Standards of Performance for New Stationary Sources as of July 1, 1979: (Second Supplemental Information Packet for Updating November 1977 NSPS Regulations Compilation, EPA-340/1-77-15)

8 STANDARDS OF PERFORMANCE
I FOR NEW STATIONARY SOURCES
1 AS OF JULY 1, 1979

-------
July 1979

To holders of Standards of Performance for New Stationary Sources,
A Compilation:

This document contains those pages necessary to update the above men-
tioned publication through July 1, 1979. It is only an update and
should be used in conjunction with the original compilation published by
the U.S. Environmental Protection Agency, Division of Stationary Source
Enforcement in November 1977 (EPA'340/1-77-015) and the first update
published in January 1979 (EPA 340/1-79-001). Copies of Standards of
Performance for New Stationary Sources, A Compilation may be obtained
from:
U.S. Environmental Protection Agency
Office of Administration
General Services Division, MD-35
Research Triangle Park, N.C. 27711
Included in this update, with complete instructions for filing, are: a
new cover, title page, and table of contents; a new Summary Table; all
revised and new Standards of Performance; the full text of all revisions
and standards promulgated since January 1979; and all proposed standards
or revisions.

Any questions, comments, or suggestions regarding this document or the
previous compilation should be directed to: Standards Handbooks, Division
of Stationary Source Enforcement (EN-341), U.S. Environmental Protection
Agency, Washington, D.C., 20460.
-------
INSTRUCTIONS FOR FILING
Remove and discard the cover of this document.
Deletions
Cover dated January 1979
Title page dated January 1979
Table of Contents:
pages v through xviii
SectionTl, Summary:
pages 11-3 through 18
Section III, Standards:
pages III-l and 2
pages III-5 and 6
pages 111-15 through 18
pages 111-23 through 24b
Section III, Appendix A
pages A-59 through A-64
Section V, Proposed Amendments
pages V-D-1 through 62
pages V-6G-17 and 18
Additions
New permanent cover
Title page of this document
Table of Contents:
pages v through xvi
Section II, Summary:
pages 11-3 through 20
Section III, Standards:
pages III-l and 2
pages 111-5 and 6
pages 111-15 through 18
pages III-23 through 24b
Section III, Appendix A
pages A-59 through A-64
pages A-79 through A-85
Section IV, Full Text
page xi
pages IV-279 through 330
Section V, Proposed Amendments
pages V-A-7 and 8
pages V-D-1 through 4
pages V-G-1 through 3
pages V-H-1 through 3
pages V-J-1 through 3
pages V-M-1 and 2
pages V-N-1 through 3
pages V-CC-1 through 16
pages V-GG-17
Place the new Technical Report Data page and this page in the back for
future reference.
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July 1979

To holders of Standards of Performance for New Stationary Sources,
A Compilation:

pages V-D-1 through 62
pages V-GG-17 and 18
Additions
New permanent cover
Title page of this document
Table of Contents:
pages v through xvi
"Section II, Summary:
pages 11-3 through 20
Section III, Standards:
pages III-l and 2
pages 111-5 and 6
pages 111-15 through 18
pages 111-23 through 24b
Section III, Appendix A
pages A-59 through A-64
pages A-79 through A-85
Section IV, Full Text
page xi
pages IV-279 through 330
Section V, Proposed Amendments
pages V-A-7 and 8
pages V-D-1 through 4
pages V-G-1 through 3
pages V-H-1 through 3
pages V-J-1 through 3
pages V-M-1 and 2
pages V-N-1 through 3
pages V-CC-1 through 16
pages V-GG-17
Place the new Tecnnical Report Data page and this page in the back for
future reference.
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CO
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" STANDARDS OF PERFORMANCE

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35
U.S. ENVIRONMENTAL PROTECTION AGENCY

OFFICE OF ENFORCEMENT

OFFICE OF GENERAL ENFORCEMENT

WASHINGTON, D.C. 20460
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EPA 340/1-77-015
EPA 340/1-79-001
EPA 340/1-79-001 a
STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES -
A COMPILATION AS OF JULY 1,1979
by

PEDCo Environmental, Inc.
Cincinnati, Ohio 45246
Contract No. 68-01-4147
EPA Project Officer: Kirk Foster
Prepared for

