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OAR Box 1865 

Prepped by Charmelle Mathews 

Document Number: 

56) IV-H-3 

Docket Number: 

A-83-27 

Printed 12/3/2008 9:15:29 AM Sheet 56 of 105 
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A-83-27 

CORPORATION IV-H-3 

December 16, 1987 

MEMORANDUM 

SUBJECT: Final Performance Standards (S02) for Industrial-Commercial' 

Institutional Steam Generating units (Subpart Db) 

FROM: David M. White J^Vic ) VAvvAt > 

Radian Corporation 

TO: File 

The attached draft documents were submitted to the Office of Management 

and Budget for their review under the Paperwork Reduction Act and 

Executive Order 12291 on October 19, 1987. 

3 attachments 

Progress Center/3200 E. Chapel Hill Rd./Nelson Hwy./P.O. Box 13000/Research triangle Park. N.C 27709/(919)541-9100 
6560-50 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 60 

(AD-FRL- ) 

STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES 

Industrial-Commercial-Institutional Steam Generating Units 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Final Rule. 

SUMMARY: Standards of performance under Subpart Db of 40 CFR 60 

limiting emissions of sulfur dioxide (SO*) from coal- and oil-fired 

industrial-commercial-institutional steam generating units and particulate 

matter (PM) from oil-fired industrial-commercial-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 60, 

Appendix A. 

Standards of performance limiting emissions of nitrogen oxides (NO ) 

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 SO-, NO , and PM is included in today's notice. This combined text is 

provided as a convenience to the reader and is M £ a repromulgation of the 

previously promulgated standards for NOx 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. 
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These standards implement Section 111 of the Clean Air Act and are 

based on the Administrator's determination that industrial-commercialinstitutional 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-commercial-institutional steam 

generating units to reduce emissions of S0~ 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: (date of publication 1n FEDERAL REGISTER). 

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 1n civil or criminal proceedings 

to enforce these requirements. 

INCORPORATION BY REFERENCE: The Incorporation by reference of certain 

publications in these standards 1s approved by the Director of the Office of 

the FEDERAL REGISTER as of (date of publication 1n the FEDERAL 

REGISTER). 

ADDRESSES: Docket. Docket number A-83-27, containing information 

used in development of the standards, 1s available for public Inspection 

between 8:00 a.m. and 4:00 p.m. Monday through Friday at the Central Docket 
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Section (LE-131), South Conference Center, Room 4, 401 M Street, S.W., 

Washington, D.C. 20460. A reasonable fee may be charged for copying. 

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. 

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. Docket 

D. Clean Air Act Procedural Requirements 

E. Office of Management and Budget Reviews 

F. Regulatory Flexibility Act Compliance 
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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 mixtures, or coal or oil 

with any other fuels. 
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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 SO* 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 SO- 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. 
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(4) Steam generating units combusting coal and using an emerging SO* 

control technology must achieve a 50 percent reduction in potential S0-

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 SO* 

control technology must achieve a 50 percent reduction in potential SO* 

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 tp an emission limit of 130 ng/J (0.3 lb/mill ion Btu) heat input. 

(7) Fluidized bed combustion (FBC) steam generating units combusting 

coal refuse must achieve an 80 percent reduction in potential SO* 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 1b/mi111 on 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 residual 

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 SOg emission monitoring is required for all coal- and 

oil-fired steam generating units. The SO* 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 1s allowed both as an alternative SO* 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 S0-

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. 
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C. Particulate M*tt»r standards 

For steam generating units firing oil, either alone or in combination 

with other fuels, the particulate matter emission limit 1s 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, 1s 20 percent opacity (6-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 tht 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 would be 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 1s required for all steam generating units except as 

provided for by the General Provisions (S60.11(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 

SO* emissions that were Included 1n 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, SO- 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 combusting coal or oil, Including 

both mixed-fuel-fired applications and fossil-fuel-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 1n 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 1n SO* emissions. This less stringent 

provision was not Included 1n 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 content residual oil from percent reduction 

requirements. 

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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, SO* 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 SO*, 

N0X, and PM calculation procedures and addresses both steam generating units 

using S02 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 SO* 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 SO* 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 

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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 impacts associated with the final standards recommended 

for promulgation are summarized in Tables 1 and 2. Table 1 summarizes 

national Impacts and Table 2 summarizes impacts on typical steam generating 

units. 

NOTE TO GPO TYPESETTER: Please put these tables 1n two columns 

immediately following the preceding line of text. 

TABLE 1. NATIONAL IMPACTS 

AIR EMISSION REDUCTIONS 

Sulfur Dioxide, thousand tons/yr 

Particulate Matter, thousand tons/yr 

LIQUID & SOLID WASTES GENERATED 

Liquid Wastes, million cubic ft/yr 

Solid Wastes, thousand tons/yr 

ENERGY IMPACTS 

Increase in Natural Gas Use, trillion Btu/yr 

COST IMPACTS 

Total Annualized Cost, million $/yr 

Average Cost Effectiveness, $/ton 

Incremental Cost Effectiveness, $/ton 

JFQAM. 

130-360 

9-24 

negligible 

negligible 

110-310 

5-50 

40-130 

0 

SALES DATA 

140 

3 

53 

270 

0 

120 

890 

1400 

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860 

750 

1900 

920 

1200 

1200 

TABLE 2. TYPICAL STEAM GENERATING UNIT IMPACTS 

Smalla Large 

AIR EMISSION REDUCTIONS 

Sulfur Dioxide, tons/yr 1200 780 

Particulate Matter, tons/yr 54 0 

LIQUID & SOLID WASTES GENERATED 

Liquid Wastes, million cubic ft/yr 1.3 

Solid Wastes, thousand tons/yr -- 2.7 

COST IMPACTS 

Total Annualized Cost, thousand S/yr 

Average Cost Effectiveness, $/ton 

Incremental Cost Effectiveness, $/ton 

a Based on 150 million Btu/hr oil-fired steam generating unit 

firing a low sulfur oil, operating at 55 percent annual 

capacity factor, and using a sodium FGD system to reduce SO* 

emissions, compared to a unit subject to SO* emission limits 

under a typical State implementation plan. 

Based on a 400 million Btu/hr coal-fired steam generating 

unit firing medium sulfur coal, operating a 60 percent annual 

capacity factor, and using lime spray drying FGD, compared to 

a unit subject to Subpart D. 

Projected national impacts associated with the standards can vary 

considerably depending on the approach used to estimate these Impacts. The 

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 industrial-commercial -

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 

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generating unit, the total cost associated with each type of fuel that could 

be fired, including the costs to comply with standards limiting SO* 

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 S02 emissions. 

Using this approach, "fuel switching" from coal or oil to natural gas can 

occur in response to standards limiting SO* emissions. For example, in the 

absence of SO* standards, it may be less expensive to combust coal or oil 

than natural gas. With SO* 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 SO* emission reductions. 

The type of fuel projected by IFCAM to be fired 1n 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. 

Impacts of the final standards recommended for promulgation on typical 

steam generating units are summarized in Table 2. These impacts ignore the 

possibility of fuel switching and assume that a new steam generating unit 

which would fire coal or oil 1n the absence of standards will continue to fire 

coal or oil when faced with standards, regardless of the costs involved. The 

actual cost impacts would be lower and emission reductions higher if fuel 

switching had been assumed to occur. 

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A number of commenters noted 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 alternative approach was also 

used to estimate national impacts (shown under the "SALES DATA" column in 

Table 1). 

This alternate approach is similar to that used to estimate the impacts 

on typical steam generating units. It 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 industrial-commercialinstitutional 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 

and no fuel switching is assumed to occur in response to standards limiting 

SO- emissions. The results are then aggregated to yield an alternative 

estimate of national impacts. 

As shown in Tables 1 and 2, the final standards result in significant 

reductions in S02 emissions from new industrial-commercial-institutional 

steam generating units on both a national and an individual basis. Tables 1 

and 2 show 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 SO* standards 

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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 SO* 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 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 and typical steam generating unit impacts 

summarized in Tables 1 and 2, 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 1n 1990, assuming "full cost 

pass-through" of all increased costs associated with standards requiring a 

percent reduction in SO* emissions at all steam generating units firing coal 

or oil. Assuming "full cost absorption," return on assets was projected to 

decrease by 0.03 to 2.8 percentage points. 

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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 1n 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. 

