); § 60.46(g); 

Appendix A to Part 60, Method 19. 

(8) ASTM D1826-77, Standard Test 

Method for Calorific Value of Gases in 

Natural Gas Range by Continuous 

Recording Calorimeter, IBR approved 

January 27,1983, for §§ 60.45(f)(5)(ii); 

60.46(g); 60.296(f); Appendix A to Part 

60, Method 19. 

(9) ASTM D240-76, Standard Test 

Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter, IBR approved January 27, 

1983, for § 60.46(g); 60.296(f); Appendix 

A to Part 60, Method 19. 

(10) ASTM D396-78, Standard 

Specification for Fuel Oils, IBR 

approved January 27,1983, for §§ 60.40b; 

60.4lb; 60.111(b); 60.111a(b). 

***-* * 

(24) ASTM D2234-76, Standard 

Methods for Collection of a Gross 

Sample of Coal, IBR approved January 

27,1983, for Appendix A to Part 60, 

Method 19. 

(25) ASTM D3173-73, Standard Test 

Method for Moisture in the Analysis 

Sample of Coal and Coke, IBR approved 

January 27,1983, for Appendix A to Part 

60, Metro i 19. * 

(26) ASTM D3177-75, Standard Test 

Methods for Total Sulfur in the Analysis 

Sample of Coal and Coke, IBR approved 

January 27,1983, for Appendix A to Part 

60, Method 19. 

(27) ASTM D2013-72, Standard 

Method of Preparing Coal Samples for 

Analysis, IBR approved January 27, 

1983, for Appendix A to Part 60, Method 

19. 

(28) ASTM D270-65 (Reapproved 

1975), Standard Method of Sampling 

Petroleum and Petroleum Products, IBR 

approved January 27,1983, for Appendix 

A to Part 60, Method 19. 

* * * * * 

(47) ASTM D3431-80, Standard Test 

Method for Trace Nitrogen in Liquid 

Petroleum Hydrocarbons 

(Microcoulometric Method), IBR 

approved November 25,1986, for 

Appendix A to Part 60, Method 19. 

(48) ASTM D129-64 (reapproved 1978), 

Standard Test Method for Sulfur in 

Petroleum Products (General Bomb 

Method), IBR approved for Appendix A 

to Part 60, Method 19. 

(49) ASTM D1552-83, Standard Test 

Method for Sulfur in Petroleum Products 

(High Temperature Method), IBR 

approved for Appendix A to Part 60, 

Method 19. 

(50) ASTM D1835-86, Standard 

Specification for Liquefied Petroleum 

(LP) Gases, to be approved for.§ 60.41b. 

(51) ASTM D3286-85, Standard Test 

Method for Gross Calorific Value of 

Coal and Coke by the Isothermal-Jacket 

Bomb Calorimeter, IBR approved for 

Appendix A to Part 60, Method 19. 

(52) ASTM D4057-81, Standard 

Practice for Manual Sampling of 

Petroleum and Petroleum Products, IBR 

approved for Appendix A to Part 60, 

Method 19. 

(53) ASTM D4239-85, Standard Test 

Methods for Sulfur in the Analysis 

Sample of Coal and Coke Using High 

Temperature Tube Furnace Combustion 

Methods, IBR approved for Appendix A 

to Part 60, Method 19. 

3. Subpart Db is revised to read as 

follows: 

Subpart Db—Standards of Performance for 

Industrial-Commercial-lnstitutional Steam 

Generating Units 

Sec. 

60.40b Applicability and delegation of 

authority. 

60.41b Definitions. 

60.42b Standard for sulfur dioxide. 

60.43b Standard for particulate matter. 

60.44b Standard for nitrogen oxides. 

60.45b Compliance and performance test 

methods and procedures'for sulfur 

dioxide. 

Sec. 

60.46b Compliance and performance test 

methods and procedures for particulate 

matter and nitrogen oxides. 

60.47b Emission monitoring for sulfur • 

dioxide. 

60.48b Emission monitoring for particulate 

matter and nitrogen oxides. 

60.49b Reporting and recordkeeping 

requirements. 

Subpart Db—Standards of 

Performance for IndustrialCommercial-Institutional Steam 

Generating Units 

§ 60.40b Applicability and delegation of 

authority. 

(a) The affected facility to which this 

subpart applies is each steam generating 

unit that commences construction, 

modification, or reconstruction after 

June 19,1984, and that has a heat input 

capacity from fuels combusted in the 

steam generating unit of greater than 29 

MW (100 million Btu/hour). 

(b) Any affected facility meeting the 

applicability requirements under 

paragraph (a) of this section and 

commencing construction, modification, 

or reconstruction after June 19,1984, but 

on or before June 19,1986, is subject to 

the following standards: 

(1) Coal-fired affected facilities having 

a heat input capacity between 29 and 73 

MW (100 and 250 million Btu/hour), 

inclusive, are subject to the particulate 

matter and nitrogen oxides standards 

under this subpart. 

(2) Coal-fired affected facilities having 

a heat input capacity greater than 73 

MW (250 million Btu/hour) and meeting 

the applicability requirements under 

Subpart D (Standards of performance 

for fossil-fuel-fired steam generators; 

§ 60.40) are subject to the particulate 

matter and nitrogen oxides standards 

under this subpart and to the sulfur 

dioxide standards under Subpart D 

(§ 60.43). 

(3) Oil-fired affected facilities having 

a heat input capacity between 29 and 73 

MW (100 and 250 million Btu/hour), 

inclusive, are subject to the nitrogen 

oxides standards under this subpart. 

(4) Oil-fired affected facilities having 

a heat input capacity greater than 73 

MW (250 million Btu/hour) and meeting 

the applicability requirements under 

Subpart D (Standards of performance 

for fossil-fuel-fired steam generators; 

§ 60.40) are also subject to the nitrogen 

oxides standards under this subpart and 

the particulate matter and sulfur dioxide 

standards under Subpart D (§ 60.42 and 

§ 60.43). • 

(c) Affected facilities which also meet 

the applicability requirements under 

Subpart J (Standards of performance for 
P.20 

Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 47843 

petroleum refineries; § 60.104) are 

subject to the particulate matter and 

nitrogen oxides standards under this 

subpart and the sulfur dioxide standards 

under Subpart J (§ 60.104). 

(d) Affected facilities which also meet 

the applicability requirements under 

Subpart E (Standards of performance for 

incinerators; § 60.50) are subject to the 

nitrogen oxides and particulate matter 

standards under this subpart. 

(e) Steam generating units meeting the 

applicability requirements under 

Subpart Da (Standards of performance 

for electric utility steam generating 

units; § 60.40a) are not subject to this 

subpart. 

(f) Any change to an existing steam 

generating unit for the sole purpose of 

combusting gases containing TRS as 

defined under § 60.281 is not considered 

a modification under § 60.14 and the 

steam generating unit is not subject to 

this subpart. 

(g) In delegating implementation and 

enforcement authority to a State under 

section 111(c) of the Act, the following 

authorities shall be retained by the 

Administrator and not transferred to a 

State. 

(1) Section 60.44b(f). 

(2) Section 60.44b(g). 

(3) Section 60.49b(a)(4). 

§ 60.41b Definitions. 

As used in this subpart, all terms not 

defined herein shall have the meaning 

given them in the Act and in Subpart A 

of this part. 

"Annual capacity factor" means the 

ratio between the actual heat input to a 

steam generating unit from the fuels 

listed in § 60.42b(a), § 60.43b(a), or 

§ 60.44b(a), as applicable, during a 

calendar year and the potential heat 

input to the steam generating unit had it 

been operated for 8,760 hours during a 

calendar year at the maximum steady 

state design heat input capacity. In the 

case of steam generating units that are 

rented or leased, the actual heat input 

shall be determined based on the 

combined heat input from all operations 

of the affected facility in a calendar 

year. 

"Byproduct/waste" means any liquid 

or gaseous substance produced at 

chemical manufacturing plants or 

petroleum refineries (except natural gas, 

distillate oil, or residual oil] and 

combusted in a steam generating unit for 

heat recovery or for disposal. Gaseous 

substances with carbon dioxide levels 

greater than 50 percent or carbon 

monoxide levels greater than 10 percent 

are not byproduct/waste for the 

purposes of this subpart. 

"Chemical manufacturing, plants" 

means industrial plants which are 

classified by the Department of 

Commerce under Standard Industrial 

Classification (SIC) Code 28. 

"Coal" means all solid fuels classified 

as anthracite, bituminous, 

subbituminous, or lignite by the 

American Society of Testing and 

Materials in ASTM D388-77, Standard 

Specification for Classification of Coals 

by Rank (IBR—see § 60.17), coal refuse, 

and petroleum coke. Coal-derived 

synthetic fuels, including but not limited 

to solvent refined coal, gasified coal, 

coal-oil mixtures, and coal-water 

mixtures, are also included in this 

definition for the purposes of this 

subpart. 

"Coal refuse" means any byproduct of 

coal mining or coal cleaning operations 

with an ash content greater than 50 

percent, by weight, and a heating value 

less than 13,900 kj/kg (6,000 Btu/lb) on a 

dry basis. 

"Combined cycle system" means a 

system in which a separate source, such 

as a gas turbine, internal combustion 

engine, kiln, etc., provides exhaust gas 

to a heat recovery steam generating unit. 

"Conventional technology" means wet 

flue gas desulfurization (FGD) 

technology, dry FGD technology, 

atmospheric fluidized bed combustion 

technology, and oil hydrodesulfurization 

technology. 

"Distillate oil" means fuel oils that 

contain 0.05 weight percent nitrogen or 

less and comply with the specifications 

for fuel oil numbers 1 and 2, as defined 

by the American Society of Testing and 

Materials in ASTM D396-78, Standard 

Specifications for Fuel Oils 

(incorporated by reference—see § 60.17). 

"Dry flue gas desulfurization 

technology" means a sulfur dioxide 

control system that is located 

downstream of the steam generating 

unit and removes sulfur oxides from the 

combustion gases of the steam 

generating unit by contacting the 

combustion gases with an alkaline 

slurry or solution and forming a dry 

powder material. This definition 

includes devices where the dry powder 

material is subsequently converted to 

another form. Alkaline slurries or 

solutions used in dry flue gas 

desulfurization technology include but 

are not limited to lime and sodium. 

"Duct burner" means a device that 

combusts fuel and that is placed in the 

exhaust duct from another source, such 

as a stationary gas turbine, internal 

combustion engine, kiln, etc., to allow 

the firing of additional fuel to heat the 

exhaust gases before the exhaust gases 

enter a heat recovery steam generating 

unit. 

"Emerging technology" means any 

sulfur dioxide control system that is not 

defined as a conventional technology 

under this section, and for which the 

owner or operator of the facility has 

applied to the Administrator and 

received approval to operate as an 

emerging technology under 

§ 60.49b(a)(4). 

"Federally enforceable" means all 

limitations and conditions that are 

enforceable by the Administrator, 

including the requirements of 40 CFR 

Parts 60 and 61, requirements within any 

applicable State Implementation Plan, 

and any permit requirements 

established under 40 CFR 52.21 or under 

40 CFR 51.18 and 40 CFR 51.24. 

"Fluidized bed combustion 

technology" means combustion of fuel in 

a bed or series of beds (including but not 

limited to bubbling bed units and 

circulating bed units) of limestone 

aggregate (or other sorbent materiuls) in 

which these materials are forced 

upward by the flow of combustion air 

and the gaseous products of combustion. 

"Fuel pretreatment" means a process 

that removes a portion of the sulfur in a 

fuel before combustion of the fuel in u 

steam generating unit. 

"Full capacity" means operation of 

the steam generating unit at 90 percent 

or more of the maximum steady-stute 

design heat input capacity. 

"Heat input" means heat derived from 

combustion of fuel in a steam generating 

unit and does not include the heat input 

from preheated combustion air, 

recirculated flue gases, or exhaust gases 

from other sources, such as gas turbines, 

internal combustion engines, kilns, etc. 

"Heat release rate" means the steam 

generating unit design heat input 

capacity (in MW or Btu/hour) divided 

by the furnace volume (in cubic meters 

or cubic feet); the furnace volume is that 

volume bounded by the front furnace 

wall where the burner is located, the 

furnace side waterwall, and extending 

to the level just below or in front of the 

first row of convection pass tubes. 

"Heat transfer medium" means any 

material that is used to transfer heut 

from one point to another point. 