U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Enforcement
Office of General Enforcement
Division of Stationary Source Enforcement
Washington, D.C. 20460

July 1979
-------
The Stationary Source Enforcement series of reports is issued by the
Office of General Enforcement, Environmental Protection Agency, to
assist the Regional Offices in activities related to enforcement of
implementation plans, new source emission standards, and hazardous
emission standards to be developed under the Clean Air Act. Copies of
Stationary Source Enforcement reports are available - as supplies permit -
from the U.S. Environmental Protection Agency, Office of Administration,
General Services Division, MD-35, Research Triangle Park, North Carolina
27711, or may be obtained, for a nominal cost, from the National Technical
Information Service, 5285 Port Royal Road, Springfield, Virginia 22151.
11
-------
TABLE OF CONTENTS
I. INTRODUCTION TO STANDARDS OF PERFORMANCE FOR NEW
STATIONARY SOURCES
II. SUMMARY OF STANDARDS AND REVISIONS
III. PART 60 - STANDARDS OF PERFORMANCE FOR NEW
STATIONARY SOURCES
SUBPART A - GENERAL PROVISIONS
Section
60.1 Applicability
60.2 Definitions
60.3 Abbreviations
60.4 Address
60.5 Determination of construction or modification
60.6 Review of plans
60.7 Notification and recordkeeping
60.8 Performance tests
60.9 Availability of information
6.10 State authority
60.11 Compliance with standards and maintenance
requirements
60.12 Circumvention
60.13 Monitoring requirements
60.14 Modification
60.15 Reconstruction
Page
1-1

II-l
III-l
III-3
III-3
III-3
III-4
III-5
III-5
III-5
III-6
III-6
111-6
III-6

III-7
III-7
III-8
111-10
Section
60.20
60.21
60.22

60.23
SUBPART B - ADOPTION AND SUBMITTAL OF STATE PLANS
FOR DESIGNATED FACILITIES
Applicability I11-11
Definitions III-l1
Publication of guideline documents, emission III-l1
guidelines, final compliance times
Adoption and submittal of state plans; public III-l1
hearings
-------
TABLE OF CONTENTS
Section Page
60.24 Emission standards and compliance schedules 111-12
60.25 Emission inventories, source surveillance reports 111-12
60.26 Legal authority 111-13
60.27 Actions by the Administrator 111-13
60.28 Plan revisions by the State 111-13
60.29 Plan revisions by the Administrator 111-13

SUBPART C - EMISSION GUIDELINES AND COMPLIANCE TIMES 111-14

SUBPART D - STANDARDS OF PERFORMANCE FOR FOSSIL-FUEL-FIRED
STEAM GENERATORS FOR WHICH CONSTRUCTION IS
COMMENCED AFTER AUGUST 17, 1971
Section
60.40 Applicability and designation of affected 111-15
facility
60.41 Definitions 111-15
60.42 Standard for particulate matter 111-15
60.43 Standard for sulfur dioxide 111-15
60.44 Standard for nitrogen oxides 111-15
60.45 Emission and fuel monitoring 111-15
60.46 Test methods and procedures 111-17
SUBPART Da - STANDARDS OF PERFORMANCE FOR ELECTRIC UTILITY
STEAM GENERATING UNITS FOR WHICH CONSTRUCTION IS
COMMENCED AFTER SEPTEMBER 18, 1978
Section
60.40a Applicability and designation of affected facility III-17a
60.41a Definitions III-17a
60.42a Standard for particulate matter III-17b
60.43a Standard for sulfur dioxide III-17b
60.44a Standard for nitrogen oxides III-17c
60.45a Commercial demonstration permit III-17c
60.46a Compliance provisions III-17d
60.47a Emission monitoring III-17d

vi
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TABLE OF CONTENTS
Section
60.48a
60.49a
Page
Compliance determination procedures and methods
Reporting requirements
Section
60.50
60.51
60.52
60.53
60.54
Section
60.60
60.61
60.62
60.63
60.64
Section
60.70
60.71
60.72
60.73
60.74
SUBPART E - STANDARDS OF PERFORMANCE FOR INCINERATORS