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P.20 

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 proposed 

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 1n the following 

areas: Applicability, Basis of Standard, Standard for SO-, 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 BID, which is referred to 

in the ADDRESSES section of this preamble. The summary of comments and 

responses discussed below, as well as 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 that steam generating units operating at 

low capacity utilization rates for oil or coal should be exempted from the 

S 02 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 S02 control 

18 
P.21 

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, units that are operated infrequently to provide 

"backup" steam or to meet seasonal demands, mixed-fuel-fired steam 

generating units burning small amounts of coal or oil, and nonfossil-fuelfired 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 of this issue 

indicate there are a number of site-specific factors that the previous 

analysis overlooked which can cause plants to install low capacity factor 

coal- or oil-fired steam generating units rather than "fuel switch" to 

natural gas. Such factors include particularly attractive local prices for 

these fuels, which are not reflected in projections of national fuel prices, 

or the existence of the "infrastructure" for handling coal or oil at an 

existing plant (I.e., coal or oil handling and storage facilities are 

already available). 

Factors such as these could make the installation of a new low capacity 

factor coal- or oil-fired steam generating unit more attractive than the 

analysis indicated. In fact, such factors could be of such significance 

that some steam generating unit owners or operators would not fuel switch to 

natural gas, despite promulgation of standards requiring a percent reduction 

in emissions from coal- and oil-fired steam generating units. These low 

capacity factor coal- or oil-fired steam generating units could experience 

unreasonably high cost effectiveness values if required to achieve a percent 

reduction in emissions. 

19 
P.22 

To avoid imposing emission control requirements that could result in 

high cost effectiveness levels, the final standards provide an exemption 

from the percent reduction requirement for coal- and oil-fired steam 

generating units, as well as mixed-fuel-fired steam generating units, which 

obtain 30 percent or less of their rated annual heat input capacity from the 

combustion of oil and coal, provided the owner or operator or the source has 

obtained a Federally enforceable permit limiting the annual capacity factor 

of the unit for coal and oil to 30 percent or less. If a decision is 

subsequently made to operate the steam generating unit at higher loads, 

compliance with the percent reduction requirement would be necessary. 

These "low capacity factor" steam generating units would, however, be 

required to meet certain emission limits. Emissions of SO- 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/mill1on Btu) If'oil 1s fired. 

Continuous emission monitoring (or fuel sampling and analysis), continuous 

compliance provisions, and quarterly reporting are required for all units, 

including these "low capacity factor" units. 

Other commenters requested that an exemption from the percent reduction 

requirement be granted for steam generating units burning anthracite coal or 

anthracite mining waste (culm), as was done in Subpart Da for electric 

utility steam generating units. Some 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 

20 
P.23 

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 SO- control system. 

The smaller coal demand in the industrial-commercial-institutional 

steam generating unit market is unlikely to result in utility-scale mine 

reclamation even if an exemption from the percent reduction requirement were 

granted for anthracite. 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 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 

21 
P24 

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 

the 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 SO* 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 

22 
P.25 

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 A1r Act was intended 

to apply to utility steam generating units only, and 1s not appropriate for 

industrial-commercial-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 

fol1ows: 

"(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 

(11) 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 subject to treatment prior to 

combustion." 

Although the discussion of the percentage reduction requirement in the 

legislative history sometimes refers to particular types of fossil-fuelfired 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 

23 
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. 

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 111 gives the Agency the flexibility 

to forego a percentage reduction where there 1s 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 1t solves. Several commenters 

said that an emission limit only, rather than a percent reduction 

24 
P.27 

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. However, as discussed throughout this rulemaking, a thorough 

analysis of the economic, environmental, and energy impacts associated with 

the standard was conducted, and no unreasonable impacts were identified for 

the final standards. Therefore, the final standard promulgated under 

Section 111 is considered reasonable. 

The percent reduction requirement does not force a source to install 

any particular technological system of SO* emission reduction. It 1s simply 

a performance standard that 1s based on the performance capabilities of the 

"best demonstrated technology." Sources are free 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 S0-

control technology. They felt that a lower percent reduction requirement 

would allow the use of less expensive technologies, achieve comparable S02 

control, and foster increased coal use in the future. 

The issue of regulatory compliance flexibility of a 90 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 S02 control 

25 
P.28 

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 for 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 SO* 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 SO* 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 fuel 

is applicable. 

To provide some flexibility and to encourage the development of 

alternative SO* control technologies, a percent reduction requirement of 

50 percent has been established for emerging technologies. This provision 

was discussed in the preamble to the proposed standards and is retained in 

the final standards and 1s discussed in more detail below. 

Several commenters said the requirements in the Subpart Da electric 

utility NSPS should be the most stringent scenario considered for 

industrial-commercial-institutional steam generating units. They said there 

is no reason Industrial-commercial-Institutional units should be regulated 

more stringently than utility units. 

Direct comparison of the standard for industrial-commercial -

institutional steam generating units with the utility standard promulgated 

26 
P.29 

in 1979 is inappropriate for several reasons. First, the Subpart Da 

standard was adopted almost 10 years ago and, therefore, does not 

necessarily reflect current technological capabilities or regulatory 

considerations. 

Second, the design and operating characteristics of utility steam 

generating units and emission control systems are different from 

industrial-commercial-institutional units. Utility steam generating units 

are generally much larger. A typical 500 MW 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) for a typical industrialcommercial -institutional unit, a 30-fold difference in size. Because of 

their large size, utility steam generating units and FGD systems are field 

erected and are usually custom designed for a specific site. Long-term fuel 

purchase contracts for up to 20 years are common. As a result, utility 

steam generating units and FGD systems can be designed to optimize site- and 

fuel-specific factors. Also, to handle the large quantities of flue gas 

generated, utility FGD systems typically consist of multiple parallel FGD 

modules (typically 4 or 5 modules), with each capable of handling part of 

the total flue gas. To ensure operating reliability of the total FGD 

system, an additional FGD module is frequently installed as a spare or 

backup module to be available during periods of FGD malfunction or for 

rotation during preventive maintenance and servicing of other FGD modules. 

In contrast, industrial-commercial-institutional steam generating units 

and FGD systems are likely to be shop-assembled based on standard designs 

and have the ability to handle a wider range of fuels than typical utility 

27 
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. 

Third, at the time Subpart Da was promulgated, lime/1Imestone 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 concerns existed about the ability of these 

newer technologies to achieve high SO* reductions on a reliable basis. 

Today, a number of demonstrated FGD technologies are available for use by 

industrial-commercial-institutional steam generating units including sodium 

scrubbing, 11me spray drying, and dual alkali FGD systems, as well as 

fluidized bed combustion. Based on experience gained with these 

technologies during the past decade, as well as various technical advantages 

of these technologies over wet lime/limestone FGD, industrial FGD systems 

are expected to be more efficient and reliable than utility FGD systems were 

at the time Subpart Da was adopted. 

Because of the many differences between Industrial-commercialinstitutional and utility steam generating units, it is inappropriate to 

conclude that the standards being adopted today must mimic Subpart Da. 

Some commenters said the proposed SO* 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 

28 
P.31 

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

compliance alternatives. 

The basis for the SO* 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 SO* 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 SO*/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. 

29 
However, the final standards do exempt certain steam generating units 

from the percent reduction requirements where the impacts associated with 

the percent reduction requirements are considered unreasonable (e.g., low 

capacity factor fossil-fuel-fired steam generating units and mixed-fuelfired steam generating units). These steam generating units, however, are 

subject to an S02 emission limit, which in the case of oil-fired units is 

130 ng/J (0.3 lb S02/mi11ion Btu). 

Unlike the 86 ng/J (0.2 1b/mi11 ion 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 1s 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 1s 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 SO* 

emission limit of 130 ng/J (0.3 lb/mill1on Btu). 

In reviewing the reasonableness of applying percent reduction 

requirements to higher capacity oil-fired steam generating units, reasonable 

impacts were noted for distillate oils and most residual oils. Unreasonable 

impacts were noted, however, for applying percent reduction requirements to 

30 
P.33 

very low sulfur content residual oils. Thus, the final standards exempt 

from percent reduction requirements steam generating units firing very low 

sulfur content residual oils with SO* emission rates less than 130 ng/J 

(0.3 lb/million Btu) because of cost effectiveness considerations. 

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, but is actually a 

clarification of 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. 

31 
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 industrial-commercial-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-commercial-institutional steam generating units 

than will the final standards. 