"High heat release rate" means a heat 

release rate greater than 730,000 J/secm

3

 (70,000 Btu/hour-ft3). 

"Lignite" means a type of coal 

classified as lignite A or lignite B by the 

American Society of Testing and 

Materials in ASTM D388-77, Standard 

Specification for Classification of Coals 

by Rank (IBR—see § 60.17). 

"Low heat release rate" means a heut 

release rate of 730,000 J/sec-m3 (70,000 

Btu/hour-ft3) or less. 

"Mass-feed stoker steam generating 

unit" means a steam generating unit 

where solid fuel is introduced directly 
P.21 

47844 Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

into a retort or is fed directly onto a 

grate where it is combusted. 

"Maximum heat input capacity" 

means the ability of a steam generating 

unit to combust a stated maximum 

amount of fuel on a steady state basis, 

as determined by the physical design 

and characteristics of the steam 

generating unit. 

"Municipal-type solid waste" means 

refuse, more than 50 percent of which is 

waste consisting of a mixture of paper, 

wood, yard wastes, food wastes, 

plastics, leather, rubber, and other 

combustible materials, and 

noncombustible materials such as glass 

and rock. 

"Natural gas" means (1) a naturally 

occurring mixture of hydrocarbon and 

nonhydrocarbon gases found in geologic 

formations beneath the earth's surface, 

of which the principal constituent is 

methane; or (2) liquid petroleum gas, as 

defined by the American Society for 

Testing and Materials in ASTM D1835-

82, "Standard Specification for Liquid 

Petroleum Gases" (IBR—see § 60.17). 

"Noncontinental area" means the 

State of Hawaii, the Virgin Islands, 

Guam, American Samoa, the 

Commonwealth of Puerto Rico, or the 

Northern Mariana Islands. 

"Oil" means crude oil or petroleum or 

a liquid fuel derived from crude oil or 

petroleum, including distillate and 

residual oil. 

"Petroleum refinery" means industrial 

plants as classified by the Department 

of Commerce under Standard Industrial 

Classification (SIC) Code 29. 

' "Potential sulfur dioxide emission 

rate" means the theoretical sulfur 

dioxide emissions (ng/J, lb/million Btu 

heat input) that would result from 

combusting fuel in an uncleaned state 

and without using emission control 

systems. 

"Process heater" means a device that 

is primarily used to heat a material to 

initiate or promote a chemical reaction 

in which the material participates as a 

reactant or catalyst. 

"Pulverized coal-fired steam 

generating unit" means a steam 

generating unit in which pulverized coal 

is introduced into an air stream that 

carries the coal to the combustion 

chamber of the steam generating unit 

where it is fired in suspension. This 

includes both conventional pulverized 

coal-fired and micropulverized coalfired steam generating units. 

"Residual oil" means crude oil, fuel oil 

numbers 1 and 2 that have a nitrogen 

content greater than 0.05 weight percent, 

and all fuel oil numbers 4, 5 and 6, as 

defined by the American Society of 

Testing and Materials in ASTM D396-

78, Standard Specifications for Fuel Oils 

(IBR—see § 60.17). 

"Spreader stoker steam generating 

unit" means a steam generating unit in 

which solid fuel is introduced to the 

combustion zone by a mechanism that 

throws the fuel onto a grate from above. 

Combustion takes place both in 

suspension and on the grate. 

"Steam generating unit" means a 

device that combusts any fuel or 

byproduct/waste to produce steam or to 

heat water or any other heat transfer 

medium. This term includes any 

municipal-type solid waste incinerator 

with a heat recovery steam generating 

unit or any steam generating unit that 

combusts fuel and is part of a 

cogeneration system or a combined 

cycle system. This term does not include 

process heaters as they are defined in 

this subpart. 

"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. 

"Very low sulfur oil" means a 

distillate oil or residual oil that when 

combusted without post combustion S02 

control has an SO2 emission rate equal 

to or less than 130 ng/J (0.30 lb SO2/ 

million Btu). 

"Wet flue gas desulfurization 

technology" means a sulfur dioxide 

control system that is located 

downstream of the steam generating 

unit and removes sulfur oxides from the 

combustion gases of the steam 

generating unit by contacting the 

combustion gas with an alkaline slurry 

or solution and forming a liquid 

material. This definition applies to 

devices where the aqueous liquid 

material product of this contact is 

subsequently converted to other forms. 

Alkaline reagents used in wet flue gas 

desulfurization technology include, but 

are not limited to, lime, limestone, and 

sodium. 

"Wet scrubber system" means any 

emission control device that mixes an 

aqueous stream or slurry with the 

exhaust gases from a steam generating 

unit to control emissions of particulate 

matter or sulfur dioxide. 

"Wood" means wood, wood residue, 

bark, or any derivative fuel or residue 

thereof, in any form, including, but not 

limited to, sawdust, sanderdust, wood 

chips, scraps, slabs, millings, shavings, 

and processed pellets made from wood 

or other forest residues. 

§ 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 the performance 

test is completed or required to be 

completed under § 60.8 of this part, 

whichever date comes first, no owner or 

operator of an affected facility that 

combusts coal or oil shall cause to be 

discharged into the atmosphere any 

gases that contain sulfur dioxide in 

excess of 10 percent (0.10) of the 

potential sulfur dioxide emission rate 

(90 percent reduction) and that contain 

sulfur dioxide in excess of the emission 

limit determined according to the 

following formula: 

E,=(KaHa+KbH1))/(Ha+Hb) 

where: 

Es is the sulfur dioxide emission limit, in ng/J 

or lb/million Btu heat input, 

K„ is 520 ng/J (or 1.2 lb/million Btu), 

K„ is 340 ng/J (or 0.80 lb/million Btu), 

H, is the heat input from the combustion of 

coal, in J (million Btu), 

Hb is the heat input from the combustion of 

oil, in J (million Btu). 

Only the heat input supplied to the 

affected facility from the combustion of 

coal and oil is counted under this 

" section. No credit is provided for the 

heat input to the affected facility from 

the combustion of natural gas, wood, 

municipal-type solid waste, or other 

fuels or heat input to the affected facility 

from exhaust gases from another source, 

such as gas turbines, internal . 

combustion engines, kilns, etc. 

(b) On and after the date on which the 

performance test is completed or 

required to be completed under § 60.8 of 

this part, whichever comes first, no 

owner or operator of an affected facility 

that combusts coal refuse alone in a 

fluidized bed combustion steam 

generating unit shall cause to be 

discharged into the atmosphere any 

gases that contain sulfur dioxide in 

excess of 20 percent of the potential 

sulfur dioxide emission rate (80 percent 

reduction) and that contain sulfur 

dioxide in excess of 520 ng/J (1.2 lb/ 

million Btu) heat input. If coal or oil is 

fired with coal refuse, the affected 

facility is subject to paragraph (a) or (d) 

of this section, as applicable. 

(c) On and after the date on which the 

performance test is completed or is 

required to be completed under § 60.8 of 

this part, whichever comes first, 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 sulfur dioxide emissions, shall 

cause to be discharged into the 

atmosphere any gases that contain 

sulfur dioxide in excess of 50 percent of 
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Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

the potential sulfur dioxide emission 

rate (50 percent reduction) and that 

contain sulfur dioxide in excess of the 

emission limit determined according to 

the following formula: 

Es=(K<*Hc-fKdH<*)/Hc + Hd) 

where: 

E, is the sulfur dioxide emission limit, 

expressed in ng/J (lb/million Btu) heat 

input, 

IQ is 260 ng/) (0.60 lb/million Btu), 

Ki is 170 ng/J (0.40 lb/million Btu), 

H. is the heat input from the combustion of 

coal, J (million Btu), 

Ha is the heat input from the combustion of 

oil, J (million Btu). 

Only the heat input supplied to the 

affected facility from the combustion of 

coal and oil is counted under this 

section. No credit is provided for the 

heat input to the affected facility from 

the combustion of natural gas, wood, 

municipal-type solid waste, or other 

fuels, or from the heat input to the 

affected facility from exhaust gases from 

another source, such as gas turbines, 

internal combustion engines, kilns, etc. 

(d) On and after the date on which the 

performance test is completed or 

required to be completed under § 60.8 of 

this part, whichever comes first, no 

owner or operator of an affected facility 

listed in paragraphs (d) (1), (2), (3), or (4) 

of this section shall cause to be 

discharged into the atmosphere any 

gases that contain sulfur dioxide in 

excess of 520 ng/J (1.2 lb/million Btu) 

heat input if the affected facility 

combusts coal, or 130 ng/J (0.30 lb/ 

million Btu) heat input if the affected 

facility combusts oil. Percent reduction 

requirements are not applicable to 

affected facilities under this paragraph: 

(1) Affected facilities that have an 

annual capacity factor for coal and oil of 

30 percent (0.30) or less and are subject 

to a Federally enforceable permit 

limiting the operation of the affected 

facility to an annual capacity factor for 

coal and oil to 30 percent (0.30) or less; 

(2) Affected facilities located in a 

noncontinental area; 

(3) Affected facilities combusting coal 

or oil, alone or in combination with any 

other fuel, in a duct burner as part of a 

combined cycle system where 30 

percent (0.30) or less of the heat input to 

the steam generating unit is from 

combustion of coal and oil in the duct 

burner and 70 percent (0.70) or more of 

the heat input to the steam generating 

unit is from the exhaust gases entering 

the duct burner; or 

(4) Affected facilities combusting very 

low sulfur oil. 

(e) Except as provided in paragraph (f) 

of this section, compliance with the 

emission limit(s) and percent reduction 

requirements under this section are 

determined on a 30-day rolling average 

basis. 

(f) Compliance with the emission 

limits under this section are determined 

on a 24-hour average basis for affected 

facilities which (1) have a Federally 

enforceable permit limiting the annual 

capacity factor for oil to 10 percent or 

less, (2) combust only oil which emits 

less than 130 ng/J (0.3 lb S02/million 

Btu), and (3) do not combust any other 

fuel. 

(g) Except as provided in paragraph (i) 

of this section, the sulfur dioxide 

emission limits and percent reduction 

requirements under this section apply at 

all times, including periods of startup, 

shutdown, and malfunction. 

(h) Reductions in the potential sulfur 

dioxide emission rate through fuel 

pretreatment are not credited toward 

the percent reduction requirement under 

paragraph (c) of this section unless: 

(1) Fuel pretreatment results in a 50 

percent or greater reduction in potential 

sulfur dioxide emissions and 

(2) Emissions from the pretreated fuel 

(without combustion or post combustion 

sulfur dioxide control) are equal to or 

less than the emission limits specified in 

paragraph (c) of this section. 

(i) An affected facility subject to 

paragraph (a), (b), or (c) of this section 

may combust very low sulfur oil or 

natural gas when the sulfur dioxide 

control system is not being operated 

because of malfunction or maintenance 

of the sulfur dioxide control system. 

§ 60.43b Standard for particulate matter. 

(a) On and after the date on which the 

initial performance test is completed or 

is required to be completed under § 60.8 

of this part, whichever comes first, no 

owner or operator of an affected facility 

which combusts coal or combusts 

mixtures of coal with other fuels, shall 

cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain particulate 

matter in excess of the following 

emission limits: 

(1) 22 ng/J (0.05 lb/million Btu) heat 

input, 

(i) If the affected facility combusts 

only coal, or 

(ii) If the affected facility combusts 

coal and other fuels and has an annual 

capacity factor for the other fuels of 10 

percent (0.10) or less. 

(2) 43 ng/J (0.10 lb/million Btu) heat 

input if the affected facility combusts 

coal and other fuels and has an annual 

capacity factor for the other fuels 

greater than 10 percent (0.10) and is 

subject to a Federally enforceable 

requirement limiting operation of the 

affected facility to an annual capacity 

factor greater than 10 percent (0.10) for 

fuels other than coal. 

(3) 86 ng/J (0.20 lb/million Btu) heut 

input if the affected facility combusts 

coal or coal and other fuels and 

(i) Has an annual capacity factor for 

coal or coal and other fuels of 30 percent 

(0.30) or less, 

(ii) Has a maximum heat input 

capacity of 73 MW (250 million Btu/ 

hour) or less, 

(iii) Has a Federally enforceable 

requirement limiting operation of the 

affected facility to an annual cupacity 

factor of 30 percent (0.30) or less for coal 

or coal and other solid fuels, and 

(iv) Construction of the affected 

facility commenced after June 19,1984, 

and before November 25,1986. 