Applicability and designation of affected facility 111-18
Definitions 111-18
Standard for particulate matter II1-18
Monitoring of operations 111-18
Test methods and procedures II1-18
SUBPART F - STANDARDS OF PERFORMANCE FOR PORTLAND
CEMENT PLANTS
Applicability and designation of affected facility II1-19
Definitions 111-19
Standard for particulate 111-19
Monitoring of operations 111-19
Test methods and procedures 111-19
SUBPART G - STANDARDS OF PERFORMANCE FOR
NITRIC ACID PLANTS
Applicability and designation of affected facility 111-20
Definitions III-20
Standard for nitrogen oxides II1-20
Emission monitoring 111-20
Test methods and procedures II1-20
vi i
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TABLE OF CONTENTS
Page
Section
60.80
60.81
60.82
60.83
60.84
60.85
SUBPART H - STANDARDS OF PERFORMANCE FOR
SULFURIC ACID PLANTS
Applicability and designation of affected facility
Definitions
Standard for sulfur dioxide
Standard for acid mist
Emission monitoring
Test methods and procedures
111-21
111-21
111-21
111-21
111-21
111-21
Section
60.90
60.91
60.92
60.93
SUBPART I - STANDARDS OF PERFORMANCE FOR
ASPHALT CONCRETE PLANTS
Applicability and designation of affected facility 111-22
Definitions 111-22
Standard for particulate matter 111-22
Test methods 111-22
SUBPART J - STANDARDS OF PERFORMANCE FOR
PETROLEUM REFINERIES
Section
60.100 Applicability and designation of affected facility 111-23
60.101 Definitions 111-23
60.102 Standard for particulate matter 111-23
60.103 Standard for carbon monoxide II1-23
60.104 Standard for sulfur dioxide 111-23
60.105 Emission monitoring 111-23
60.106 Test methods and procedures II1-23
Section
60.110
SUBPART K - STANDARDS OF PERFORMANCE FOR
STORAGE VESSELS FOR PETROLEUM LIQUIDS
Applicability and designation of affected facility 111-25
vm
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TABLE OF CONTENTS
Section
60.111
60.112
60.113
Definitions
Standard for hydrocarbons
Monitoring of operations
Page
111-25
111-25
111-25
Section
60.120
60.121
60.122
60.123
SUBPART L - STANDARDS OF PERFORMANCE FOR
SECONDARY LEAD SMELTERS
Applicability and designation of-affected facility 111-26
Definitions 111-26
Standard for participate matter 111-26
Test methods and procedures 111-26
SUBPART M - STANDARDS OF PERFORMANCE FOR SECONDARY
BRASS AND BRONZE INGOT PRODUCTION PLANTS
Section
60.130
60.131
60.132
60.133
Applicability and designation of affected facility 111-27
Definitions II1-27
Standard for participate matter 111-27
Test methods and procedures 111-27
Section
60.140
60.141
60.142
60.143
60.144
SUBPART N - STANDARDS OF PERFORMANCE FOR
IRON AND STEEL PLANTS
Applicability and designation of affected facility 111-28
Definitions 111-28
Standard for particulate matter II1-28
Monitoring of operations 111-28
Test methods and procedures II1-28
Section
60.150
SUBPART 0 - STANDARDS OF PERFORMANCE FOR
SEWAGE TREATMENT PLANTS
Applicability and designation of affected facility 111-29
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TABLE OF CONTENTS
Section
60.151
60.152
60.153
60.154
Definitions
Standard for participate matter
Monitoring of operations
Test methods and procedures
Page
111-29
111-29
111-29
111-29
SUBPART P - STANDARDS OF PERFORMANCE FOR
PRIMARY COPPER SMELTERS
Section
60.160 Applicability and designation of affected facility 111-30
60.161 Definitions 111-30
60.162 Standard for participate matter 111-30
60.163 Standard for sulfur dioxide 111-30
60.164 Standard for visible emissions 111-30
60.165 Monitoring of operations 111-30
60.166 Test methods and procedures 111-31