Current national energy policy as reflected in a-recent report by a 

senior Federal Interagency group ("Energy Security--A Report to the 

President of the United States," U.S. Department of Energy, March 1987) 

concludes that the primary national energy security need Is to limit Imports 

of foreign oil while encouraging the use of a versatile mix of domestically 

produced fuels, including both coal and natural gas. While the standards 

may cause a larger proportion of new steam generating units to fire natural 

gas than might otherwise do so, much of this "fuel switching" will be from 

oil to gas rather than from coal to oil or coal to gas. Although some 

decrease in coal use may result, the final standards treat coal and oil in 

equivalent fashions and are therefore expected to discourage the use of 

imported oil. As a result, the promulgated standards are viewed as 

consistent with national energy policies. 

In any event, the total amount of fossil fuel demand by industrialcommercial- institutional steam generating units is a very small percentage 

of total U.S. demand, and any changes in the fuel mix in this sector will 

32 
P.35 

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 1n 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" 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 (i.e., the high oil 

penetration scenario), these revised projections of future energy prices 

33 
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, coal is projected to be fired in new units. 

An energy scenario leading to massive fuel switching from oil and 

natural gas to coal, therefore, 1s considered Improbable. Although 

improbable, such a scenario was examined at proposal (i.e., the high coal 

penetration scenario) and the potential impacts of standards requiring a 

percent reduction in emissions under such a scenario were considered 

reasonable. 

Using these revised projections of future energy prices, however, the 

potential national impacts associated with the final standards were 

examined ("Revised Impacts of Alternative Sulfur Dioxide New Source 

Performance Standards for Industrial Fossil Fuel-Fired Boilers," February 

1987). Natural gas consumption in new steam generating units 1s projected 

by IFCAM to Increase by about 120-330 PJ/yr (110-310 trillion Btu/yr) in 

1990. This represents about 1.5 to 4.5 percent of natural gas consumption 

by all industrial sources. This projected Increase in natural gas 

consumption, however, is projected to be accompanied by a similar decrease 

in national oil consumption. Coal consumption 1s not projected to be 

affected since little coal consumption by new steam generating units 1s 

projected by IFCAM even In the absence of an 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) 1n 1990. The 

corresponding national annualized costs are projected to range from $5 to 50 

million, resulting in a national average cost effectiveness of $45-150/Mg 

34 
P.37 _ 

($40-130/ton) of SO* reduction and the national incremental cost 

effectiveness associated with the final standards compared to standards 

based on the use of low sulfur fuels is projected to be negligible. 

A number of commenters have 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 

examined 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," 1987). 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 (140,000 

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 1s projected to be about 

$1,600/Mg ($l,400/ton) of S02» 

The use of revised projections of future energy prices or even the use 

of different approaches to estimate the national impacts of the final 

standards, therefore, does not alter the conclusion that the final standards 

are appropriate and 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 as "new capacity." According to the commenters, as much 

35 
P.38 

as 80 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-commercial-institutional steam generating unit market 

and a net increase in SO- 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 1s 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 steam-consuming 

industries and energy conservation efforts, but appear to have stabilized 

since 1980. 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 SO* reductions achieved by the standard 

are still considered significant, both from Individual units and from the 

source category as a whole. Also, while steam generating unit sales are 

lower than in 1970, new units are being built and will continue to be built 

in the future. As more and more units are constructed, further SO* 

reductions will be achieved by the standards being adopted today. The cost, 

environmental, and energy impacts of the final standards therefore are 

considered reasonable, even assuming lower population growth projections. 

36 
P.39 

In response to comments concerning the proportion of new steam 

generating units that are replacements for existing steam generating units, 

a survey was conducted of steam generating units ordered between January 

1981 and September 1984 ("Survey of New Industrial Boiler Projects -

1981-1984," EPA-450/3-87-006, April 1987). Responses were received for 168 

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 discussed below. Comparison with steam 

generating unit sales data collected by ABMA Indicated that these units 

represent almost all of the industrial steam generating units In this size 

category sold between 1981 and 1984. The survey indicated that about 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 the price of oil and natural gas result in 

a 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 SO* emissions 

associated with this 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, 

37 
P.40 

meaning a new unit must be installed. The above survey indicated that 

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 SO- emissions from plants Installing 

new industrial steam generating units. Analysis of SO* 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 

SO* per million Btu of fuel fired than the existing (replaced) steam 

generating units, the total annual emissions (i.e., tons/year) emitted by 

plants to 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, and (4) continued operation of 

the existing steam generating units which were "replaced" by new units. 

38 
P.41 

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 more 

sensitive to cost considerations, calculations were also made excluding 

these types of projects. Even without these significant sources of SO* 

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 S02 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 SO- 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 SO* 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 

SO- emissions from new industrial-commercial-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. 

39 
P.42 

E. Cost of the Standard 

Several commenters felt that the 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 ignoring economies of scale resulted in 

the capital costs being greatly underestimated. Other commenters stated 

that the cost estimates did not adequately consider costs associated with 

sludge disposal, the need for backup SO- 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. 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 1n 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 1n 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. 

40 
P.43 

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. 

41 
P.44 

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 analyses considered the increased 

costs necessary to address reliability problems. 

The coal prices used in the cost analyses were also developed 

specifically for industrial-commercial-institutional 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-commercial-institutional steam generating units, 

and these costs were carefully considered 1n 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 A1r 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 SO* 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 1n emissions and 

costs among increasingly stringent alternatives. Varying assumptions 

42 
P.45 

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 1s 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 

43 
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 SO* emissions from industrial-commercial-institutional steam 

generating units. This is because sodium scrubbing is generally less 

expensive than other FGD technologies for many industrial-commercialinstitutional 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 SO* 

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 SO* control system varied 

by less than 10 percent for all technologies examined. However, when only 

the cost associated with SO* control was considered, this variation was much 

larger, ranging from 30 to 100 percent. Therefore, because of variations 1n 

project-specific factors that could influence the choice of S02 control 

system, the use of any single technology as a "surrogate" for all types of 

SO* control systems in cost analyses was judged to be Inappropriate. 

Consequently, "generic" FGD cost estimates were developed to represent the 

44 
P.47 

midpoint in the range of cost estimates for several types of industrial S0~ 

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 from coal or oil 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. 

45 
P.48 

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 gas 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 from firing coal or oil to firing an alternative fuel during 

periods of malfunction were included in the cost analyses. For all model 

steam generating unit sizes analyzed (100, 150, 250 and 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 1n terms of additional S02 control. 

F. Performance/Reliability of Demonstrated Technologies 

Many commenters said there is inadequate proof that there are 

demonstrated SO* 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 

46 
P.49 

units, which have totally different design and operation requirements than 

industrial units. Other commenters questioned the adequacy of the data base 

for SO* 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 "SO- 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 SO* 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 coal-fired steam generating units have shown short-term SO* 

removal efficiencies of greater than 90 percent, with long-term efficiencies 

47 
P.50 

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 

SO* removal levels with lime spray drying, short-term tests resulting in 

greater than 90 percent SO- removal indicate this process is capable of 

achieving these performance levels. Current long-term removal rates of 60 

to 80 percent reflect the fact that these systems have not been required to 

achieve high removal levels, rather than any Inherent limitation on the 

technology. This is supported by the willingness of vendors of lime spray 

drying systems to guarantee long-term SO- removal performance of 90 percent. 

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/Hmestone FGD system, the SO* 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. 

48 
P.51 

Performance test data also demonstrate that FBC technology is capable 

of achieving 90 percent SO- removal at high reliabilities. A recent 30-day 

test on a bubbling bed FBC unit burning high sulfur coal (4000 ng S0-/J, 9.3 

lb/million Btu) showed SO* 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 SO* removal at high reliability levels. 

Consequently, the ability of FGD and FBC systems to achieve a 90 

percent SO* 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 SO- reduction at high reliability levels. 

Commenters also questioned the adequacy of the data base for S0-

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 

49 
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, SO* 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 SO* loading. This 

can result from an increase in either the flue gas flow rate or the flue gas 

SO* concentration. As discussed in the "SO* 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 1s 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 S02 loadings typically operate at high alkaline 

reagent concentrations. This provides a buffering capacity against large 

swings in solution pH caused by dramatic changes in S02 concentration. As a 

result, sufficient excess alkaline reagent 1s present to ensure adequate SO* 

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 

50 
P.53 

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 "S02 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. SO* 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 11me 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 

51 
P.54 

typically operated at moderate performance levels, there is no reason to 

believe lime spray dryers cannot maintain high reliabilities achieving 90 

percent SO* 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) 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. 

Also as discussed above, the reliability of FBC systems has also been 

demonstrated in both long- and short-term tests in industrial applications. 

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 

SO* removal levels. To allow continued steam generating unit operation 

during periods of FGD system malfunction, backup FGD modules, common 1n 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. 