(b) On and after the date on which the 

performance test is completed or 

required to be completed under § 60.8 of 

this part, whichever date comes first, no 

owner or operator of an affected facility 

that combusts oil or that combusls 

mixtures of oil with other fuels shall 

cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain particulate 

matter in excess of 43 ng/J (0.10 lb/ 

million Btu) heat input. 

(c) On and after the date on which the 

initial performance test is completed or 

is required to be completed under § 60.8 

of this part, whichever date comes first, 

no owner or operator of an affected 

facility that combusts wood, or wood 

with other fuels, except coal, shull causo 

to be discharged from that affected 

facility any gases that contain 

particulate matter in excess of the 

following emission limits: 

(1) 43 ng/J (0.10 lb/million Btu] heut 

input if the affected facility has nn 

annual capacity factor greater than 30 

percent (0.30) for wood. 

(2) 86 ng/J (0.20 lb/million Btu) heat 

input if 

(i) The affected facility has an annual 

capacity factor of 30 percent (0.30) or 

less for wood, 

(ii) Is subject to a Federally 

enforceable requirement limiting 

operation ofthe affected facility to un 

annual capacity factor of 30 percent 

(0.30) or less for wood, and 

(iii) Has a maximum heat input 

capacity of 73 MW (250 million Btu/ 

hour) or less. 

(d) On and after the date on which the 

initial performance test is completed or 

is required to be completed under § 60.8 

of this part, whichever date comes first, 

no owner or operator of an affected 

facility that combusts municipal-type 

solid waste or mixtures of municipaltype solid waste with other fuels, shall 

cause to be discharged into the 
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47846 Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

atmosphere from that affected facility 

any gases that contain particulate 

matter in excess of the following 

emission limits: 

(1) 43 ng/J (0.10 lb/million Btu) heat 

input, 

(i) If the affected facility combusts 

only municipal-type solid waste, or 

(ii) If the affected facility combusts 

municipal-type solid waste and other 

fuels and has an annual capacity factor 

for the other fuels of 10 percent (0.10) or 

less. 

(2) 86 ng/J (0.20 lb/million Btu) heat 

input if the affected facility combusts 

municipal-type solid waste or municipaltype solid waste and other fuels; and 

(i) Has an annual capacity factor for 

municipal-type solid waste and other 

fuels of 30 percent (0.30) or less, 

(ii) Has a maximum heat input 

capacity of 73 MW (250 million Btu/ 

hour) or less, 

(iii) Has a Federally enforceable 

requirement limiting operation ofthe 

affected facility to an annual capacity 

factor of 30 percent (0.30) for municipaltype solid waste, or municipal-type solid 

waste and other fuels, and 

(iv) Construction of the affected 

facility commenced after June 19,1984, 

but before November 25,1986. 

(e) For the purposes of this section, 

the annual capacity factor is determined 

by dividing the actual heat input to the 

steam generating unit during the 

calendar year from the combustion of 

coal, wood, or municipal-type solid 

waste, and other fuels, as applicable, by 

the potential heat input to the steam 

generating unit if the steam generating 

unit had been operated for 8,760 hours at 

the maximum design heat input 

capacity. 

(f) On and after the date on which the 

initial performance test is completed or 

is required to be completed under § 60.8 

of this part, whichever date comes first, 

no owner or operator of an affected 

facility subject to the particulate matter 

emission limits under paragraph (a), (b) 

or (c) of this section shall cause to be 

discharged into the atmosphere any 

gases that exhibit greater than 20 

percent opacity (6-minute average), 

except for one 6-minute period per hour 

of not more than 27 percent opacity. 

(g) The particulate matter and opacity 

standards apply at all times, except 

during periods of startup, shutdown or 

malfunction. 

§ 60.44b Standard for nitrogen oxides. 

(a) On and after the date on which the 

initial performance test is completed or 

is required to be completed under § 60.8 

of this part, whichever date comes first, 

no owner or operator of an affected 

facility that is subject to the provisions 

of this section and that combusts only 

coal, oil, or natural gas shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain nitrogen oxides (expressed as 

N02) in excess of the following emission 

limits: 

Fuef/Steam generating unit type 

(1) Natural gas and distillate oil, except (4): 

(2) Residual oil: 

(3) Coal: 

(ii) Spreader stoker and fluidized bed 

(v) Lignite mined in North Dakota, South 

Dakota, or Montana and combusted in 

(4) Duct burner used in a combined cycle 

system: 

Nitrogen oxide 

emission limits 

ng/J (lb/ 

million Btu) 

(expressed as 

NO,) heat 

input 

43 (0.10) 

86 (0.20) 

130 (0.30) 

170 (0.40) 

210 (0.50) 

260 (0.60) 

300 (0.70) 

260 (0.60) 

340 (0.80) 

210 (0.50) 

86 (0.20) 

170 (0.40) 

(b) On and after the date on which the 

initial performance test is completed or 

is required to be completed under § 60.8 

of this part, whichever date comes first, 

no owner or operator of an affected 

facility that simultaneously combusts 

mixtures of coal, oil, or natural gas shall 

cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain nitrogen oxides 

in excess of a limit determined by use of 

the following formula: 

E„=[(EL„0 hU-HELTM Hro) + (ELc Hc)]/ 

(Hg0-fHro-(-Hc) 

where: 

En is the nitrogen oxides emission limit 

(expressed as NO2), ng/J (lb/million Btu) 

EL,„ is the appropriate emission limit from 

paragraph (a)(1) for combustion of ' 

natural gas or distillate oil, ng/) (lb/ 

million Btu) 

Ht0 is the heat input from combustion of 

natural gas or distillate oil, 

ELro is the appropriate emission limit from 

paragraph (a)(2) for combustion of 

residual oil, 

Hro is the heat input from combustion of 

residual oil, 

ELC is the appropriate emission limit from 

paragraph (a)(3) for combustion of coal, 

and 

Hc is the heat input from combustion of coal; 

(c) On and after the date on which the 

initial performance test is completed or 

is required to be completed under § 60.8 

of this part, whichever comes first, no 

owner or operator of an affected facility 

that simultaneously combusts coal or 

oil, or a mixture of these fuels with 

natural gas, and wood, municipal-type 

solid waste, or any other fuel shall 

cause to be discharged into the 

atmosphere any gases that contain 

nitrogen oxides in excess of the 

emission limit for the coal or oil, or 

mixture of these fuels with natural gas 

combusted in the affected facility, as 

determined pursuant to paragraph (a) or 

(b) of this section, unless the affected 

facility has an annual capacity factor for 

cOal or oil, or mixture of these fuels with 

natural gas of 10 percent (0.10) or less 

and is subject to a Federally enforceable 

requirement that limits operation of the 

facility to an annual capacity factor of 

10 percent (0.10) or less for coal, oil, or a 

mixture of these fuels with natural gas. 

(d) On and after the date on which the 

initial performance test is completed or 

is required to be completed under § 60.8 

of this part, whichever date comes first, 

no owner or operator of an affected 

facility that simultaneously combusts 

natural gas with wood, municipal-type 

solid waste, or other solid fuel, except 

coal, shall cause to be discharged into 

the atmosphere from that affected 

facility any gases that contain nitrogen 

oxides in excess of 130 ng/J (0.30 lb/ 

million Btu) heat input unless the 

affected facility has an annual capacity 

factor for natural gas of 10 percent (0.10) 

or less and is subject to a Federally 

enforceable requirement that limits 

operation of the affected facility to an 

annual capacity factor of 10 percent 

(0.10) or less for natural gas. 

(e) On and after the date on which the 

initial performance test is completed or 

is required to be completed under § 60.8 

of this part, whichever date comes first, 

no owner or operator of an affected 

facility that simultaneously combusts 

coal, oil, or natural gas with byproduct/ 

waste shall cause to be discharged into 

the atmosphere from that affected 

facility any gases that contain nitrogen 

oxides in excess of an emission limit 

determined by the following formula 

unless the affected facility has an 

annual capacity factor for coal, oil, and 

natural gas of 10 percent (0.10) or less 

and is subject to a Federally enforceable 

requirement which limits operation of 

the affected facility to an annual 

capacity factor of 10 percent (0.10) or 

less: 

En = ((ELB0 HB0) + (EL„ HJ + (ELC Hc)|/ 

(Hg0+Hro + Hc) 

where: 

En is the nitrogen oxides emission limit 

(expressed as NO2), ng/J (lb/million Btu) 

ELso is the appropriate emission limit from 

paragraph (a)(1) for combustion of 

natural gas or distillate oil, ng/J (lb/ 

million Btu). 

Hgo is the heat input from combustion of 

natural'gas, distillate oil and gaseous 

byproduct/waste, ng/J (lb/million Btu). 
P.24_ 

Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

ELr0 is the appropriate emission limit from 

paragraph (a)(2) for combustion of 

residual oil, ng/J (lb/million Btu) 

Hro is the heat input from combustion of 

residual oil and/or liquid byproduct/ 

waste. 

ELC is the appropriate emission limit from 

paragraph (a)(3) for combustion of coal, 

and 

Hc is the heat input from combustion of coal. 

(f) Any owner or operator of an 

affected facility that combusts 

byproduct/waste with either natural gas 

or oil may petition the Administrator 

within 180 days of the initial startup of 

the affected facility to establish a 

nitrogen oxides emission limit which 

shall apply specifically to that affected 

facility when the byproduct/waste is 

combusted. The petition shall include 

sufficient and appropriate data, as 

determined by the Administrator, such 

as nitrogen oxides emissions from the 

affected facility, waste composition 

(including nitrogen content), and 

combustion conditions to allow the 

Administrator to confirm that the 

affected facility is unable to comply 

with the emission limits in paragraph (e) 

of this section and to determine the 

appropriate emission limit for the 

affected facility. 

(1) Any owner or operator of an 

affected facility petitioning for a facilityspecific nitrogen oxides emission limit 

under this section shall: 

(i) Demonstrate compliance with the 

emission limits for natural gas and 

distillate oil in paragraph (a)(1) of this 

section or for residual oil in paragraph 

(a)(2) of this section, as appropriate, by 

conducting a 30-day performance test as 

provided in § 60.46b(e). During the 

performance test only natural gas, 

distillate oil, or residual oil shall be 

combusted in the affected facility; and 

(ii) Demonstrate that the affected 

facility is unable to comply with the 

emission limits for natural gas and 

distillate oil in paragraph (a)(1) of this 

section or for residual oil in paragraph 

(a)(2) of this section, as appropriate, 

when gaseous or liquid byproduct/ 

waste is combusted in the affected 

facility under the same conditions and 

using the same technological system of 

emission reduction applied when 

demonstrating compliance under 

paragraph (f)(l)(i) of this section. 

(2) The nitrogen oxides emission 

limits for natural gas or distillate oil in 

paragraph (a)(1) of this section or for 

residual oil in paragraph (a)(2) of this 

section, as appropriate, shall be 

applicable to the affected facility until 

and unless the petition is approved by 

the Administrator. If the petition is 

approved by the Administrator, a 

facility-specific nitrogen oxides 

emission limit will be established at the 

nitrogen oxides emission level 

achievable when the affected facility is 

combusting oil or natural gas and 

byproduct/waste in a manner that the 

Administrator determines to be 

consistent with minimizing nitrogen 

oxides emissions. 

(g) Any owner or operator of an 

affected facility that combusts 

hazardous waste (as defined by 40 CFR 

Part 261 or 40 CFR Part 761) with natural 

gas or oil may petition the Administrator 

within 180 days of the initial startup of 

the affected facility for a waiver from 

compliance with the nitrogen oxides 

emission limit which applies specifically 

to that affected facility. The petition 

must include sufficient and appropriate 

data, as determined by the 

Administrator, on nitrogen oxides 

emissions from the affected facility, 

waste destruction efficiencies, waste 

composition (including nitrogen 

content), the quantity of specific wastes 

to be combusted and combustion 

conditions to allow the Administrator to 

determine if the affected facility is able 

to comply with the nitrogen oxides 

emission limits required by this section. 

The owner or operator of the affected 

facility shall demonstrate that when 

hazardous waste is combusted in the 

affected facility, thermal destruction 

efficiency requirements for hazardouswaste specified in an applicable 

Federally enforceable requirement 

preclude compliance with the nitrogen 

oxides emission limits of this section. 