SUBPART Q - STANDARDS OF PERFORMANCE FOR
PRIMARY ZINC SMELTERS
Section
60.170 Applicability and designation of affected facility 111-32
60.171 Definitions 111-32
60.172 Standard for particulate matter 111-32
60.173 Standard for sulfur dioxide 111-32
60.174 Standard for visible emissions 111-32
60.175 Monitoring of operations 111-32
60.176 Test methods and procedures II1-32
Section
60.180
60.181
SUBPART R - STANDARDS OF PERFORMANCE FOR
PRIMARY LEAD SMELTERS
Applicability and designation of affected facility
Definitions
111-33
111-33
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TABLE OF CONTENTS
Section
60.182
60.183
60.184
60.185
60.186
Standard for participate matter
Standard for sulfur dioxide
Standard for visible emissions
Monitoring of operations
Test methods and procedures
Page
111-33
111-33
111-33
111-33
111-33
Section
60.190
60.191
60.192
60.193
60.194
•60.195
SUBPART S - STANDARDS OF PERFORMANCE FOR
PRIMARY ALUMINUM REDUCTION PLANTS
Applicability and designation of affected facility 111-34
Definitions 111-34
Standard for fluorides 111-34
Standard for visible emissions 111-34
Monitoring of operations 111-34
Test methods and procedures 111-34
SUBPART T - STANDARDS OF PERFORMANCE FOR PHOSPHATE
FERTILIZER INDUSTRY: WET PROCESS PHOSPHORIC ACID PLANTS
Section
60.200
60.201
60.202
60.203
60.204
Applicability and designation of affected facility 111-36
Definitions 111-36
Standard for fluorides 111-36
Monitoring of operations 111-36
Test methods and procedures 111-36
SUBPART U - STANDARDS OF PERFORMANCE FOR PHOSPHATE
FERTILIZER INDUSTRY: SUPERPHOSPHORIC ACID PLANTS
Section
60.210
60.211
60.212
60.213
60.214
Applicability and designation of affected facility 111-37
Definitions 111-37
Standard for fluorides 111-37
Monitoring of operations 111-37
Test methods and procedures 111-37
XI
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TABLE OF CONTENTS
Page
SUBPART V - STANDARDS OF PERFORMANCE FOR PHOSPHATE
FERTILIZER INDUSTRY: DIAMMONIUM PHOSPHATE PLANTS
Section
60.220 Applicability and designation of affected facility III-38
60.221 Definitions 111-38
60.222 Standard for fluorides 111-38
60.223 Monitoring of operations 111-38
60.224 Test methods and procedures 111-38

SUBPART W - STANDARDS OF PERFORMANCE FOR PHOSPHATE
FERTILIZER INDUSTRY: TRIPLE SUPERPHOSPHATE PLANTS
Section
60.230 Applicability and designation of affected facility 111-39
60.231 Definitions 111-39
60.232 Standard for fluorides 111-39
60.233 Monitoring of operations 111-39
60.234 Test methods and procedures 111-39

SUBPART X - STANDARDS OF PERFORMANCE FOR THE PHOSPHATE
FERTILIZER INDUSTRY: GRANULAR TRIPLE SUPERPHOSPHATE
STORAGE FACILITIES
Section
60.240 Applicability and designation of affected facility 111-40
60.241 Definitions 111-40
60.242 Standard for fluorides II1-40
60.243 Monitoring of operations 111-40
60.244 Test methods and procedures II1-40
SUBPART Y - STANDARDS OF PERFORMANCE FOR
COAL PREPARATION PLANTS
Section
60.250 Applicability and designation of affected facility 111-41
60.251 Definitions 111-41
xn
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TABLE OF CONTENTS
Section
60.252
60.253
60.254
Standards for particulate matter
Monitoring of operations
Test methods and procedures
Page
111-41
111-41
111-41
SUBPART Z - STANDARDS OF PERFORMANCE FOR FERROALLOY
PRODUCTION FACILITIES
Section
60.260 Applicability and designation of affected facility 111-42
60.261 Definitions 111-42
60.262 Standard for participate matter 111-42
60.263 Standard for carbon monoxide II1-42
60.264 Emission monitoring 111-42
60.265 Monitoring of operations 111-42
60.266 Test methods and procedures II1-43
Section
60.270
60.271
60.272
60.273
60.274
60.275
SUBPART AA - STANDARDS OF PERFORMANCE FOR STEEL
PLANTS: ELECTRIC ARC FURNACES
Applicability and designation of affected facility 111-45
Definitions II1-45
Standard for particulate matter II1-45
Emission monitoring • II1-45
Monitoring of operations II1-45
Test methods and procedures 111-46
Section
60.280
60.281
60.282
60.283
60.284
60.285
SUBPART BB - STANDARDS OF PERFORMANCE
FOR KRAFT PULP MILLS
Applicability and designation of affected facility 111-47
Definitions III-47
Standard for particulate matter 111-47
Standard for total reduced sulfur (TRS) 111-47
Monitoring of emissions and operations 111-48
Test methods and procedures 111-48
xm
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Section
60.300
60.301
60.302
60.303
60.304
TABLE OF CONTENTS
SUBPART DD - STANDARDS OF PERFORMANCE
FOR GRAIN ELEVATORS
Applicability and designation of affected facility
Definitions
Standard for participate matter
Test methods and procedures
Modification
Page
111-50
111-50
111-50
111-50
111-50
Section
60.340
60.341
60.342
60.343
60.344
SUBPART HH - STANDARDS OF PERFORMANCE
FOR LIME MANUFACTURING PLANTS
Applicability and designation of affected facility
Definitions
Standard for particulate matter
Monitoring of emissions and operations
Test methods and procedures
111-51
111-51
111-51
111-51
111-51
xiv
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TABLE OF CONTENTS
APPENDIX A - REFERENCE METHODS