52 
P.55 

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 SO* removal efficiencies 

during combustion of low sulfur fuels is determined by the concentration of 

SO* in the flue gas exiting the FGD system. Test data from sodium and lime 

spray drying FGD systems and from FBC systems indicate S02 emissions of less 

than 15 ppm (equal to roughly 13 ng/J or 0.03 lb/m1H1on Btu) are 

achievable; in some tests, SO- 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/mill1on 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 1n 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 

53 
P.56 

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 or 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 

54 
P.57 

standards require the use of any particular FGD system or SO* 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 confronted with the standard may view 

the "burden" of using these control technologies as excessive, "fuel 

switching" to natural gas can be employed. In this manner, the necessity of 

using these SO- control technologies can be avoided. 

As discussed throughout the "Background Information Document," the "SO* 

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 SO* 

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, 1s 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" S02 control systems 

(i.e., lime spray drying or FBC) to firing natural gas. 

Other commenters expressed concern about the 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, 

55 
P.58 

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 SO* 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 generate less than twice as 

much solid waste as the use of low sulfur coal alone, rather than fifteen 

times as suggested by the commenters. For example, a typical 44 MW (150 

million Btu/hour) steam generating unit firing low sulfur coal 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 1n S02 

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 1n 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 

56 
P.59 

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 SO* 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, such as natural 

gas, 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 SO* 

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 SO- at 

57 
P.60 

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 SO* 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 SO* 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 SO* 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 

mixed-fuel-fired steam generating units results 1n very small reductions in 

costs while allowing significant increases in SO- emissions. As a result, 

the incremental cost effectiveness of the additional reduction in S0-

emissions achieved by not providing emission credits 1s 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 

58 
P.61 

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 SO- Emission Credits for 

Cogeneration Systems," and "Impact of New Fuel Prices on S02 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 S02 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 $220-660/Mg ($200-600/ton). These costs are considered reasonable. 

Strong economic incentives exist for use of cogeneration and the 

absence of emission credits for cogeneration systems is not expected to 

significantly reduce these incentives. Consequently, the final standards do 

not include provisions for emission credits for cogeneration systems. 

59 
P.62 

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 costs increased by 10 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 

SO- 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 fuels are not affected by the final standards. 

Finally, new coal- and oil-fired cogeneration steam generating units 

compete with new coal-fired electric utility steam generating units that are 

60 
P.63 

subject to percent reduction requirements under Subpart Da. Thus, 

application of percent reduction to coal- and oil-fired cogeneration steam 

generating units under Subpart Db could be viewed as a "neutral" position 

which treats both utility steam generating units and Industrial-commercialinstitutional cogeneration steam generating units in a similar manner. 

Consequently, the final standards treat coal- or oil-fired cogeneration 

steam generating units just like any other coal- or oil-fired steam 

generating unit. 

I. Emerging Technologies 

Several commenters said that, because emerging technologies have not 

been "adequately demonstrated" as required by the Clean A1r 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 

rEssex Chemical Corp. v. Ruckelshaus. 486 F. 2d 42 (D. C. C1r. 1973)]. 

Standards requiring a high level of performance, such as 90 percent 

reduction, without a provision for emerging technologies, would act to 

discourage continued development of some new technologies and their 

attendant economic and environmental benefits. Owners and operators of new 

steam generating units could simply view the risks of using a new and 

61 
untried emission control technology to achieve a 90 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 any increase in S02 emissions will be 

minimized. 

The final standard requiring a 50 percent reduction in SO- emissions 

while limiting emissions to 170 and 260 ng/J (0.4 and 0.6 lb/million Btu) 

heat input for oil and coal, respectively, appears to achieve this 

objective. The minimal percent reduction requirement of 50 percent should 

effectively eliminate the risk of failure for any technology which has the 

potential to ultimately reduce emissions by 90 percent. When combined with 

emission limits of 170 and 260 ng/J (0.4 and 0.6 lb/million Btu), the 

standard also minimizes SO- 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 higher percent reductions when firing higher sulfur fuels. For 

example, a technology may be Initially tested at 50 percent SO- reduction on 

a steam generating unit firing low sulfur coal, 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 of 260 ng/J (0.6 lb/million Btu). 

62 
P.65 

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 post-combustion 

cleanup. 

While the allowance of fuel pretreatment credits toward the 90 percent 

reduction requirement is considered appropriate and is allowed in the final 

standards, allowing fuel pretreatment credits toward the 50 percent 

reduction requirement for emerging technologies is contrary to the purpose 

of the emerging technology provisions. The primary objective of the 50 

percent reduction requirement is to stimulate and encourage the development 

and use of emerging S02 control technologies which show promise of achieving 

significant emission reductions in the future. Any emerging technology that 

is unable to reduce emissions by 50 percent without the use of fuel 

pretreatment credits is unlikely to have any potential for achieving S02 

removal levels of 90 percent 1n the future. 

The final standard, therefore, does not allow fuel pretreatment to be 

credited against the percent reduction requirement for emerging 

technologies. The final standard has, however, been amended to allow fuel 

pretreatment credit for emerging technologies if aJLL of the required 50 

percent reduction is achieved by the fuel pretreatment technology. This 

will serve to encourage the development of fuel pretreatment technologies 

that show promise of achieving significant (i.e., 90 percent) S0-

reductions. 

63 
P.66 

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 SO- or NO 

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 

64 
P.67 

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 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 enforcement of the 

special provisions for emerging technologies, these provisions will not be 

delegated to the States and will remain with the Agency. 

65 
P.68 

VI. ADMINISTRATIVE 

A. Outline of Additions to Subpart Db 

Subpart Db, as published in today's FEDERAL REGISTER, includes both the 

provisions for N0X and PM promulgated on November 25, 1986 (51 FR 42768) and 

the provisions for SO* and PM from oil-fired 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. 

§60.40b: revised paragraphs (b) and (c), added paragraph (g). 

§60.41b: revised and added new definitions. 

§60.42b: added entire section. 

§60.43b: added paragraph (b). 

§60.44b: no substantive changes. 

§60.45b: added entire section. 

§60.46b: no substantive changes. 

§60.47b: added entire section. 

§60.48b: no substantive changes. 

§60.49b: revised paragraph (b), added paragraphs (a)(3), (a)(4), (j), 

(k),(l),(m), and (n). 

B. Revision of Method 19 

Today's action also promulgates revisions to Method 19 of 40 CFR 60 

Appendix A. These revisions include updating, reorganizing, and combining 

the existing Method 19 and 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 

66 
P.69 

percent reduction for FGD-equipped steam generating units, and Method 19A 

was applicable to determining SO- emissions from steam generating units 

firing low sulfur content fuels without FGD controls. Method 19A included 

three alternatives for measuring S02 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 SO- emission limits and percent 

reduction requirements for electric utility steam generating units subject 

to 40 CFR 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) S02, N0X, and PM emission calculations, 2) SOpercent reduction calculations for post-combustion control, 3) SO* percent 

reduction calculations for fuel pretreatment, and 4) fuel sampling and 

analysis procedures for compliance fuel-fired 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, 

67 
P.70 

municipal solid waste, and mixtures of these fuels with other fuels in new, 

modified, or reconstructed Industrial-commercial-institutional steam 

generating units. 

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. 

68 
P.71 

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 25399). Depending on the nature of these 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 1s 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 (date of 

publication in the FEDERAL REGISTER). Section 111 of the Clean Air Act 

69 
072 

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 industrial-commercialinstitutional 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. 

70 
P.73 

F. Office of Management and Budget Reviews 

The information collection requirements associated with this regulation 

(those included in 40 CFR 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. 3501 et seq. and have been 

assigned OMB Control Number 2060-0136. 

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 costs in the fifth year after the standards go into 

effect of more than the $100 million cutoff established as the first 

criterion for a "major rule" in the Order. In accordance with the Order, an 

RIA was prepared for this regulation. The RIA reviews the benefits, costs, 

and economic impacts associated with the regulatory alternatives that were 

considered. This rule was submitted to OMB for review under Executive Order 

12291. 

G. Regulatory Flexibility Act Compliance 

The Regulatory Flexibility Act of 1980 requires the Identification of 

potentially adverse impacts of Federal regulations upon small business 

entities. The Act specifically requires the completion of a Regulatory 

Flexibility Analysis in those instances where small business impacts are 

possible. Because these standards impose no adverse economic Impacts on 

small businesses, a Regulatory Flexibility Analysis has not been conducted. 