The nitrogen oxides emission limits for 

natural gas or distillate oil in paragraph 

(a)(1) of this section or for residual oil in 

paragraph (a)(2) of this section, as 

appropriate, are applicable to the 

affected facility until and unless the 

petition is approved by the 

Administrator. (See 40 CFR 761.70 for 

regulations applicable to the 

incineration of materials containing 

polychlorinated biphenyls (PCB's).) 

(h) The nitrogen oxide standards; 

under this section apply at all times 

including periods of startup, shutdown 

or malfunction. 

§ 60.45b Compliance and performance 

test methods and procedures for sulfur 

dioxide. 

(a) The sulfur dioxide emission 

standards under § 60.42b apply at all 

times. 

(b) In conducting the performance 

tests required under § 60.8, the owner or 

operator shall use the methods and 

procedures in Appendix A of this part or 

the method and procedures as specified 

in this section, except as provided in 

§ 60.8(b). Section 60.8(f) does not apply 

to this subpart. The 30-day notice 

required in § 60.8(d) applies only to the 

initial performance test unless otherwise 

specified by the Administrator. 

(c) The owner or operator of an 

affected facility shall conduct 

performance tests to determine 

compliance with the percent of potential 

sulfur dioxide emission rate (% PD) and 

the sulfur dioxide emission rate (Fy 

pursuant to § 60.42b following the 

procedures listed below, except as 

provided under paragraph (d) of this 

section. 

(1) The initial performance test shall 

be conducted over the first 30 

consecutive operating days of the steam 

generating unit. Compliance with the 

sulfur dioxide standards shall be 

determined using a 30-day average. The 

first operating day included in the initial 

performance test shall be scheduled 

within 30 days after achieving the 

maximum production rate at which the 

affected facility will be operated, but 

not later than 180 days after initial 

startup of the facility. 

(2) If only coal or only oil is 

combusted, the following procedures are 

used: 

(i) The procedures in Method 19 are 

used to determine the hourly sulfur 

dioxide emission rate (Eho) and the 30-

day average emission rate (E00). The 

hourly averages used to compute the 30-

day averages are obtained from the 

continuous emission monitoring system 

of § 60.47b (a) or (b). 

(ii) The percent of potential sulfur 

dioxide emission rate [% PJ emitted to 

the atmosphere is computed using the 

following formula: 

% P8=100 (1-?S R„/l00)(l-% R,/100) 

where: 

% R„ is the sulfur dioxide removal efficiency 

of the control device as determinod by 

Method 19, in percent. 

% Rf is the sulfur dioxide removal efficiency 

of fuel pretreatment as determined by 

Method 19, in percent. 

(3) If coal or oil is combusted with 

other fuels, the same procedures 

required in paragraph (c)(2) of this 

section are used, except as provided in 

the following: 

(i) An adjusted hourly sulfur dioxide 

emission rate (Eh0°) is used in Equation 

19-19 of Method 19 to compute an 

adjusted 30-day average emission rate 

(Eao°). The Eh0 is computed using the 

following formula: 

EK„°=[E*,0-Ew(l-Xk)l/X*, 

where: 

Eh()

0

 is the adjusted hourly sulfur dioxide 

emission rate, ng/J (lb/million Btu). 

Eho is the hourly sulfur dioxide emission rate, 

ng/J (lb/million Btu). 
47848 Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

E„ is the sulfur dioxide concentration in fuels 

other than coal and oil combusted in the 

affected facility, as determined by the 

fuel sampling and analysis procedures in 

Method 19, ng/J (lb/million Btu). The 

value Ew for each fuel lot is used for each 

hourly average during the time that the 

lot is being combusted. 

Xk is the fraction of total heat input from fuel 

combustion derived from coal, oil, or coal 

and oil, as determined by applicable 

procedures in Method 19. 

(ii) To compute the percent of 

potential sulfur dioxide emission rate (% 

Ps), an adjusted % Rg (% Rg°) is computed 

from the adjusted Eao° from paragraph 

(b)(3)(i) of this section and an adjusted 

average sulfur dioxide inlet rate (Eal°) 

using the following formula: 

%R,°=100(1.0-Eao°/Eai°) 

To compute Eai°, an adjusted hourly 

sulfur dioxide inlet rate (Ehi°) is used. 

The Ehi° is computed using the following 

formula: 

Ehl°=[E111-Ew(l-Xk)]/Xt 

where: 

Ehi° is the adjusted hourly sulfur dioxide inlet 

rate, ng/J (lb/million Btu). 

Ehi is the hourly sulfur dioxide inlet rate, ng/J 

(lb/million Btu). 

(4) The owner or operator of an 

affected facility subject to paragraph 

(b)(3) of this section does not have to 

measure parameters Ew or Xk if the 

owner or operator elects to assume that 

Xk=1.0. Owners or operators of affected 

facilities who assume Xk=1.0 shall 

(i) Determine % Ps following the 

procedures in paragraph (c)(2) of this 

section, and 

(ii) Sulfur dioxide emissions (Es) are 

considered to be in compliance with 

sulfur dioxide emission limits under 

§ 60.42b. 

(5) The owner or operator of an 

affected facility that qualifies under the 

provisions of § 60.42b(d) does not have 

to measure parameters E^, or Xk under 

paragraph (b)(3) of this section if the 

owner or operator of the affected facility 

elects to measure sulfur dioxide 

emission rates of the coal or oil 

following the fuel sampling and analysis 

procedures under Method 19. 

(d) The owner or operator of an 

affected facility that combusts only oil 

emitting less than 130 ng/J (0.3 lb/ 

million Btu) SO2, has an annual capacity 

factor for oil of 10 percent (0.10) or less, 

and is subject to a Federally enforceable 

requirement limiting operation of the 

affected facility to an annual capacity 

for oil of 10 percent (0.10) or less shall: 

(1) Conduct the initial performance 

test over 24 consecutive steam 

generating unit operating hours at full 

load; 

(2) Determine compliance with the 

standards after the initial performance 

test based on the arithmetic average of 

the hourly emissions data during each 

steam generating unit operating day if a 

continuous emission measurement 

system (CEMS) is used, or based on a 

daily average if Method 6B or fuel 

sampling and analysis procedures under 

Method 19 are used. 

(e) The owner or operator of an 

affected facility subject to § 60.42b(d)(l) 

shall demonstrate the maximum design 

capacity of the steam generating unit by 

operating the facility at maximum 

capacity for 24 hours. This 

demonstration will be made during the 

initial performance test and a 

subsequent demonstration may be 

requested at any other time. If the 24-

hour average firing rate for the affected 

facility is less than the maximum design 

capacity provided by the manufacturer 

of the affected facility, the 24-hour 

average firing rate shall be used to 

determine the capacity utilization rate 

for the affected facility, otherwise the 

maximum design capacity provided by 

the manufacturer is used. 

(f) For the initial performance test 

required under § 60.8, compliance with 

the sulfur dioxide emission limits and 

percent reduction requirements under 

§ 60.42b is based on the average 

emission rates and the average percent 

reduction for sulfur dioxide for the first 

30 consecutive steam generating unit 

operating days, except as provided 

under paragraph (d) of this section. 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 180 days 

after initial startup of the facility. The 

boiler load during the 30-day period 

does not have to be the maximum design 

load, but must be representative of 

future operating conditions and include 

at least one 24-hour period at full load. 

(g) After the initial performance test 

required under § 60.8, compliance with 

the sulfur dioxide emission limits and 

percent reduction requirements under 

§ 60.42b is based on the average 

emission rates and the average percent 

reduction for sulfur dioxide for 30 

successive steam generating unit 

operating days, except as provided 

under paragraph (d). 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 sulfur dioxide 

are calculated to show compliance with 

the standard. 

(h) Except as provided under 

paragraph (i) of this section, the owner 

or operator of an affected facility shall 

use all valid sulfur dioxide emissions 

data in calculating % Ps and Eho under 

paragraph (c), of this section whether or 

not the minimum emissions data 

requirements under § 60.46b are 

achieved. All valid emissions data, 

including valid sulfur dioxides emission 

data collected during periods of startup, 

shutdown and malfunction, shall be 

used in calculating % P5 and Eh0 

pursuant to paragraph (c) of this section. 

(i) During periods of malfunction or 

maintenance of the sulfur dioxide 

control systems when oil is combusted 

as provided under § 60.42b(i), emission 

data are not used to calculate % Ps or Es 

under § 60.42b (a), (b) or (c), however, 

the emissions data are used to 

determine compliance with the emission 

limit under § 60.42b(i). 

§ 60.46b Compliance and performance 

test methods and procedures for 

particulate matter and nitrogen oxides. 

(a) The particulate matter emission 

standards and opacity limits under 

§ 60.43b apply at all times except during 

periods of startup, shutdown, or 

malfunction. The nitrogen oxides 

emission standards under § 60.44b apply 

at all times. 

(b) Compliance with the particulate 

matter emission standards under 

§ 60.43b shall be determined through 

performance testing as described in 

paragraph (d) of this section. 

(c) Compliance with the nitrogen 

oxides emission standards under 

§ 60.44b shall be determined through 

performance testing as described in 

paragraph (e) or (f) of this section. 

(d) The following procedures and 

reference methods are used to determine 

compliance with the standards for 

particulate matter emissions under 

§ 60.43b. 

(1) Method 3 is used for gas analysis 

when applying Method 5 or Method 17. 

(2) Method 5, Method 5B, or Method 

17 shall be used to measure the 

concentration of particulate matter as 

follows: 

(i) Method 5 shall be used at affected 

facilities without wet flue gas 

desulfurization (FGD) systems; and 

(ii) Method 17 may be used at 

facilities with or without wet scrubber 

systems provided the stack gas 

temperature does not exceed a 

temperature of 160 °C (320 °F). The 
P.26 

Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

procedures of sections 2.1 and 2.3 of 

Method 5B may be used in Method 17 

only if it is used after a wet FGD system. 

Do not use Method 17 after wet FGD 

systems if the effluent is saturated or 

laden with water droplets. 

(iii) Method 5B is to be used only after 

wet FGD systems. 

(3) Method 1 is used to select the 

sampling site and the number of 

traverse sampling points. The sampling 

time for each run is at least 120 minutes 

and the minimum sampling volume is 1.7 

dscm (60 dscf) except that smaller 

sampling times or volumes may be 

approved by the Administrator when 

necessitated by process variables or 

other factors. 

(4) For Method 5, the temperature of 

the sample gas in the probe and filter 

holder is monitored and is maintained at 

160 °C (320 °F). 

(5) For determination of particulate 

matter emissions, the oxygen or carbon 

dioxide sample is obtained 

simultaneously with each run of Method 

5, Method 5B or Method 17 by traversing 

the duct at the same sampling location. 

(6) For each run using Method 5, 

Method 5B or Method 17, the emission 

rate expressed in nanograms per joule 

heat input is determined using: 

(i) The oxygen or carbon dioxide 

measurements and particulate matter 

measurements obtained under this 

section, 

(ii) The dry basis F factor, and 

(iii) The dry basis emission rate 

calculation procedure contained in 

Method 19 (Appendix A). 

(7) Method 9 is used for determining 

the opacity of stack emissions. 

(e) To determine compliance with the 

emission limits for nitrogen oxides 

required under § 60.44b, the owner or 

operator of an affected facility shall 

conduct the performance test as 

required under § 60.8 using the 

continuous system for monitoring 

nitrogen oxides under § 60.48(b). 

(1) For the initial compliance test, 

nitrogen oxides from the steam 

generating unit are monitored for 30 

successive steam generating unit 

operating days and the 30-day average 

emission rate is used to determine 

compliance with the nitrogen oxides 

emission standards under § 60.44b. The 

30-day average emission rate is 

calculated as the average of all hourly 

emissions data recorded by the 

monitoring system during the 30-day test 

period. 

(2) Following the date on which the 

initial performance test is completed or 

is required to be completed under § 60.8 

of this part, whichever date comes first, 

the owner or operator of an affected 

facility which combusts coal or which 

combusts residual oil having a nitrogen 

content greater than 0.30 weight percent 

shall determine compliance with the 

nitrogen oxides emission standards 

under § 60.44b on a continuous basis 

through the use of a 30-day rolling 

average emission rate. A new 30-day 

rolling average emission rate is 

calculated each steam generating unit 

operating day as the average of all of 

tiie hourly nitrogen oxides emission data 

for the preceding 30 steam generating 

unit operating days. 