Method 1
Sample and velocity traverses for stationary
sources
Method 2 - Determination of stack gas velocity and volumetric
flow rate (Type S Pi tot Tube)

Method 3 - Gas analysis for carbon dioxide, excess air, and
dry molecular weight

Method 4 - Determination of moisture in stack gases

Method 5 - Determination of particulate emissions from
stationary sources

Method 6 - Determination of sulfur dioxide emissions from
stationary sources

Method 7 - Determination of nitrogen oxide emissions from
stationary sources

Method 8 - Determination of sulfuric acid mist and sulfur
dioxide emissions from stationary sources

Method 9 - Visual determination of the opacity of emissions
from stationary sources

Method 10 - Determination of carbon monoxide emissions
from stationary sources

Method 11 - Determination of hydrogen sulfide content of
fuel gas streams in petroleum refineries

Method 12 - [Reserved]

Method ISA - Determination of total fluoride emissions
from stationary sources - SPADNS Zirconium
Lake method

Method 13B - Determination of total fluoride emissions
from stationary sources - Specific Ion
Electrode method

Method 14 - Determination of fluoride emissions from
potroom roof monitors of primary aluminum
plants
Page

Ill-Appendix A-l

Ill-Appendix A-4

Ill-Appendix A-14

Ill-Appendix A-l7

Ill-Appendix A-21

Ill-Appendix A-28

Ill-Appendix A-30

Ill-Appendix A-32

Ill-Appendix A-35

Ill-Appendix A-39

Ill-Appendix A-41

Ill-Appendix A-45

Ill-Appendix A-51

Ill-Appendix A-55
xv
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Page

Method 15 - Determination of hydrogen sulfide, carbonyl Ill-Appendix A-57
sulfide, and carbon desulfide emissions from
stationary sources

Method 16 - Semi continuous determination of sulfur emissions Ill-Appendix A-60
from stationary sources

Method 17 - Determination of particulate emissions from Ill-Appendix A-68
stationary sources (in-stack filtration method)

Method 19 - Determination of sulfur dioxide removal Ill-Appendix A-79
efficiency and particulate, sulfur dioxide and
nitrogen oxides emission rates from electric
utility steam generators

APPENDIX B - PERFORMANCE SPECIFICATIONS Ill-Appendix B-l

APPENDIX C - DETERMINATION OF EMISSION RATE CHANGE Ill-Appendix C-l

APPENDIX D - REQUIRED EMISSION INVENTORY INFORMATION Ill-Appendix D-l

IV. FULL TEXT OF REVISIONS (References) IV-1

V. PROPOSED AMENDMENTS V-l
xv i
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STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
I
CO
Source category
Subpart D - Fossil-Fuel Fired
Steam Generators for Which
Construction 1s Commenced
After August 17. 1971