71 
P.74 

Pursuant to the provisions of 5 U.S.C. 605(b), I hereby certify that 

this regulation will not have a significant economic impact on a substantial 

number of small entities. ^ 

LIST OF SUBJECTS IN 40 CFR PART 60 

Air pollution control, Intergovernmental relations, Reporting and 

recordkeeping requirements, Incorporation by reference, Industrialcommercial -institutional steam generating units. 

Date Administrator 

72 
P.75 

HI 

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 subparagraphs (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 adding subparagraphsf^^^^P^f 

§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), (11), (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)(1); 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)(ii); §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 

73 
P.76^ 

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; 60.41b; 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, Method 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. 

74 
(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. 

* * * * * 

(XX) ASTM D129-64 (reapproved 1978), Standard Test Method for Sulfur 

-4 

in PetrJSfeum Products (General Bomb Method), IBR approved for Appendix A to 

Part 6Q^Method 19. 

(x*| ASTM D1552-83, Standard Test Method for Sulfur in Petroleum 

ProductM(H1gh-Temperature Method), IBR approved for Appendix A to Part 60, 

u 

Methodlo_9. I 

(tfx) ASTM D1835-86, Standard Specification for Liquified Petroleum 

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

|pc) ASTM D3286-85, Standard Test Method for Gross Calorific Value of 

Solid;;Fuel by the Isothermal-Jacket Bomb Calorimeter, IBR approved for 

Appendix A to Part 60, Method 19. 

||K) ASTM D4057-81, Practice for Manual Sampling of Petroleum and 

Petroleum Products, IBR approved for Appendix A to Part 60, Method 19. 

(xx) ASTM D4239-85, Standard Test Method for Sulfur in the Analysis 

Sampliief Coal and Coke Using High Temperature Tube Furnace Combustion 

Methods, IBR approved for Appendix A to Part 60, Method 19. 

3. 40 CFR Part 60 1s amended by adding Sections 60.42b, 60.45b, and 60.47b 

and revising other sections of Subpart Db to read as follows: 

Subpart Db - Standards of Performance for Industrial-CommercialInstitutional Steam Generating Units 

75 
P.78 

Sec. 

60.40b Applicability and delegation of authority. 

60.41b Definitions. 

60.42b Standards for sulfur dioxide. 

60.43b Standards for particulate matter. 

60.44b Standards for nitrogen oxides. 

60.45b Compliance and performance test methods and procedures for sulfur 

dioxide. 

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 Industrial-CommercialInstitutional 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: 

76 
P.79 

(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) 011-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 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; 

77 
P.80 

§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) §60.44b(f) 

(2) §60.44b(g) 

(3) §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, 

78 
P.81 

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 

1n 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. 

79 
P.82 

"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 011s (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 1s 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). 

80 
P.83 

"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 

t 

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 materials) 

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 a steam generating unit. 

"Full capacity" means operation of the steam generating unit at 

90 percent or more of the maximum steady-state 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. 

81 
P.84 

"Heat transfer medium" means any material that is used to transfer heat 

from one point to another point. 

"High heat release rate" means a heat release rate greater than 730,000 

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

(70,000 Btu/hour-ft3) or less. 

"Mass-feed stoker steam generating unit" means a steam generating unit 

where solid fuel is introduced directly 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 

82 
P.85 

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 1s 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 1s 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 coal-fired 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 

83 
P.86 

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 1s not necessary for fuel to 

be combusted continuously for the entire 24-hour period. 

"Very low sulfur content residual oil" means an oil that (1) when 

combusted without post combustion SO- control has an SO* emission rate equal 

to or less than 130 ng/J (0.30 lb S0*/m1ll1on Btu), (2) has a flash point 

greater than 60°C (140°F), and (3) has a kinematic viscosity greater than 

15 centistokes at 100°C (212°F). 

"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 

84 
P.87 

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 1s 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, 1n 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 Standards for sulfur dioxide. 

(a) Except as provided 1n 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: 

Es ' <Ka H a + K b Hb>/<Ha + V 

where: 

E is the sulfur dioxide emission limit, in ng/J or lb/million Btu 

heat input, 

85 
P.88 

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

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

Ha is the heat input from the combustion of coal, in J (million Btu), 

cl 

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 1n excess of 520 ng/J 

(1.2 lb/m1llion Btu) heat input. If coal or oil 1s fired with coal refuse, 

the affected facility 1s subject to paragraph (a) or (d) of this section, as 

applicable. 

(c) On and after the date on which the performance test 1s 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 

86 
to be discharged into the atmosphere any gases that contain sulfur dioxide 

in excess of 50 percent of 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 " <Kc H c + Kd Hd>/<Hc + Hd> 

where: 

E is the sulfur dioxide emission limit, expressed 1n ng/J (lb/million 

Btu) heat input, 

Kr is 260 ng/J (0.60 lb/million Btu), 

Kd 1s 170 ng/J (0.40 lb/m1H1on Btu), 

H is the heat Input from the combustion of coal, J (million Btu), 

H. 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 subparagraphs (1), 

(2), (3), or (4) of this paragraph 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 

87 
P.90 

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 1s from the 

exhaust gases entering the duct burner; or 

(4) affected facilities combusting very low sulfur content residual 

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 other oil which emits less than 130 

ng/J (0.3 lb S02/m11lion Btu), and (3) do not combust any fuel. 

88 
P.91 

(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 of less than 50 percent are not credited toward the 

percent reduction requirement under paragraph (c) of this section. 

(i) An affected facility subject to paragraph (a), (b), or (c) of this 

section may combust oil which has a sulfur dioxide emission rate equal to or 

less than 130 ng/J (0.3 lb/mill ion Btu) heat input during periods when the 

sulfur dioxide control system 1s not being operated because of malfunction 

or maintenance of the sulfur dioxide control system, if the sulfur dioxide 

control system: 

(1) was operated during the calendar quarter and 

(2) was 1n compliance with the percent reduction requirement and 

emission limit under paragraph (a), (b), or (c) of this section, as 

applicable, when operated. 

§60.43b Standard for particulate matter. 

(a) On and after the date on which the Initial performance test 1s 

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, 

89 
P.92 

(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 1s 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 1b/m1111 on Btu) heat Input If the affected facility 

combusts coal or coal and other fuels and 

89a 
P.93 

(1) 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 capacity 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 1s 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 combusts 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 1s 

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, shall cause 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) heat Input If the affected facility 

has an annual capacity factor greater than 30 percent (0.30) for wood. 

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

90 
P.94 

(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 of the affected facility to an 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 municipal-type solid waste with 

other fuels, shall cause to be discharged Into the atmosphere from that 

affected facility any gases that contain particulate matter 1n excess of the 

following emission limits: 

(1) 43 ng/J (0.10 lb/mill1on Btu) heat input, 

(1) 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/mllllon Btu) heat input 1f the affected facility 

combusts municipal-type solid waste or municipal-type 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, 

91 
P.95 

(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 capacity factor of 30 percent (0.30) for 

municipal-type 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 paragraphs (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. 

92 
§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 in excess of the 

following emission limits: 

NOTE TO GPO TYPESETTER: Please put this table 1n one column 

immediately following the preceding line of text. 

Nitrogen oxide emission limits 

ng/J (lb/million Btu) 

Fuel/Steam generating unit type heat Input 

(1) Natural gas and distillate oil, 

except (4) 

(i) low heat release rate 43 (0.10) 

(11) high heat release rate 86 (0.20) 

(2) Residual oil 

(i) low heat release rate 130 (0.30) 

(ii) high heat release rate 170 (0.40) 

(3) Coal 

(i) mass-feed stoker 210 (0.50) 

(ii) spreader stoker and fluidized bed 

combustion 260 (0.60) 

(iii) pulverized coal 300 (0.70) 

(iv) lignite, except (v) 260 (0.60) 

(v) lignite mined in North Dakota, 340 (0.80) 

South Dakota, or Montana and 

combusted in a slag tap furnace 

(vi) coal-derived synthetic fuels 210 (0.50) 

(4) Duct burner used in a combined 

cycle system 

(i) natural gas and distillate oil 86 (0.20) 

(ii) residual oil 170 (0.40) 

93 
P.97 

(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„rt H I + (ELrn H I + (EL„ Hr)]/(Hnft + ti + H J n

 x go go' ro ro7 v c c' go ro c' 

where: 

E is the nitrogen oxides emission limit, ng/J (lb/million Btu) 

EL is the appropriate emission limit from paragraph (a)(1) for 

combustion of natural gas or distillate oil, ng/J (lb/million Btu) 

H is the heat input from combustion of natural gas or distillate oil, 

EL is the appropriate emission limit from paragraph (a)(2) for 

combustion of residual oil, 

Hr Q is the heat input from combustion of residual oil, 

ELC is the appropriate emission limit from paragraph (a)(3) for 

combustion of coal, and 

H 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 

94 
P.98 

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 1s 

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 1b/mi111on 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 

95 
P.99 

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: 

E„ - t(EL„n

 Hn*) + (Ek* H,J + (EL„ HJ]/(H„A + H + H J n

 tx go go7 v ro ro7 x c c/J' v go ro c' 

where: 

E is the nitrogen oxides emission limit, ng/J (lb/million Btu) 

EL is the appropriate emission limit from paragraph (a)(1) for 

combustion of natural gas or distillate oil, ng/J (lb/million 

Btu). 