(3) Following the date on which the 

initial performance test is completed or 

is required to be completed under § 60.8 

of this part, whichever date comes first, 

the owner or operator of an affected 

facility which has a heat input capacity 

greater than 73 MW (250 million Btu/ 

hour) and which combusts natural gas, 

distillate oil, or residual oil having a 

nitrogen content of 0.30 weight percent 

or less shall determine compliance with 

the nitrogen oxides standards under 

§ 60.44b on a continuous basis through 

the use of a 30-day rolling average 

emission rate. A new 30-day rolling 

average emission rate is calculated each 

steam generating unit operating day as 

the average of all of the hourly nitrogen 

oxides emission data for the preceding 

30 steam generating unit operating days. 

(4) Following the date on which the 

initial performance test is completed or 

required to be completed under § 60.8 of 

this part, whichever date comes first, the 

owner or operator of an affected facility 

which has a heat input capacity of 73 

MW (250 million Btu/hour) or less and 

which combusts natural gas, distillate 

oil, or residual oil having a nitrogen 

content of 0.30 weight percent or less 

shall upon request determine 

compliance with the nitrogen oxides 

standards under § 60.44b through the 

use of a 30-day performance test. During 

periods when performance tests are not 

requested, nitrogen oxides emissions 

data collected pursuant to § 60.48b(g)(l) 

or § 60.48b(g)(2) are used to calculate a 

30-day rolling average emission rate on 

a daily basis and used to prepare excess 

emission reports, but will not be used to 

determine compliance with the nitrogen 

oxides emission standards. A new 30-

day rolling average emission rate is 

calculated each steam generating unit 

operating day as the average of all of 

the hourly nitrogen oxides emission data 

for the preceding 30 steam generating 

unit operating days. 

(5) If the owner or operator of an 

affected facility which combusts 

residual oil does not sample and 

analyze the residual oil for nitrogen 

content, as specified in § 60.49b(e), the 

requirements of paragraph (iii) of this 

section apply and the provisions of 

paragraph (iv) of this section are 

inapplicable. 

(f) To determine compliance with Ihe 

emission limit for nitrogen oxides 

required by § 60.44b(a)(4) for duct 

burners used in combined cycle systems, 

the owner or operator of an affected 

facility shall conduct the performance 

test required under § 60.8 using the 

nitrogen oxides and oxygen 

measurement procedures in 40 CFR Part 

60 Appendix A, Method 20. During the 

performance test, one sampling site shall 

be located as close as practicable to the 

exhaust of the turbine, as provided by 

section 6.1.1 of Method 20. A second 

sampling site shall be located at the 

outlet to the steam generating unit. 

Measurements of nitrogen oxides and 

oxygen shall be taken at both sampling 

sites during the performance test, The 

nitrogen oxides emission rate from the 

combined cycle system shall be 

calculated by subtracting the nitrogen 

oxides emission rate measured at the 

sampling site at the outlet from the 

turbine from the nitrogen oxides 

emission rate measured at the sampling 

site at the outiet from the steam 

generating unit. 

§ 60.47b 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 

sulfur dioxide standards under § 60.42b 

shall install, calibrate, maintain, and 

operate continuous emission monitoring 

systems (CEMS) for measuring sulfur 

dioxide concentrations and either 

oxygen (O2) or carbon dioxide (CO2) 

concentrations and shall record the 

output of the systems. The sulfur dioxide 

and either oxygen or carbon dioxide 

concentrations shall both be monitored 

at the inlet and outlet of the sulfur 

dioxide 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 

sulfur dioxide emissions and percent 

reduction by: 

(1) Collecting coal or oil samples in an 

as-fired condition at the inlet to the 

steam generating unit and analyzing 

them for sulfur and heat content 

according to Method 19. Method 19 

provides procedures for converting these 

measurements into the format to be used 

in calculating the average sulfur dioxide 

input rate, or 

(2) Measuring sulfur dioxide according 

to Method 6B at the inlet or outlet to the 

sulfur dioxide control system. An initial 

stratification test is required to verify 

the adequacy of the Method 6B sampling 
47850 Federal Register / Vol. 52, No. 241 / Wednesday, .December 16, 1987 / Rules and Regulations 

location. The stratification test shall 

consist of three paired runs of a suitable 

sulfur dioxide and carbon dioxide 

measurement train operated at the 

candidate location and a second similar 

train operated according to the 

procedures in Section 3.2 and the 

applicable procedures in Section 7 of 

Performance Specification 2. Method 6B, 

Method 6A, or a combination of 

Methods 6 and 3 or Methods 6C and 3A 

are suitable measurement techniques. If 

Method 6B is used for the second train, 

sampling time and timer operation may 

be adjusted for the stratification test as 

long as an adequate sample volume is 

collected; however, both sampling trains 

are to be operated similarly. For the 

location to be adequate for Method 6B 

24-hour tests, the mean of the absolute 

difference between the three paired runs 

must be less than 10 percent. 

(3) A daily sulfur dioxide emission 

rate, ED, shall be determined using the 

procedure described in Method 6A, 

Section 7.6.2 (Equation 6A-8) and stated 

in ng/J (lb/million Btu) heat input. 

(4) The mean 30-day emission rate is 

calculated using the daily measured 

values in ng/J (lb/million Btu) for 30 

successive steam generating unit 

operating days using equation 19-20 of 

Method 19. 

(c) The owner or operator of an 

affected facility shall obtain emission 

data for at least 75 percent of the 

operating hours in at least 22 out of 30 

successive boiler operating days. If this 

minimum data requirement is not met 

with a single monitoring system, the 

owner or operator of the affected facility 

shall supplement the emission data with 

data collected with other monitoring 

systems as approved by the 

Administrator or the reference methods 

and procedures as described in 

paragraph (b) of this section. 

(d) The 1-hour average sulfur dioxide 

emission rates measured by the CEMS 

required by paragraph (a) of this section 

and required under § 60.13(h) is 

expressed in ng/J or lb/million Btu heat 

input and is used to calculate the 

average emission rates under § 60.42b. 

Each 1-hour average sulfur dioxide 

emission rate must be based on more 

than 30 minutes of steam generating unit 

operation and include at least 2 data 

points with each representing a 15-

minute period. Hourly sulfur dioxide 

emission rates are not calculated if the 

affected facility is operated less than 30 

minutes in a 1-hour period and are not 

counted toward determination of a 

steam generating unit operating day. 

(e) The procedures under § 60.13 shall 

be followed for installation, evaluation, 

and operation of the CEMS. . 

(1) All CEMS shall be operated in waste, the span value for a continuous 

accordance with the applicable monitoring system for measuring opacilv 

procedures under Performance shall be between 60 and 80 percent. 

Specifications 1, 2, and 3 (Appendix B). r2j For affected facilities combusting 

(2) Quarterly accuracy determinations coal j 0jl, o r natur a l gas, the span value 

and daily calibration drift tests shall be fo r ni tr 0 gen oxides is determined as 

performed in accordance with Procedure follows' 

1 (Appendix F). 

(3) For affected facilities combusting 

coal or oil, alone or in combination with 

other fuels, the span value of the sulfur 

dioxide CEMS at the inlet to the sulfur 

dioxide control device is 125 percent of 

the maximum estimated hourly potential 

sulfur dioxide emissions of the fuel 

combusted, and the span value of the 

CEMS at the outlet to the sulfur dioxide where: 

control device is 50 percent of the • ,*_ r .• r . . i u . * . J • • 

.. . t"-' 1-

1

- " 1" ""• _ x is the fraction of total heat input derived 

maximum estimated hourly potential fro m natura | ga s 

sulfur dioxide emissions of the fuel y is th e fractjo n o f to ; a l hea l inpu t derive d 

combusted. from oii, and 

z is the fraction of total heat input derived 

from coal. 

Oil 

Fuel 

Span values (or 

nitrogen oxides 

(PPM) 

. 500 

500 

1,000 

500(x + y) + 1,000z 

§ 60.48b Emission monitoring for 

particulate matter and nitrogen oxides. 

(a) The owner or operator of an 

affected facility subject to the opacity 

standard under § 60.43b shall install, 

calibrate, maintain, and operate a 

continuous monitoring system for 

measuring the opacity of emissions 

discharged to the atmosphere and 

record the output of the system. 

(b) Except as provided in paragraphs 

(g) and (h) of this section, the owner or 

operator of an affected facility subject to 

the nitrogen oxides standard of 

§ 60.44b(a) shall install, calibrate, 

maintain, and operate a continuous 

monitoring system for measuring 

nitrogen oxides emissions discharged to 

the atmosphere and record the output of 

the system. 

(c) The continuous monitoring systems 

required under paragraph (b) of this 

section shall be operated and data 

recorded during all periods of operation 

of the affected facility except for 

continuous monitoring system 

breakdowns and repairs. Data is 

recorded during calibration checks, and 

zero and span adjustments. 

(d) The 1-hour average nitrogen 

oxides emission rates measured by the 

continuous nitrogen oxides monitor 

required by paragraph (b) 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 § 60.44b. 

The 1-hour averages shall be calculated 

using the data points required under 

§ 60.13(b). 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 continuous 

monitoring systems. 

(1) For affected facilities combusting 

coal, wood or municipal-type solid 

(3) All span values computed under 

paragraph (e)(2) of this section for 

combusting mixtures of regulated fuels 

are rounded to the nearest 500 ppm. 

(f) When nitrogen oxides emission 

data are not obtained because of 

continuous monitoring system 

breakdowns, repairs, calibration checks 

and zero and span adjustments, 

emission data will be obtained by using 

standby monitoring systems, Method 7, 

Method 7A, or other approved reference 

methods to provide emission data for a 

minimum of 75 percent of the operating 

hours in each steam generating unit 

operating day, in at least 22 out of 30 

successive steam generating unit 

operating days. 

(g) The owner or operator of an 

affected facility that has a heat input 

capacity of 73 MW (250 million Btu/ 

hour) or less, and which has an annual 

capacity factor for residual oil having a 

nitrogen content of 0.30 weight percent 

or less, natural gas, distillate oil, or any 

mixture of these fuels, greater than 10 

percent (0.10) shall: 

(1) Comply with the provisions of 

paragraphs (b), (c), (d), (e)(2), (e)(3), and 

(f) of this section, or 

(2) Monitor steam generating unit 

operating conditions and predict 

nitrogen oxides emission rates as 

specified in a plan submitted pursuant 

to § 60.49b(c). 

(h) The owner or operator of an 

affected facility which is subject to the 

nitrogen oxides standards of 

§ 60.44b(a)(4) is not required to install or 

operate a continuous monitoring system 

to measure nitrogen oxides emissions. 

(Approved by the Office of Management and 

Budget undercontrol number 2060-0072) 
P.28 

Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

§ 60.49b Reporting and recordkeeping 

requirements. 

(a) The owner or operator of each 

affected facility shall submit notification 

of the date of initial startup, as provided 

by § 60.7. This notification shall include: 

(1) The design heat input capacity of 

the affected facility and identification of 

the fuels to be combusted in the affected 

facility, 

(2) If applicable, a copy of any 

Federally enforceable requirement that 

limits the annual capacity factor for any 

fuel or mixture of fuels under 

§ 60.42b(d)(l), § 60.43(b)(a)(2), 

§ 60.43b(a)(3)(iii), § 60.43b(c)(2)(ii), 

§ 60.43b(d)(2)(iii), § 60.44b(c), 

§ 60.44b(d), § 60.44b(e), or § 60.45b(d], 

(3) The annual capacity factor at 

which the owner or operator anticipates 

operating the facility based on all fuels 

fired and based on each individual fuel 

fired, and, 

(4) Notification that an emerging 

technology will be used for controlling 

emissions of sulfur dioxide. The 

Administrator will examine the 

description of the emerging technology 

and will determine whether the 

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 affected facility is subject to 

the provisions of § 60.42b(a) unless and 

until this determination is made by the 

Administrator. 

(b) The owner or operator of each 

affected facility subject to the sulfur 

dioxide, particulate matter and nitrogen 

oxides emission limits under § 60.42b, 

§ 60.43b, and § 60.44b, shall submit to 

the Administrator the performance test 

data from the initial performance test 

and the performance evaluation of the 

CEMS using the applicable performance 

specifications in Appendix B. 