Proposed/effective
8/17/71 (36 FR 15704)
Promulgated
12/23/71

Revised
(36 FR 24876)

7/26/7Z (37 FR 14877)
10/15/73
(38 FR 28564)
6/14/74 (39 FR 20790)
1/16/75
10/6/75
12/22/75
11/22/76
1/31/77
7/25/77
8/15/77
8/17/77
40 FR 2803)
40 FR 46250)
(40 FR 59204)
(41 FR 51397)
42 FR 5936)
42 FR 37936)
42 FR 41122)
42 FR 41122)
12/5/77 (42 FR 61537)
3/3/78 (43 FR 8800)
3/7/78 (43 FR 9276)
1/17/79
6/11/79

44 FR 3491)
44 FR 33580)

Affected
facility

Coal, coal /wood
residue fired boilers
>250 million Btu/hr

Oil, oil/wood residue
fired boilers
>250 million Btu/hr

Gas, gas/wood residue
fired boilers
>250 million Btu/hr

Mixed fossil fuel
fired boilers
>250 million Btu/hr

Lignite, lignite/wood
residue
>250 million Btu/hr

Pollutant

Parti cul ate
Opacity
SO?
NOX

Parti cul ate
Opacity
S02
NOX

Partlculate
Opacity
NOX

Particulate
Opacity
SO?
NOX (except lignite
or 25% coal refuse)

Particulate
Opaci ty
S02
NOX (as of 12/22/76)

Emission level

0.10 lb/106 Btu
20*; 27% 6 min/hr
1.2 lb/106 Btu
0.70 lb/106 Btu

0.10 lb/106 Btu
20%, 27% 6 min/hr
0.80 lb/106 Btu
0.30 lb/106 Btu

0.10 lb/106 Btu
20%; 27% 6 min/hr
0.20 lb/106 Btu

0.10 lb/106 Btu
20%; 27% 6 min/hr
Prorated
Prorated

0.10 lb/106 Btu
20%; 27% 6 min/hr
1.2 lb/106 Btu
0.60 lb/106 Btu
0.80 lb/106 Btu for
ND, SO, MT lignite
burned In >cycl one-
fired unit

Monitoring
requirement

No requirement
Continuous
Continuous*
Continuous*

No requirement
Continuous*
Continuous*

No requirement
Continuous
Continuous*
Continuous*

•exceptions; see
standards
-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
Source category
Subpart Oa - electric
utility steam gen-
erating units for
for which construc-
tion is commenced
after September 18.
1978

Proposed/effective
9/19/78 (43 FR 42154)

Promulgated

6/11/79 (44 FR 33580)

Affected facility
Boilers >73 MW
(>250 million
Btu/h) firing
solid and solid
derived fuel

Pollutant
Particulate

Opacity

S02

S02 - solvent
refined coal
S02 - 100*
anthracite;
non-conti-
nental
NOX - coal de-
rived fuels;
subbi luminous;
shale oil
NOX - >25%
lignite mined
in NO. SD, MT,
combusted in
slag tap
furnace
NOx - lignite;
bituminous;
anthracite;
other fuels
Emission level
13 ng/J (0.03 Ib/mil-
lion Btuj
20%; 27* 6 min/h

520 ng/J (1.20 lb/
million Btu)
or
<260 ng/J (0.60 lb/
million Btu)

520 ng/J (1.20 lb/
million Btu)
520 ng/J (1.20 lb/
million Btu)

210 ng/q (0.50 lb/
million Btu)

340 ng/J (0.80 lb/
million Btu)

260 ng/J (0.60 lb/
million Btu)

Potential
combustion
concentration
3000 ng/J (7.0
Ib/million Btu)

See 60.48a(b)

990 ng/J (2.30
Ib/million Btu)

Reduction of
potential com-
bustion con-
centration, %
99

Exempt

Monitoring
requirement
No requirement

Continuous

-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES (Continued)
I
en
Source category

Affected facility
Boilers > 73 MW
(>250 million
Btu/h) firing
liquid fuel

Boilers >73 MW
(>250 million Btu)
firing gaseous
fuels

Pollutant
Partlculate

Opacity

S02

SO? (non-
continental)
NOX

Particulate
Opacity

SO?