H is the heat input from combustion of natural gas, distillate oil 

and gaseous byproduct/waste, ng/J (lb/million Btu). 

ELr o is the appropriate emission Hmit from paragraph (a)(2) for 

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

H is the heat Input from combustion of residual oil and/or liquid 

byproduct/waste. 

EL is the appropriate emission limit from paragraph (a)(3) for 

combustion of coal, and 

H 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 

96 
p.1 

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 

facility-specific nitrogen oxides emission limit under this section shall: 

(1) demonstrate compliance with the emission limits for natural gas 

and distillate oil in paragraph (a)(1) or for residual oil in paragraph 

(a)(2), 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 1s unable to comply with 

the emission limits for natural gas and distillate oil 1n paragraph (a)(1) 

or for residual oil in paragraph (a)(2), 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 subparagraph (1). 

(2) The nitrogen oxides emission limits for natural gas or distillate 

oil in paragraph (a)(1) or for residual oil in paragraph (a)(2), 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 

97 
P.2 

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 261 or 40 CFR 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 hazardous waste specified 1n 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) or for 

residual oil in paragraph (a)(2), as appropriate, are applicable to the 

affected facility until and unless the petition 1s approved by the 

Administrator. (See 40 CFR 761.70 for regulations applicable to the 

incineration of materials containing polychlorlnated biphenyls (PCB's).) 

98 
P.3 

(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 (% P ) and the sulfur dioxide emission rate 

(E$) pursuant to§50.42b 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. 

99 
(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 (EL ) and the 30-day average emission rate 

(Eart)-

 Tne hourly averages used to compute the 30-day averages are obtained 

do 

from the continuous emission monitoring system of §60.47b(a) or (b). 

(ii) The percent of potential sulfur dioxide emission rate (% P ) 

emitted to the atmosphere is computed using the following formula: 

% Ps = 100 (1 - % Rg/100)(l - % Rf/100) 

where: 

% R is the sulfur dioxide removal efficiency of the control device 

as determined by Method 19, in percent. 

% Rr 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 (En o°) 1s used in 

Equation 19-19 of Method 19 to compute an adjusted 30-day average emission 

rate (Ea o ° )- The Eh ° is computed using the following formula: 

where: 

:ho 

Eho° " tEho " V 1 " V^ k 

Ehn° ^S tn e adjusted hourly sulfur dioxide emission rate, ng/J 

(lb/million Btu). 

E. is the hourly sulfur dioxide emission rate, ng/J (lb/million Btu). 

100 
P.5 

E Is the sulfur dioxide concentration In fuels other than coal and oil 

combusted 1n 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 1s 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. 

(11) To compute the percent of potential sulfur dioxide emission rate 

(% PJ , an adjusted % R_ (% R.°) Is computed from tht adjusted E ° from 

s g g ao 

paragraph (b)(3)(1) of this section and an adjusted average sulfur dioxide 

inlet rate (E.j°) using tht following formula: 

X Rg° - 100 (1.0 - Ea o°/Ea i°) 

To compute Ea 1 °, an adjusted hourly sulfur dioxide Inlet rate (Eh1°) 

1s used. Tht E^ 0 1s computed using tht following formula: 

where: 

Ehj° Is the adjusted hourly sulfur dioxide Inlet rate, ng/J 

(lb/million Btu). 

Eh 1 1s the hourly sulfur dioxide Inlet rate, ng/J (lb/m1ll1on 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 X^ - 1.0. Owners or 

operators of affected facilities who assume X^ - 1.0 shall 

101 
P.6 

(i) determine % P$ following the procedures in paragraph (c)(2) of this 

section, and 

(11) sulfur dioxide emissions (EJ 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 X. 

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) SO-, 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) 1s used, or based on a dally 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. 

102 
P.7 

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 1s 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 1s 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 1s 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 1s required unless otherwise specified by the Administrator. 

The Initial performance test 1s to be scheduled so that the first steam 

generating unit operating day of the 30 successive steam generating unit 

operating days 1s 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 

103 
P.8 

generating unit operating days, except as provided under paragraph (d). A 

separate performance test 1s 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 (1) of this section, the owner 

or operator of an affected facility shall use all valid sulfur dioxide 

emissions data in calculating % P$ and E h o 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 % P. and E. pursuant to paragraph (c) of this 

section. 

(1) During periods of malfunction or maintenance of the sulfur dioxide 

control systems when oil is combusted as provided under §60.42b(1), emission 

data are not used to calculate % P or E under §60.42b(a), (b) or (c), 

however, the emissions data are used to determine compliance with the 

emission limit under §60.42b(1). 

§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. 

104 
P.9 

(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. 

104a 
P.10 

(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 

desulfurizatlon (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 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 1s used to select the sampling site and the number of 

traverse sampling points. The sampling time for each run 1s 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). 

105 
P.11 

(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 1s 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 1s required to be completed under §60.8 of this part, whichever 

date comes first, the owner or operator of an affected facility which 

106 
p.1; 

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 the 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 1s calculated each steam generating unit operating day as the 

average of all of the hourly nitrogen oxide emission data for the preceding 

30 steam generating unit operating days. 

(4) Following the date on which the initial performance test 1s 

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 

107 
P.13 

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 (111) of 

this section apply and the provisions of paragraph (iv) of this section are 

inapplicable. 

(f) To determine compliance with the 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 

108 
P.14 

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 outlet 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 (0*) or carbon dioxide (C0~) 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 outle. 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 1n 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 location. The 

stratification test shall consist of three paired runs of a suitable sulfur 

dioxide and carbon dioxide measurement train operated at the candidate 

109 
P.15 

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 1s 

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, EQ, 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 dally 

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. 

110 
P.16 

(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 accordance with the applicable 

procedures under Performance Specifications 1, 2, and 3 (Appendix B). 

(2) Quarterly accuracy determinations and dally calibration drift 

tests shall be performed 1n accordance with Procedure 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 1s 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 control 

device is 50 percent of the maximum estimated hourly potential sulfur 

dioxide emissions of the fuel combusted. 

§60.48b Emission monitoring for particulate matter and nitrogen oxides. 

Ill 
P.17 

(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 paragraph (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 1n ng/J or lb/mill ion 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. 

112 
P.U 

(1) For affected facilities combusting coal, wood or municipal-type 

solid waste, the span value for a continuous monitoring system for measuring 

opacity shall be between 60 and 80 percent. 

(2) For affected facilities combusting coal, oil, or natural gas, the 

span value for nitrogen oxides is determined as follows: 

Span Values for 

Fuel Nitrogen Oxides (PPM) 

Natural gas 

011 

Coal 

Mixtures 

500 

500 

1,000 

500 (x + y) + l,000z 

where: 

x is the fraction of total heat Input derived from natural gas, 

y is the fraction of total heat input derived from oil, and 

z is the fraction of total heat input derived from coal. 

(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. 

113 
P.19 

(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 under control 

number 2060-0072]. 

§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)(111), §60.43b(c)(2)(ii), 

§60.43b(d)(2)(1ii), §60.44b(c), §60.44b(d), §60.44b(e), or §60.45b(d), 

114 
P.20 

(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 

115 
P.21 

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/mil Ho n 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 1s 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, 

116 
P.22 

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 1n the fuel blend. 

(f) For facilities subject to the opacity standard under §60.43b, the 

owner or operator shall maintain records of opacity. 

(g) 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 (ng/J or 

lb/million Btu heat input) measured or predicted. 

117 
P.23 

(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 Specifications 2 or 3. 

(10) Results of daily CEMS drift tests and quarterly accuracy 

assessments as required under Appendix F, Procedure 1. 

118 
P.24 

(h) The owner or operator of any affected facility 1n any category 

listed below in subparagraphs (1) or (2) of this paragraph 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 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(1)(1). 