(c) The owner or operator of each 

affected facility subject to the nitrogen 

oxides standard of § 60.44b who seeks 

to demonstrate compliance with those 

standards through the monitoring of 

steam generating unit operating 

conditions under the provisions of 

§ 60.48b(g)(2) shall submit to the 

Administrator for approval a plan that 

identifies the operating conditions to be 

monitored under § 60.48b(g)(2) and the 

records to be maintained under 

§ 60.49b(j). This plan shall be submitted 

to the Administrator for approval within 

360 days of the initial startup of the 

affected facility. The plan shall: 

(1) Identify the specific operating 

conditions to be monitored and the 

relationship between these operating 

conditions and nitrogen oxides emission 

rates (i.e., ng/J or lbs/million Btu heat 

input). Steam generating unit operating 

conditions include, but are not limited 

to, the degree of staged combustion (i.e., 

the ratio of primary air to secondary 

and/or tertiary air) and the level of 

excess air (i.e., flue gas oxygen level); 

(2) Include the data and information 

that the owner or operator used to 

identify the relationship between 

nitrogen oxides emission rates and these 

operating conditions; 

(3) Identify how these operating 

conditions, including steam generating 

unit load, will be monitored under 

§ 60.48b(g) on an hourly basis by the 

owner or operator during the period of 

operation of the affected facility; the 

quality assurance procedures or 

practices that will be employed to 

ensure that the data generated by 

monitoring these operating conditions 

will be representative and accurate; and 

the type and format of the records of 

these operating conditions, including 

steam generating unit load, that will be 

maintained by the owner or operator 

under § 60.49b(j). 

If the plan is approved, the owner or 

operator shall maintain records of 

predicted nitrogen oxide emission rates 

and the monitored operating conditions, 

including steam generating unit load, 

identified in the plan. 

(d) The owner or operator of an 

affected facility shall record and 

maintain records of the amounts of each 

fuel combusted during each day and 

calculate the annual capacity factor 

individually for coal, distillate oil, 

residual oil, natural gas, wood, and 

municipal-type solid waste for each 

calendar quarter. The annual capacity 

factor is determined on a 12-month 

rolling average basis with a new annual 

capacity factor calculated at the end of 

each calendar month. 

(e) For affected facilities that: (1) 

Combust residual oil having a nitrogen 

content of 0.3 weight percent or less; (2) 

have heat input capacities of 73 MW 

(250 million Btu/hour) or less; and (3) 

monitor nitrogen oxides emissions or 

, steam generating unit operating 

conditions under § 60.48b(g), the owner 

or operator shall maintain records of the 

nitrogen content of the oil combusted in 

the affected facility and calculate the 

average fuel nitrogen content on a per 

calendar quarter basis. The nitrogen 

content shall be determined using 

ASTM Method D3431-80, Test Method 

for Trace Nitrogen in Liquid Petroleum 

Hydrocarbons (IBR—see § 60.17), or fuel 

specification data obtained from fuel 

suppliers. If residual oil blends are being 

combusted, fuel nitrogen specifications 

may be prorated based on the ratio of 

residual oils of different nitrogen 

content in the fuel blend. 

(f) For facilities subject to the opacity 

standard under § 60.43b, the owner or 

operator shall maintain records of 

opacity. 

(9) For facilities subject to nitrogen 

oxides standards under § 60.44b, the 

owner or operator shall maintain 

records of the following information for 

each steam generating unit operating 

day: 

(1) Calendar date. 

(2) The average hourly nitrogen oxides 

emission rates (expressed as N02) (ng/J 

or lb/million Btu heat input) measured 

or predicted. 

(3) The 30-day average nitrogen 

oxides emission rates (ng/J or lb/million 

Btu heat input) calculated at the end of 

each steam generating unit operating 

day from the measured or predicted 

hourly nitrogen oxide emission rates for 

the preceding 30 steam generating unit 

operating days. 

(4) Identification of the steam 

generating unit operating days when the 

calculated 30-day average nitrogen 

oxides emission rates are in excess of 

the nitrogen oxides emissions standards 

under § 60.44b, with the reasons for such 

excess emissions as well as a 

description of corrective actions taken. 

(5) Identification of the steam 

generating unit operating days for which 

pollutant data have not been obtained, 

including reasons for not obtaining 

sufficient data and a description of 

corrective actions taken. 

(6) Identification of the times when 

emission data have been excluded from 

the calculation of average emission 

rates and the reasons for excluding data. 

(7) Identification of "F" factor used for 

calculations, method of determination, 

and type of fuel combusted. 

(8) Identification of the times when 

the pollutant concentration exceeded 

full span of the continuous monitoring 

system. 

(9) Description of any modifications to 

the continuous monitoring system that 

could affect the ability of the continuous 

monitoring system to comply with 

Performance Specification 2 or 3. 

(10) Results of daily CEMS drift tests 

and quarterly accuracy assessments as 

required under Appendix F, Procedure 1. 

(h) The owner or operator of any 

affected facility in any category listed in 

paragraphs (h) (1) or (2) of this section is 

required to submit excess emission 

reports for any calendar quarter during 

which there are excess emissions from 

the affected facility. If there are no 

excess emissions during the calendar 

quarter, the owner or operator shall 

submit a report semiannually stating 
-S7852 Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

that no excess emissions occurred 

during the semiannual reporting period. 

(1) Any affected facility subject to the 

opacity standards under § 60.43b(e) or 

to the operating parameter monitoring 

requirements under § 60.13(i)(l). 

(2) Any affected facility that is subject 

to the nitrogen oxides standard of 

§ 60.44b, and that 

(i) Combusts natural gas, distillate oil, 

or residual oil with a nitrogen content of 

0.3 weight percent or less, or 

(ii) Has a heat input capacity of 73 

MW (250 million Btu/hour) or less and is 

required to monitor nitrogen oxides 

emissions on a continuous basis under 

§ 60.48b(g)(l) or steam generating unit 

operating conditions under 

§ 60.48b(g)(2). 

(3) For the purpose of § 60.43b, excess 

emissions are defined as all 6-minute 

periods during which the average 

opacity exceeds the opacity standards 

under § 60.43b(f). 

(4) For purposes of § 60.48b(g)(l), 

excess emissions are defined as any 

calculated 30-day rolling average 

nitrogen oxides emission rate, as 

determined under § 60.46b(e), which 

exceeds the applicable emission limits 

in § 60.44b. 

(i) The owner or operator of any 

affected facility subject to the 

continuous monitoring requirements for 

nitrogen oxides under § 60.48(b) shall 

submit a quarterly report containing the 

infonnation recorded under paragraph 

(g) of this section. All quarterly reports 

shall be postmarked by the 30th day 

following the end of each calendar 

quarter. 

(j) The owner or operator of any 

affected facility subject to the sulfur 

dioxide 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. 

(k) For each affected facility subject to 

the compliance and performance testing 

requirements of § 60.45b and the 

reporting requirement in paragraph (j) of 

this section, the following information 

shall be reported to the Administrator: 

(1) Calendar dates covered in ths 

reporting period. 

(2) Each 30-day average sulfur dioxide 

emission rate (ng/J or lb/million Btu 

heat input) 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 sulfur dioxide 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 that coal 

or oil was combusted and for which 

sulfur dioxide or diluent (oxygen or 

carbon dioxide) data have not been 

obtained by an approved method for at 

least 75 percent of the operating hours in 

the steam generating unit operating day; 

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 

coal or oil were not 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 that could affect the ability of 

the CEMS to comply with Performance 

Specification 2 or 3. 

(10) Results of daily CEMS drift tests 

and quarterly accuracy assessments as 

required under Appendix F, Procedure 1. 

(11) The annual capacity factor of 

each fired as provided under paragraph 

(d) of this section. 

(1) For each affected facility subject to 

the compliance and performance testing 

requirements of § 60.45b(d) and the 

reporting requirements of paragraph (j) 

of this section, the following information 

shall be reported to the Administrator: 

(1) Calendar dates when the facility 

was in operation during the reporting 

period; 

(2) The 24-hour average sulfur dioxide 

emission rate measured for each steam 

generating unit operating day during the 

reporting period that coal or oil was 

combusted, ending in the last 24-hour 

period in the quarter; reasons for 

noncompliance with the emission 

standards; and a description of 

corrective actions taken; 

(3) Identification of the steam 

generating unit operating days that coal 

or oil was combusted for which sulfur 

dioxide 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. 

(4) 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 

coal or oil were not combusted in the 

steam generating unit. 

(5) Identification of "F" factor used for 

calculations, method of determination, 

and type of fuel combusted. 

(6) Identification of times when hourly 

averages have been obtained based on 

manual sampling methods. 

(7) Identification of the times when 

the pollutant concentration exceeded 

ful] span of the CEMS. 

(8) Description of any modifications, to 

the CEMS which could affect the ability 

of the CEMS to comply with 

Performance Specification 2 or 3. 

(9) Results of daily CEMS drift tests 

and quarterly accuracy assessments as 

required under Appendix F, Procedure 1. 

(m) For each affected facility subject 

to the sulfur dioxide 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 (k) of this 

section: 

(1) 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 7. 

(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 7. 

(4) 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. 

(n) If a percent removal efficiency by 

fuel pretreatment (i.e., % RJ is used to 

determine the overall percent reduction 

(i.e., % R0) under § 60.45b, the owner or 

operator of the affected facility shall 

submit a signed statement with the 

quarterly report: 

(1) Indicating what removal efficiency 

by fuel pretreatment (i.e., % Rf) was 

credited 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 
P.30 

Federal Register / Vol. 52. No. 241 / Wednesday, December 16. 1987 / Rules and Regulations 47853 

all fuels received at the affected facility 

during the previous calendar quarter; 

(3) Documenting the transport of the 

fuel from the fuel pretreatment facility to 

the steam generating unit. 

(4) Including a signed statement from 

the owner or operator of the fuel 

pretreatment facility certifying that the 

percent removal efficiency achieved by 

fuel pretreatment was determined in 

accordance with the provisions of 

Method 19 (Appendix A) and listing the 

heat content and sulfur content of each 

fuel before and after fuel pretreatment 

(o) 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. 

(Approved by the Office of Management and 

Budget under control number 2060-0135) 

4. 40 CFR Part 60, Appendix A, is 

amended by revising Method 19 to read 

as follows: 

Appendix A to Part 60—[Amended] 

Method 19—Determination of Sulfur Dioxide 

Removal Efficiency and Particulate Matter, 

Sulfur Dioxide, and Nitrogen Oxides 

Emission Rates 

1. Applicability and Principle 

1.1 Applicability. This method is 

applicable for (a) determining particulate 

matter (PM), sulfur dioxide (SO2), and 

nitrogen oxides (NO,) emission rates; (b) 

determining sulfur removal efficiencies of fuel 

pretreatment and SOj control devices; (c) 

determining overall reduction of potential 

SO2 emissions from steam generating units or 

other sources as specified in applicable 

regulations; and (d) determining SOj rates 

based on fuel sampling and analysis 

procedures. 

1.2 Principle. 

1.2.1 Pollutant emission rates are 

determined from concentrations of PM, SOj, 

or NO,, and oxygen (O2) or carbon dioxide 

(CO2) along with F factors (ratios of 

combustion gas volumes to heat inputs). 

1.2.2 An overall SO2 emission reduction 

efficiency is computed from the efficiency of 

fuel pretreatment systems (optional) and the 

efficiency of SO2 control devices. 

1.2.3 The sulfur removal efficiency of a 

fuel pretreatment system is determined by 

fuel sampling and analysis of the sulfur and 

heat contents of the fuel before and after the 

pretreatment system. 

1.2.4 The SO2 removal efficiency of a 

control device is determined by measuring 

the SO2 rates before and after the control 

device. 

1.2.5 The inlet rates to SO2 control 

systems and when SO2 control systems are 

not used, SO2 emission rates to the 

atmosphere may be determined by fuel 

sampling and analysis (optional). 

2. Emission Rates of Particulate Matter. 

Sulfur Dioxide, and Nitrogen Oxides 

Select from the following sections the 

applicable procedure to compute the PM, 

SO2, or NO, emission rate (E) in ng/J (lb/ 

million Btu). The pollutant concentration 

must be in ng/scm (Ib/scf) and the F factor 

must be in scm/J (scf/million Btu). If the 

pollutant concentration (C) is not in the 

appropriate units, use the following table to 

make the proper conversion: 

CONVERSION FACTORS FOR 

CONCENTRATION 

From 

g/scm 

mg/scm 

Ib/scf 

ppm SO2 

ppm NO, 

ppm SO2 

ppm NO, 

To 

ng/scm 

ng/scm 

ng/scm 

ng/scm 

ng/scm 

Ib/scf 

Ib/scf 

Multiply by 

109 

10" 

1.602X1013 

2.66 x106 

1.912x10s 

1.660X10-1 

1.194X10"' 

An F factor is the ratio of the gas volume of 

the products of combustion to the heat 

content of the fuel. The dry F factor (F„) 

includes all components of combustion less 

water, the wet F factor (F„.) includes all 

components of combustion, and the carbon F 

factor (Fc) includes only carbon dioxide. 