SO? (non-
continental )
NOX

Emission level
13 ng/J (0.03 lb/
million Btu)
20%; 27% 6 min/h

340 ng/J (0.80 lb/
million Btu)
or
<86 ng/J (0.20 lb/
million Btu)
340 ng/J (0.80 lb/
million Btu)
130 ng/J (0.30 lb/
million Btu)
13 ng/J (0.03 lb/
million Btu)
20*; 27* 6 min/h

340 nq/J (0.80 lb/
million Btu)
or
<86 ng/J (0.20 lb/
million Btu)
340 ng/J (0.80 lb/
million Btu)
86 ng/J (0.20 lb/
million Btu)
Potential
combustion
concentration
75 ng/J (0.17
It/million Btu)

See 60.48a(b)

310 ng/J (0.72
lb/ million Btu)

See 60.48a(b)

290 ng/J (0.67
Ib/million Btu)
Reduction of
potential com-
bustion con-
centration, %
70

Exempt

Monitoring
requirement
No requirement

Continuous

No requirement
No requirement

Continuous*

Continuous

*Except when using only natural gas.
-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES (Continued)
Source category
Subpart E - Incinerators
Proposed/effective
8/17/71 (36 FR 15704)
Promulgated
12/23/71 (36 FR 24876)
Revised
6/14/74 (36 FR 20790)
7/25/77 (42 FR 37936)
8/17/77 (42 FR 41424)
3/3/78 (43 FR 8800)
Subpart F - Portland Cement Plant;
Proposed/effective
8/17/71 (36 FR 15704)
Promulgated
12/23/71 (36 FR 24876)
Revised
6/14/74 (39 FR 20790)
11/12/74 (39 FR 39872)
10/6/75 (40 FR 46250)
7/25/77 (42 FR 37936)
8/17/77 (42 FR 41424)
3/3/78 (43 FR 8800)
Affected
facility

Incinerators
>50 tons/day

Kiln
Clinker cooler
Fugitive
emission points
Pollutant

Partlculate

Partlculate
Opacity
Partlculate
Opacity
Opacity
Emission level

0.08 gr/dscf (0.18
g/dscm) corrected
to 12X C02

0.30 Ib/ton
20X
0.10 Ib/ton
10X
10X
Monitoring
requirement

No requirement
Dally charging
rates and hours

No requirement
No requirement
No requirement
No requirement
No requirement
Dally production
and feed kiln
rates
-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES (Continued)
Source category
Affected
facility
Pollutant
Emission level
Monitoring
requirement
Subpart G - Nitric Acid Plants

Proposed/effective
3717/71 (36 FR 15704)

Promulgated
12/33/71 (36 FR 24876)

Revised
5/23/73 (38 FR 13562)
10/15/73 (38 FR 28564)
6/14/74 (39 FR 20790
10/6/75 (40 FR 46250
7/25/77 (42 FR 37936
8/17/77 (42 FR 41424
3/3/78 (43 FR 8800)
Process equipment
Opacity
NOX
10*
3.0 Ib/ton
No requirement
Continuous
Dally production
rates and hours
Subpart H - Sulfurlc Acid Plants
8/17/71 (36 FR 15704)

Promulgated
12/23/71 (36 FR 24876)

Revised
STzlTTT (38 FR 13562)
10/15/73 (38 FR 28564)
Process equipment
S0?
Acid mist
Opacity
4.0 Ib/ton
0.15 Ib/ton
10X
Continuous
No requirement
No requirement
6/14/74
10/6/75
7/25/77
8/17/77
39 FR 20790
40 FR 46250
42 FR 37936
42 FR 41424
3/3/78 (43 FR 8800)
-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES (Continued)
I
CO

Source category
Subpart I - Asphalt Concrete Plants
Proposed/effective
6/11/73 (38 FR 15406)
Promulgated
3/8/74 (39 FR 9308)

Revised
107 6/75 (40 FR 46250)
7/25/77 (42 FR 37936)
8/17/77 (42 FR 41424)
3/3/78 (43 FR 8800)
Subpart J - Petroleum Refineries
Proposed/effective

6/11/73 (38 FR 15406)
10/4/76 (41 FR 43866)