(2) Any affected facility that is subject to the nitrogen oxides 

standard of §60.44b, and that (1) 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. 

119 
P.25 

(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 information 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 the 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 

120 
P.26 

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 Specifications 2 or 3. 

(10) Results of dally 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: 

121 
P.27 

(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 cription 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 full span of the CEMS. 

(8) Description of any modifications to the CEMS which could affect 

the ability of the CEMS to comply with Performance Specifications 2 or 3. 

122 
P.28 

(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., 

% Rr) is used to determine the overall percent reduction (i.e., % R J 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., 

% R£) was credited for the calendar quater; 

(2) Listing the quantity, heat content, and date each pretreated fuel 

shipment was received during the previous calendar quarter; the name and 

123 
P.29 

location of the fuel pretreatment facility; and the total quantity and total 

heat content of all fuels received at the affected facility during the 

previous calendar quarter; 

(3) 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.) 

124 
P.30 

4. 40 CFR Part 60, Appendix A, is amended by revising Method 19 to 

read as follows: 

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 (SO-), and nitrogen oxides (NO ) 

emission rates; (b) determining sulfur removal efficiencies of fuel 

pretreatment and SO- control devices; (c) determining overall reduction of 

potential SO- emissions from steam generating units or other sources as 

specified in applicable regulations; and (d) determining SO* rates based on 

fuel sampling and analysis procedures. 

1.2 Principle. 

1.2.1 Pollutant emission rates are determined from concentrations of 

PM, S02, or N0X , and oxygen (0-) or carbon dioxide (CO-) along with F 

factors (ratios of combustion gas volumes to heat inputs). 

1.2.2 An overall SO- emission reduction efficiency is computed from 

the efficiency of fuel pretreatment systems (optional) and the efficiency of 

SO- 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. 

125 
P.31 

1.2.4 The SO- removal efficiency of a control device is determined by 

measuring the SO- rates before and after the control device. 

1.2.5 The inlet rates to S02 control systems and when S02 control 

systems are not used, SO- 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, S02, or N0X 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: 

NOTE TO GPO TYPESETTER: Please put this table in two columns 

immediately following the preceding line of text. 

CONVERSION FACTORS FOR CONCENTRATION 

From 

g/scm 

mg/scm 

lb/scf 

ppm SOppm NO* 

ppm SO? 

ppm NO* 

To 

ng/scm 

ng/scm 

ng/scm 

ng/scm 

ng/scm 

lb/scf 

lb/scf 

Multiply by 

1 0 6 

10 13 1.602x10" 

2.66x10% 

1.912x10% 

1.660x10"i 

1.194x10"' 

126 
P.32 

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 (FJ includes 

all components of combustion less water, the wet F factor (F ) includes all 

components of combustion, and the carbon F factor (FJ includes only carbon 

dioxide. 

NOTE: Since F factors include water resulting only from the 

combustion of hydrogen 1n 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 0 2 (X02d) and pollutant (C^) concentrations, use the 

following equation: 

E - Cd Fd [20.9/(20.9 - %02 d)] Eq. 19-1 

2.2 Oxygen-Based F Factor, Wet Basis. When measurements are on a wet 

basis for both 02 (%02w) and pollutant (Cw) concentrations, use either of 

the following: 

2.2.1 If the moisture fraction of ambient air (B J 1s measured: 

E - [Cw Fw 20.9]/[20.9(l-Bwa) - %02 w ] 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 

127 
P.33 

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 = 0.027. This value may be used at any location at all 

WO 

times. 

2.2.1.2 Bu a * Highest monthly average of B... that occurred within the 

Wo Wd 

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 B - Highest daily average of B that occurred within a 

calendar month at the nearest Weather Service Station, calculated from the 

data from the past 3 years. This value shall be computed for each month and 

may be used as an estimate for the current respective calendar month. 

2.2.2 If the moisture fraction (B ) of the effluent gas is measured: 

E - Cw Fd (20.9/[20.9(l-Bws) - %02 w]} Eq. 19-3 

2.3 Oxygen-Based F Factor, Dry/Wet Basis. 

2.3.1 When the pollutant concentration 1s measured on a wet basis (CJ 

and 0- concentration is measured on a dry basis (%02J, use the following 

equation: 

E - [(Cw Fd)/(l-Bws)]/[20.9/(20.9 - % 02 d )] Eq. 19-4 

128 
P.34 

2.3.2 When the pollutant concentration is measured on a dry basis (CJ 

and the 02 concentration 1s measured on a wet basis (^vJ' use the 

following equation: 

E = [Cd Fd 20.9]/[20.9 - %02 v/(l-Bw s)] Eq. 19-5 

2.4 Carbon Dioxide-Based F Factor, Dry Basis. When measurements are 

on a dry basis for both CO- (%C02d) and pollutant (CJ concentrations, use 

the following equation: 

E - Cd Fc (100/%C02d) Eq. 19-6 

2.5 Carbon Dioxide-Based F Factor, Wet Basis. When measurements are 

on a wet basis for both C02 (%C02w) and pollutant (C ) concentrations, use 

the following equation: 

E = Cw Fc (100/%C02w) Eq. 19-7 

2.6 Carbon Dioxide-Based F Factor, Dry/Wet Basis. 

2.6.1 When the pollutant concentration is measured on a wet basis (C ) 

W 

and CO- concentration is measured on a dry basis (%C02J, use the following 

equation: 

E - [Cw Fc/(1-Bws)] (100/%C02d) Eq. 19-8 

129 
P.35 

2.6.2 When the pollutant concentration is measured on a dry basis (CJ 

and C02 concentration is measured on a wet basis (%C02 ), use the following 

equation: 

E - Cd (1-BWS) Fc (100/%C02w) 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 turbine-steam 

generator combined cycle systems, determine the emissions from the steam 

generating unit or the percent reduction 1n potential SO- emissions as 

follows: 

2.8.1 Compute the emission rate from the steam generating unit using 

the following equation: 

Ebo ' Eco + <Y H b)(E c o - Eg) Eq. 19-10 

where: 

E. = pollutant emission rate from the steam generating unit, ng/J 

(lb/million Btu). 

E - pollutant emission rate in combined effluent, ng/J (lb/million 

Btu). 

130 
P.36 

E = pollutant rate from gas turbine, ng/J (lb/million Btu). 

H. = 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 E„„ and E„. Do not use Fw factors for determining E„ or E„rt. If an 

co g w 3 g co 

S 02 control device is used, measure E after the control device. 

2.8.1.2 Suitable methods shall be used to determine the heat input 

rates to the steam generating units (H^) and the gas turbine (HJ. 

2.8.2 If a control device is used, compute the percent of potential 

SO- emissions (% P ) using the following equations: 

Ebi "Eci " Vb^c i " V Eq* 1!M1 

% Ps - 100 (1 - Eb Q/Eb 1) Eq. 19-12 

where: 

Eb i = pollutant rate from the steam generating unit, ng/J (lb/million 

Btu) 

E . • pollutant rate in combined effluent, ng/J (lb/million Btu). 

Use the test methods and procedures section of Subpart GG to obtain E . 

and E . Do not use F factors for determining E or E *. 

131 
P.37 

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 F J from 

Table 19-1 may be used. 

NOTE TO GPO TYPESETTER: Please put this table in two columns 

immediately following the preceding line of text. 

TABLE 19-1. F FACTORS FOR VARIOUS FUELS 1 

Fuel Type 

Coal: 

Anthracite 

Bituminous 

Lignite 

Oil3 

Gas 

Natural 

Propane 

Butane 

Wood 

Wood Bark 

Municipal 

Solid Waste 

Determined 

(29.92 in. 

* 

at 

Hg) 

Fd 

dscm/J 

2.71x10"! 

2.63x10"£ 

2.65x10"' 

2.47xl0"7 

2.43x10"! 

2.34x10", 

2.34x10"' 

2.48x10"! 

2.58x10"' 

dsgf/ 

10°Btu 

10,100 

9,780 

9,860 

9,190 

8,710 

8,710 

8,710 

9,240 

9,600 

See Section 3.2 

standard conditions: 

Fw 

wscm/J 

2.83x10"? 

2.86x10", 

3.21x10"' 

2.77X10'7 

2.85x10'? 

2.74x10", 

2.79x10"' 

20°C (68°F) 

wscf/ 

10°Btu 

10,540 

10,640 

11,950 

10,320 

10,610 

10,200 

10,390 

and 760 

Fc 

scm/J 

0.530x10"? 

0.484x10", 

0.513x10"' 

0.383xl0"7 

0.287x10"? 