Note: Since Fw factors include water 

resulting only from the combustion of 

hydrogen in the fuel, the procedures using F„ 

factors are not applicable for computing E 

from steam generating units with wet 

scrubbers or with other processes that add 

water (e.g., steam injection) 

2.1 , Oxygen-Based F Factor, Dry Basis. 

When measurements are on a dry basis for 

both O2 (%02„) and pollutant (C„) 

concentrations, use the following equation: • 

E=CdFd [20.9/(20.9-%O2„)] Eq. 19-1 

2.2 Oxygen-Based F Factor, Wet Basis. 

When measurements are on a wet basis for 

both O2 (%02w) and pollutant (C„) 

concentrations, use either of the following: 

2.2.1 If the moisture fraction of ambient 

air (BwJ is measured: 

E=(C».FW20.9]/[20.9(1-Bwn) -%Os„] Eq. 

19-2 

Instead of actual measurement. B„, may be 

estimated according to the procedure below. 

(Note: The estimates are selected to ensure 

that negative errors will not be larger than 

—1.5 percent. However, positive errors, or 

over-estimation of emissions, of as much as 5 

percent may be introduced depending upon 

the geographic location of the facility and the 

associated range of ambient moisture): 

2.2.1.1 B„a=0.027. This value may be used 

at any location at all times. 

2.2.1.2 B„. = Highest monthly average of 

Baa that occurred within the previous 

calendar year at the nearest Weather Service 

Station. This value shall be determined 

annually and may be used as an estimate for 

the entire current calendar year. 

2.2.1.3 Bwi^Highest daily average of Bw, 

that occurred within a calendar month at the 

nearest Weather Service Station, calculated 

from Ihe dutu from thu pusl .'I years. This 

value shall be computed for each month itncl 

may be used as an estimate for the current 

respective calendar month. 

2.2.2 If the moisture fraction (ll„,| of llie 

effluent gas is measured: 

E = CwFd (20.9/[20.9(1 B»h) 'VO-Jl l'.(|. 

19-3 

2.3 Oxygen-Based F Factor. Dry/ Wei 

Basis. 

2.3.1 When the pollutant umr.entiullon is 

measured on a wet basis (C„) and ()• 

concentration is measured on a dry basis 

(%02d), use the following equation: 

E==!(C„Fd)/(1 Dw J|/ [20.9/(20.9 '\,0-,)| 

Eq. 19-4 

2.3.2 When tho pollutant eoneenli-alion Is 

measured on a dry basis (Crt) and llie ()» 

concentration is measured on a wet basis 

(%02w). use the following equation: 

E = [CdFd20.9)/|20.9* 0,„/(l B.,)| 

Eq. 19-5 

2.4 Carbon Dioxide Based F l-'ur'ur. Dry 

Basis. When measurements are on a dry 

basis for both COj ("iCO:,,) and pollutant (CJ 

concentrations, use Ihe following equation: 

E = CdKc(100/"iCO2d) Eq. 19-0 

2.5 Carbon Dioxide-Uased F Factor. Wet 

Basis. When measurements are on n wet 

basis for both CO2 (%COs») and pollutant 

(C„) concentrations, use thu folhtvvin^ 

equation: 

E^C».Fr (100/%CO2„.) Eq. 19 7 

2.6 Carbon Dioxide-Based F Factor, Dry/ 

Wet Basis. 

2.6.1 When Ihe pollutant concentration is 

measured on a wet basis (CJ and (.()» 

concentration is measured on a dry basis 

(%CO-d). use Ihe following equation: 

E*= ICFC/(1 - B„J] (100/%CO.d) K(|. 19-11 

2.6.2 When the pollutant concentration is 

measured on a dry basis (Cd) and COs 

concentration is measured on a wet basis 

(%C02»), use the following equation: 

E = Cd(l-B„.)Fc(l00/%CO2„) Eq. 19 9 

2.7 Direct-Fired Reheat Fuel Burning. The 

effect of direct-fired reheat fuel burning (for 

the purpose of raising the temperature of the 

exhaust effluent from wet scrubbers to above 

the moisture dew-point) on emission rates 

will be less than ±1.0 percent and, therefore, 

may be ignored. 

2.8 Combined Cycle-Gas Turbine 

Systems. For gas turbinc-steum generator 

combined cycle systems, determine the 

emissions from the steam generating unit or 

the percent reduction in potential SO2 

emissions as follows: 

2.8.1 Compute the emission rale from the 

steam generating unit using the following 

equation: 

E*,„=Ec0-t (H,/II„)(FW EJ Eq. 19 10 

where: 

Ebo = pollutant emission rate from the steam 

generating unit, ng/J (lb/million Btu). 

Eco = pollutant emission rate in combined 

effluent, ng/J (lb/million Btu). 
P.31 

47854 Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

E,=pollutant rate from gas turbine, ng/J (lb/ 

million Btu). 

Hb=heat input rate to the steam;generating 

unit from fuels fired in the steam 

generating unit, J/hr (million Btu/hr). 

H„ = heat input rate to gas turbine from all 

fuels fired in the gas turbine, J/hr (million 

Btu/hr). 

2.8.1.1 Use the test methods and 

procedures section of Subpart GG to obtain 

Eco and EB. Do not use Fw factors for 

determining E„ or E„. If an SO2 control device 

is used, measure Em after the control device. 

2.8.1.2 Suitable methods shall: be used1 to 

determine the heat input rates to the steam 

generating units (H„) and the gas turbine (H,). 

2.8.2 If a control device is used, compute 

the percent of potential S02 emissions (% PJ 

using the following, equations: 

Eb i=Ed -(H,/Hb )(Ed -Eg ) Eq. 19-11 

%P, = \Q0[l-EbolEbiy Eq. 19-12 

where: 

E*,i=pollutant rate from the steam generating 

unit, ng/J (lb/million Btu) 

Eci=pollutantrate in combined effluent, ng/J 

(lb/million Btu). 

Use the test methods and procedures 

section, of Subpart GG to obtain Ecl and E„. 

Do not use Fw factors for determining E, or 

E* 

3: F Factors 

Use an average F factor according to 

Section 3.1 or determine an applicable F 

factor according to Section 3.2. If combined 

fuels are fired, prorate the applicable F 

factors using the procedure in Section 3.3. 

3.1 Average F Factors: Average F factors 

(Fd, F„, or FJ from Table 19-1 may be used. 

TABLE 19-1.—F FACTORS FOR VARIOUS FUELS > 

Fuel type 

Coal: 

Anthracite

 2 

Bituminous

 2 

Lignite 

Oil3 

Gas: 

Propane 

Butane 

Wood 

Wood Bark 

Municipal 

Solid Waste • 

F 

dscm/J 

2.71x10' ' 

2.63x10"' 

2.65x10-' 

2.47x10-' 

2.43x10"' 

2.34X10"' 

2.34x10"' 

2.48 X TO"' 

2.5&X10"' 

2.57x10"' 

d 

dscf/106 

Btu 

10,100 

9,780 

9,860 

9,1.90 

8,710 

8,710 

8,710 

9,240 

9,600 

9,570 

F 

wscm/J 

2.83 xtO-T 

2.86x10-' 

, 3.21 X10"' 

£77X10"' 

; 2.85x10"' 

2.74X10"' 

2.79X10"' 

wscf/10

 6 

Btu 

10,540 

10,640 

11,950 

10,320 

10,610 

10,200 

10,390 

F 

scm/J 

0.530x10"'' 

0.484x10"' 

0.513X10"' 

0.383X10"' 

0.287X10"' 

0.321x10-' 

0.337 X TO"' 

0.492x10"' 

0.516X10-' 

0.488x10"' 

c 

scf/106Btu 

1,970 

1,800 

1,910 

1,420 

1,040 

1,190 

1,250 

1,830 

1,920 

1,820 

1

 Determined at standard conditions: 20 °C (68 °F) and 760 mm Hg (29.92 in. Hg)i 

2

 As classified according to ASTM D388-77. 

3

 Crude, residual, or distillate. 

3.2 Determined F Factors. If the. fuel burned: 

is not listed in Table 19-1 or if the owner or 

operator chooses to determine an F factor 

rather than use the values in Table 19-1, use 

the procedure below: 

3.2.1 Equations. Use the equations below, 

as appropriate, to compute the F factors: 

Fd = K[(Khd%H) + (KC%C) + (K,%S) + [K„%N) -

(Ko%,0)]/GCV Eq. 19-13 

F«=Kl(Khw%H) + (KC%C) •+ (K.7&S) + (Kn%N)-

(K„%0) + (K.%H2O)]/GCVw Eq, 19--14 

FC=K(KCC%C)/GCV Eq. 19-15 

(Note..—Omit the %H20 term, in; the 

equations for F„ if %H andi%0 include the 

unavailable hydrogem and oxygen, in the form 

0fH2O.) 

where: 

Fd,Fw,Fc=volumes of combustion components 

per unit of heat content, scm/J (scf/ 

million Btu). 

%H, %C, %S, %N, %0: and 

%H20=concentrations of hydrogen, 

carbon, sulfur, nitrogen, oxygen, and 

water from an ultimate analysis of fuel, 

weight percent. 

GCV=gross calorific value ofthe fuel 

consistent with the ultimate analysis, kJ/ 

kg (Btu/lb). 

K=conversion factor, 10"5 (kJ/J)/(%) [10"6 

Btu/million Btu). 

Khd = 22.7 (scm/kg))[(3.64 (scf/lb)/(%)J. 

1^=9.57 (scm/kg)((1.53 (scf/lb)/(%)]. 

K, = 3.54 (scm/kg) [(0.57 (scf/lb)/(%)]: 

Kn=0.86 (scm/kg [0;14 (scf/lb)/(%)]'. 

K„=2.85 (scm/kg) |U.46 (scf/lb)/(%))„ 

Khw=34.74 (scm/kg) [(5.57 (scf/lb)/(%)]. 

K„=1.30 (scm/kg) [(0.21 (scf/lb)/(%)]. 

1^=2.0 (scm/kg) [(0.321 (sef/lb)/(%)J. 

3.2.2 Use applicable sampling procedures in 

Section 5.2.1 or 5.2.2 to obtain samples for 

analyses. 

3.2.3 Use ASTM D3176-74 (incorporated by 

reference—see § 60.17). for ultimate analysis 

of the fuel. 

3.2.4 Use applicable, methods in Section 

&2.1 or 5.2.2. to determine the heat content of 

solid or liquid fuels. For gaseous fuels, use 

ASTM D1826-77 (IBR—see § 60:17) to 

determine the heat content. 

3.3 F Factors for Combination of Fuels.. If 

combinations of fuels are bumed',. use- the 

following equations, as applicable unless 

otherwise specified in applicable subpart: 

Eq. 19-16 

w

 k-l

 k wk 

Eq. 19-17 

n 

C R- 1 K CK 

Eq. 19-18 

where: 

Xk = fraction of total heat input from, each 

type of fuel k. 
P.32 

Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 47855 

n=number of fuels being burned in 

combination. 

4. Determination of Average Pollutant Rates 

4.1 Average Pollutant Rates from Hourly 

Values. When hourly average pollutant rates 

(Eh), inlet or outlet, are obtained (e.g., CEMS 

values), compute the average pollutant rate 

(Ea) for the performance test period (e.g., 30 

days) specified in the applicable regulation 

using the following equation: 

E

a = ( W *EhJ j -l 

Eq. 19-19 

where: 

E„=average pollutant rate for the specified 

performance test period, ng/J (lb/million 

Btu). 

Eh=hourly average pollutant, ng/J (lb/million 

Btu). 

H = total number of operating hours for which 

pollutant rates are determined in the 

performance test period. 

4.2 Average Pollutant Rates from Other 

than Hourly Averages. When pollutant rates 

are determined from measured values 

representing longer than 1-hour periods (e.g., 

daily fuel sampling and analyses or Method 

6B values), or when pollutant rates are 

determined from combinations of 1-hour and 

longer than 1-hour periods (e.g., CEMS and 

Method 6B values), compute the average 

pollutant rate (Ea) for the performance test 

period (e.g., 30 days) specified in the 

applicable regulation using the following 

equation: 

Eq. 19-20 

where: 

Ed = average pollutant rate for each sunip'.ing 

period (e.g., 24-hr Method 6B sample or 

24-hr fuel sample) or for each fuel lot 

(e.g., amount of fuel bunkered), ng/J (lb/ 

million Btu). 

nd=number of operating hours of the uffected 

facility within the performance test 

period for each Ed determined. 

D = number of sampling periods during tho 

performance test period. 

5. Determination of Overall Reduction in 

Potential Sulfur Dioxide Emission 

5.1 Overall Percent Reduction. Compute 

the overall percent SO2 reduction (%R0) using 

the following equation: 

%R„=100 [1.0-(1.0-%R,/100)(1.0-%R„/t00)) 

Eq. 19-21 

where: 

%Rr=S02 removal efficiency from fuel 

pretreatment, percent. 

%RB=S02 removal efficiency of the control 

device, percent. 

5.2 Pretreatment Removal Efficiency 

(Optional). Compute the SOa removal 

efficiency from fuel pretreatment (96Rf) for thu 

averaging period (e.g., 90 days) as specified in 

the applicable regulation using the following 

equation: 

%*R f

 - 100 (1.0 - [ I (%Spj/GCVpj) Lp j]/[ £ (%Srj/GCVr1) l_ri]} Eq. 19-22 

where: 

%S„, %Sr=sulfur content of the product and 

raw fuel lots, respectively, dry basis 

weight percent. 

GCVD, GCVr=gross calorific value for the 

product and raw fuel lots, respectively, 

dry basis, kg/kg (Btu/lb). 

Lp, L,=weight of the product and raw fuel 

lots, respectively, metric ton (ton). 

n = number of fuel lots during the averaging 

period. 

Note: In calculating %R,. include %S and 

GCV values for all fuel lots that are not 

pretreated and are used during the averaging 

period. 

5.2.1 Solid Fossil (Including Waste) FuelSampling and Analysis. 

Note: For the purposes of this method, raw 

fuel (coal or oil) is the fuel delivered to the 

desulfurization (pretreatment) facility. For oil. 

the input oil to the oil desulfurization process 

(e.g., hydrotreatment) is considered to be the 

raw fuel. 

5.2.1.1 Sample Increment Collection. Use 

ASTM D2234-76 (IBR—see § 60.17), Type I, 

Conditions A, B, or C, and systematic 

spacing. As used in this method, systematic 

spacing is intended to include evenly spaced, 

increments in time or increments based on 

equal weights of coal passing the collection 

area. 

As a minimum, determine the number and 

weight of increments required per gross 

sample representing each coal lot according 

to Table 2 or Paragraph 7.1.5.2 of ASTM 

D2234-76. Collect one gross sample for each 

lot of raw coal and one gross sample for each 

lot of product coal. 

5.2.1.2 ASTM Lot Size. For the purpose of 

Section 5.2 (fuel pretreatment), the lot size of 

product coal is the weight of product coal 

from one type of raw coal. The lot size of raw 

coal is the weight of raw coal used to 

produce one lot of product coal. Typically, 

the lot size is the weight of coal processed in 

a 1-day (24-hour) period. If more than one 

type of coal is treated and produced in 1 day, 

then gross samples must be collected and 

analyzed for each type of coal. A coal lot size 

equaling the 90-day quarterly fuel quantity 

for a steam generating unit may be used if 

representative sampling can be conducted for 

each raw coal and product coal. 

Note: Alternative definitions of lot sizes 

may be used, subject to prior approval of the 

Administrator. 

5.2.1.3 Gross Sample Analysis. Use ASTM 

D2013-72 to prepare the sample, ASTM 

D3177-75 or ASTM D4239-85 to determine 

sulfur content (%S), ASTM D3173-73 to 

determine moisture content, and ASTM 

D2015-77 or ASTM D3286-85 to determine 

gross calorific value (GCV) (all methods cited 

IBR—see § 60.17) on a dry basis for each 

gross sample. 

5.2.2 Liquid Fossil Fuel—Sampling and 

Analysis. See Note under Section 5.2.1. 

5.2.2.1 Sample Collection. Follow the 

procedures for continuous sampling in ASTM 

D270-65 (Reapproved 1975) (IBR—see § 60.17) 

for each gross sample from each fuel lot. 

5.2.2.2 Lot Size. For the purpose of Section 

5.2 (fuel pretreatment), the lot size of a 

product oil is the weight of product oil from 

one pretreatment facility and intended as one 

shipment (ship load, barge load, etc.). Tho lot 

size of raw oil is the weight of each crude 

liquid fuel type used to produce a lot of 

product oil. 

Note: Alternative definitions of lot sizes 

may be used, subject to prior approval of the 

Administrator. 

5.2.2.3 Sample Analysis. Use ASTM 

D129-64 (Reapproved 1978), ASTM D1552-83, 

or ASTM D4057-81 to determine the sulfur 

content (%S) and ASTM D240-78 (all methods 

cited IBR—see § 60.17) to determine the GCV 

of each gross sample. These values may be 

assumed to be on a dry basis. The owner or 

operator of an affected facility may elect to 

determine the GCV by sampling thu oil 

combusted on the first steam generating unit 

operating day of each calendar month und 

then using the lowest GCV value of tho three 

GCV values per quarter for the GCV of all oil 

combusted in that calendar quurter. 

5.2.3 Use appropriate procedures, subject 

to the approval of the Administrator, to 

determine the fraction of total mass input 

derived from each type of fuel. 

5.3 Control Device Removal Efficiency. 

Compute the percent removal efficiency ("',R0 
47856 Federal Register / Vol. 52, No. 241 / Wednesday, December 16, 1987 / Rules and Regulations 

of the control device using the following 

equation: 

%Rg=100[1.0-Eoo/Eal] Eq. 19-23 

where: 

Eao. Eal = average pollutant rate of the control 

device, outlet and inlet, respectively, for 

the performance test period, ng/J (lb/ 

million Btu). 

5.3.1 Use continuous emission monitoring 

systems or test methods, as appropriate, to 

determine the outlet SO2 rates and, if 

appropriate, the inlet SO2 rates. The rates 

may be determined as hourly (E*,) or other 

sampling period averages (Ed). Then, compute 

the average pollutant rates for the 

performance test period (Eao and Eai) using 

the procedures in Section 4. 

5.3.2 As an alternative, as-fired fuel 

sampling and analysis may be used to 

determine inlet SO2 rates as follows: 

5.3.2.1 Compute the average inlet S02 rate 

(Ed-) for each sampling period using the 

following equation: 

Edi=K (%S/GCV) Eq. 19-24 

where: 

Edi=average inlet SO2 rate for each sampling 

period d, ng/J (lb/million Btu) 

% S=sulfur content of as-fired fuel lot, dry 

basis, weight percent. 

GCV = gross calorific value of the fuel lot 

consistent with the sulfur analysis, kj/kg 

(Btu/lb). 

K = 2xlO'[(kg)(ng)/(%)(J)]{2xl04(lb)(Btu/ 

(%))(million Btu)} 

After calculating Edi use the procedures in 

Section 4.2 to determine the average inlet SO2 

rate for the performance test period (Eai). 

5.3.2.2 Collect the fuel samples from a 

location in the fuel handling system that 

provides a sample representative of the fuel 

bunkered or consumed during a steam 

generating unit operating day. 

For the purpose of as-fired fuel sampling 

under Section 5.3.2 or Section 6, the lot size 

for coal is the weight of coal bunkered or 

consumed during each steam generating unit 

operating day. The lot size for oil is the 

weight of oil supplied to the "day" tank or 

consumed during each steam generating unit 

operating day. 

For reporting and calculation purposes, the 

gross sample shall be identified with the 

calendar day on which sampling began. For 

steam generating unit operating days when a 

coal-fired steam generating unit is operated 

without coal being added to the bunkers, the 

coal analysis from the previous "as 

bunkered" coal sample shall be used until 

coal is bunkered again. For steam generating 

unit operating days when an oil-fired steam 

generating unit is operated without oil being 

added to the oil "day" tank, the oil analysis 

from the previous day shall be used until the 

"day" tank is filled again. 

Alternative definitions of fuel lot size may 

be used, subject to prior approval of the 

Administrator. 

5.3.2.3 Use ASTM procedures specified in 

Section 5.2.1 or 5.2.2 to determine the sulfur 

contents (%S) and gross calorific values 

(GCV). 

ft Sulfur Retention Credit for Compliance 

Fuel 

If fuel sampling and analysis procedures in 

Section 5.2.1 are being used to determine 

average S02 emission rates (Ea5) to the 

atmosphere from a coal-fired steam 

generating unit when there is no SO2 control 

device, the following equation may be used to 

adjust the emission rate for sulfur retention 

credits (no credits are allowed for oil-fired 

systems) (Edl) for each sampling period using 

the following equation: 

Edi=0.97 K (%S/GCV) Eq. 19-25 

where: 

Edi = average inlet SO2 rate for each sampling 

period d, ng/J (lb/million Btu) 

%S = sulfur content of as-fired fuel lot, dry 

basis, weight percent. 

GCV=gross calorific value of the fuel lot 

consistent with the sulfur analysis, kj/kg 

(Btu/lb). 

K = 2x 107|(kg)(ng)/(%)(J)] {2X 10<(lb)(Btu/ 

(%))(million Btu)} 

After calculating Edi use the procedures in 

Section 4-2 to determine the average SO2 

emission rate to the atmosphere for the 

performance test period (Eao). 

7. Determination of Compliance When 

Minimum Data Requirement Is Not Met 

7.1 Adjusted Emission Rates and Control 

Device Removal Efficiency. When the 

minimum data requirement is not met, the 

Administrator may use the following adjusted 

emission rates or control device removal 

efficiencies to determine compliance with the 

applicable standards. 

7.1.1 Emission Rate. Compliance with the 

emission rate standard may be determined by 

using the lower confidence limit of the 

emission rate (Ea0*) as follows: 

Ea„*=Eao-to.95S0 Eq. 19-26 

where: 

S0 = standard deviation of the hourly average 

emission rates for each performance test 

period, ng/J (lb/million Btu). 

to.95=values shown in Table 19-2 for the 

indicated number of data points n. 

7.1.2 Control Device Removal Efficiency. 

Compliance with the overall emission 

reduction (%R„) may be determined by using 

the lower confidence limit of the emission 

rate (Ea0*) and the upper confidence limit of 

the inlet pollutant rate (E,,*) in calculating the 

control device removal efficiency (%RB) as 

follows: 

%R,=100[1.0-E.o*/E,i*] Eq. 19-27 

Eai* = Eai + to.95S, Eq. 19-28 

where: 

S| = standard deviation of the hourly average 

inlet pollutant rates for each 

performance test period, ng/J (lb/million 

Btu). 

TABLE 19-2.—VALUES FOR T0 9 5 

n

1 

2 

3 

4 

5 

6 

7 

to .95 

6.31 

2.42 

2.35 

2.13 

2.02 

1.94 

n

1 

8 

9 

10 

11 

12-16.. 

17-21.. 

to .95 

1.89 

1.86 

1.83 

1.81 

1.77 

1.73 

> 

n

1 

22-26.. 

27-31.. 

32-51.. 

59-91.. 

92-

151. 

152 

or 

more 

to .95 

1.71 

1.70 

1 m 

1.67 

1 66 

1.65 

1

 The values of this table are corrected lor 

n-1 degrees of freedom. Use n equal to the 

number (H) of hourly average data points. 

7.2 Standard Deviation of Hourly Average 

Pollutant Rates. Compute the standard 

deviation (Sc) of the hourly average pollutant 

rates using the following equation: 

-\/(i/H) - (I/H ) { A r 

V j=l 

(E hj - Ea)

2

]/(H 1) ) Eq. 19-29 

where: 

S = standard deviation of the hourly average 

pollutant rates for each performance test 

period, ng/J (lb/million Btu). 

Hr= total numbers of hours in the 

performance test period (e.g., 720 hours 

for 30-day performance test period). 

Equation 19-29 may be used to compute the 

standard deviation for both the outlet (S„) 

and, if applicable, inlet (Sj) pollutant rates. 

[FR Doc. 87-28216 Filed 12-15-87;.8:45 am) 

BILLING CODE 6560-50-M