0.321x10"' 

0.337x10"' 

0.492x10"? 

0.516x10"' 

mm Hg 

10°Btu 

1,970 

1,800 

1,910 

1,420 

1,040 

1,190 

1,250 

1,830 

1,920 

•As classified according to ASTM D388-77. 

Crude, residual, or distillate. 

132 
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

 W) + (Kc

 a > + <Ks W + <Kn *") " <Ko »)"/« V Eq. 19-13 

Fw " K [(Khw

 W) + (Kc

 %C) + (Ks

 reS) + (Kn yM) 

- (K0 %0) + (1^ %H20)]/GCVw Eq. 19-14 

Fc a K (Kcc W/M Eq. 19-15 

fNOTE: Omit the %H20 term in the equations for Fw if %H and %0 include 

the unavailable hydrogen and oxygen in the form of H20.] 

where: 

Fd, F , F - volumes of combustion components per unit of heat content, 

scm/J (scf/million Btu). 

%H, %C, %S, %N, %0, and %r\Ji - concentrations of hydrogen, carbon, 

sulfur, nitrogen, oxygen, and water from an ultimate analysis 

of fuel, weight percent. 

GCV - gross calorific value of the fuel consistent with the ultimate 

analysis, kJ/kg (Btu/lb). 

K = conversion factor, IO"5 (kJ/J)/(%) [IO6 Btu/million Btu]. 

Khd - 22.7 (scm/kg))[(3.64 (scf/lb)/(%)] 

133 
P.39 

K_ = 9.57 (scm/kg)[(1.53 (scf/lb)/(%)]. 

Ks = 3.54 (scm/kg) [(0.57 (scf/lb)/(%)]. 

Kn = 0.86 (scm/kg [0.14 (scf/lb)/(%)]. 

KQ = 2.85 (scm/kg) [0.46 (scf/lb)/(%)]. 

Kh w - 34.74 (scm/kg) [(5.57 (scf/lb)/(%)]. 

Kw - 1.30 (scm/kg) [(0.21 (scf/lb)/(%)]. 

Kcc - 2.0 (scm/kg) [(0.321 (scf/lb)/(%)]. 

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 5.2.1 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 

burned, use the following equations, as applicable unless otherwise 

specified in applicable subpart: 

Fd • !_ Xk fd k Eq. 19-16 

n 

Fw - Z Xk Fw k Eq. 19-17 

Fc - £ Xk Fc k Eq. 19-18 

134 
P.40 

where: 

X. = fraction of total heat input from each type of fuel k. 

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

compute the average pollutant rate (EJ for the performance test period 

(e.g., 30 days) specified in the applicable regulation using the following 

equation: 

E

a " Wi&hi 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 

135 
P.41 

average pollutant rate (EJ for the performance test period (e.g., 30 days) 

a 

specified in the applicable regulation using the following equation: 

D D 

E. [ I(n d EJ i ]/Zn d i

 Eq. 19-20 

j=l

 a a J j»l

 a j 

where: 

Ed = average pollutant rate for each sampling 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). 

n. = number of operating hours of the affected facility within the 

performance test period for each Ed determined. 

D - number of sampling periods during the performance test period. 

5. Determination of Overall Reduction in Potential Sulfur Dioxide Emission 

5.1 Overall Percent Reduction. Compute the overall percent S0-

reduction (%RJ using the following equation: 

%RQ - 100 [1.0 - (1.0 - %Rf/100)(1.0 - %R /100)] Eq. 19-21 

where: 

%R-

 a SO* removal efficiency from fuel pretreatment, percent. 

%R * S02 removal efficiency of the control device, percent. 

5.2 Pretreatment Removal Efficiency (Optional). Compute the S02 

removal efficiency from fuel pretreatment (%RJ for the averaging period 

136 
P.42 

(e.g., 90 days) as specified 1n the applicable regulation using the 

following equation: 

%Rf = 100 {1.0 - [ Z (%Spj/GCVpj) Lpj]/[ £ («Srj/GCVrj) Lr j]} Eq. 19-22 

J X J X 

where: 

%S , %S =• sulfur content of the product and raw fuel lots, 

respectively, dry basis weight percent. 

GCV , GCVf - gross calorific value for the product and raw fuel lots, 

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

L , Lf - weight of the product and raw fuel lots, respectively, metric 

ton (ton), 

n - number of fuel lots during the averaging period. 

NOTE: In calculating %Rr, 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) Fuel - Sampling and Analysis. 

NOTE: For the purposes of this method, raw fuel (coal or oil) is the 

fuel delivered to the desulfurizatlon (pretreatment) facility. For oil, the 

input oil to the oil desulfurizatlon 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 

137 
P.43 

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 1s the weight .of raw 

coal used to produce one lot of product coal. Typically, the lot size 1s 

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 

03286-85 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. 

138 
P.44 

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.). The 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 D240-76 (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 the oil combusted on the first steam generating unit operating day 

of each calendar month and then using the lowest GCV value of the three GCV 

values per quarter for the GCV of all oil combusted in that calendar 

quarter. 

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 (%RJ of the control device using the following equation: 

139 
P.45 

%Rg = 100 [1.0 - Ea o/Ea.] Eq. 19-23 

where: 

E , E | - 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 SO- rates and, 1f appropriate, the 

inlet S02 rates. The rates may be determined as hourly (EJ or other 

sampling period averages (EJ. Then, compute the average pollutant rates 

for the performance test period (E and E J using the procedures 1n 

Section 4. 

5.3.2 As an alternative, as-fired fuel sampling and analysis may be 

used to determine inlet SO- rates as follows: 

5.3.2.1 Compute the average inlet S02 rate (Ed J for each sampling 

period using the following equation: 

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

where: 

Edi a avera 9e inlet so ? rate ^or eacn sam Plin 9 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 = 2xl07[(kg)(ng)/(%)(J)]{2xl04(lb)(Btu/(%))(million Btu)} 

140 
P.46 

After calculating £.. use the procedures in Section 4.2 to determine the 

average inlet S02 rate for the performance test period (E ..). 

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). 

141 
P.47 

6. Sulfur Retention Credit for Compliance Fuel 

If fuel sampling and analysis procedures in Section 5.2.1 are being 

used to determine average SO- emission rates (E J to the atmosphere from a 

coal-fired steam generating unit when there is no S02 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) (Ed J for 

each sampling period using the following equation: 

Ed i - 0.97 K (%S/GCV) Eq. 19-25 

where: 

Ed1 = avera 9e in le t SO? 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 = 2xl07[(kg)(ng)/(%)(J)]{2xl04(lb)(Btu/(%))(mill1on Btu)} 

After calculating Ej. use the procedures in Section 4-2 to determine the 

average SO- emission rate to the atmosphere for the performance test period 

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 

142 
P.48 

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 

(E *) as follows: 

Eart* - Ea n - t- -- Sn Eq. 19-26 

ao ao 0.95 o 

where: 

S - standard deviation of the hourly average emission rates for 

each performance test period, ng/J (lb/million Btu). 

t- gc - 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 (%RJ may be determined by using the lower confidence 

limit of the emission rate (E *) and the upper confidence limit of the 

inlet pollutant rate (E <*) in calculating the control device removal 

efficiency (%R ) as follows: 

% Rg - 100 [1.0 - Ea o*/Ea 1*] Eq. 19-27 

E a1* " Eai + ^ S1 E<- 19"28 

where: 

S^ » standard deviation of the hourly average Inlet pollutant rates 

for each performance test period, ng/J (lb/million Btu). 

143 
P.49 

NOTE TO GPO TYPESETTER: Please put this table in two columns 

immediately following the preceding line of text. 

TABLE 19-2. VALUES FOR tQ g5 

n* 

2 

3 

4 

5 

6 

7 

^.95 

6.31 

2.42 

2.35 

2.13 

2.02 

1.94 

n* 

8 

9 

10 

11 

12-16 

17-21 

^.95 

1.89 

1.86 

1.83 

1.81 

1.77 

1.73 

n* 

22-26 

27-31 

32-51 

59-91 

92-151 

152 or more 

l0.95 

1.71 

1.70 

1.68 

1.67 

1.66 

1.65 

* The values of this table are corrected for 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 (SJ of the hourly average pollutant rates using the 

following equation: 

Se =-\/(l/H) - (1/Hr) {-/[ Z (Ehj - Ea)

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

" J X 

where: 

S - standard deviation of the hourly average pollutant rates for each 

performance test period, ng/J (lb/m1ll1on Btu). 

H = 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 (S.) pollutant rates. 

144