Promulgated
3/8/74 (39 FR 9308)

Revised
10/6/75 (40 FR 46250)
6/24/77 (42 FR 32426)
7/25/77 (42 FR 37936)
8/4/77 (42 FR 39389)
8/17/77 (42 FR 41424)
3/3/78 (43 FR 8800)
3/15/78 (43 FR 10866)
3/12/79 (44 FR 13480)
Affected
facility

Dryers; screening and
weighing systems; stor-
age, transfer, and
loading systems; and
dust handling equipment

Catalytic cracker

With incinerator or
waste heat boiler

Fuel gas
combustion

Claus sulfur re-
covery plants
>20 LTD/day
(as of 10/4/76)

Pollutant

Particulate

Opacity

Particulate

Opacity
Particulate

S02

Emislson level

0.04 gr/dscf
(90 mg/dscm)
20%

1.0 lb/1000 Ib
(1JO kg/1000 kg)
3035 (6 min. exemption)
Additional 0.10
Ib/million Btu
(43J.O g/HJ)
0.05%

0.10 gr H2S/dscf
(230 mg/dscm) fuel
gas content

0.025% with oxida-
tion or reduction
and incineration
0.030% with reduc-
tion only

Monitoring
requirement

No requirement

Continuous
No requirement

Continuous

-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES (Continued)
i
VO
Source category
Subpart K - Storage Vessels for
Petroleum Liquids
Proposed/ effective

5/11/73 (38 FR 15406)
Promulgated
3/8/74 (39 FR 9308)

Revised
4717774" (39 FR 13776
6/14/74 (39 FR 20790
7/25/77 (42 FR 37936

8/17/77 (42 FR 41424)
3/3/78 (43 FR 8800)
Subpart L - Secondary
Proposed/effective
6/11/73 (38 FR 15406

Promulgated
j/8/74 (39 FR 9308)
Revised
4717/74 39 FR 13776
10/6/75 40 FR 46250
7/25/77 42 FR 37936
8/17/77 42 FR 41424
3/3/78 (43 FR 8800)

t Lead Smelter

Affected
facility

Storage tanks
>40.000 gal. capacity

Reverberatory and
blast furnaces

Pot furnaces
>550 Ib/capaclty

Pollutant

Hydrocarbons

Partlculate
Opacity

Opacity

Emission level

For vapor pressure
78-570 nn Hg (1.5
psla-11.1 psla),
equip with floating
roof, vapor recovery
system, or equiv-
alent; for vapor
pressure >570 mm Hg
(11.1 psla), equip
with vapor recovery
system or equivalent
0.022 gr/dscf
(50 mg/dscm)
20S

10X

Monitoring
requl reroent

No requirement

Date, type, vapor
pressure and tem-
perature
No requirement
No requirement

No requirement

-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES (Continued)

Source category
Subpart M - Secondary Brass, Bronz
and Ingot Production Plants
Proposed/ef f ect i ve
6/11/73 (38 FR 15406)

Promulgated
3/8/74 (39 FR 9308)

Revised
10/6/75 40 FR 46250)
7/25/77 42 FR 37936)
8/17/77 42 FR 41424)
3/3/78 (43 FR 8800)
Subpart N - Iron and Steel Plants
Proposed/ effect lye
6:/ll/73 (38 FR 15406)
Promulgated
3/8/74 (39 FR 9308)
Revised
7/25/77 (42 FR 37936)
8/17/77 (42 FR 41424)
3/3/78 (43 FR 8800)
4/13/78 (43 FR 15600)

Affected
facility
a

Reverberate ry
furnace

Blast and
electric furnaces

Basic oxygen
process furnace

Pollutant

Particulate

Opacity

Particulate

Opacity

Emission level

0.022 gr/dscf
(50 mg/dscm)
202

10%

0.022 gr/dscf
(50 mg/dscm)
10% (202
exception/cycle)

Monitoring
requirement

No requirement

Time and dura-
tion of each
cycle; exhaust
gas diversion;
scrubber pressure
loss; water
supply pressure
-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES (Continued)
Source category
Subpart 0 - Sewage Treatment
Plants
Proposed/effective
6/11/73 (38 FR 15406)
3/8/74 (39 FR 9308)
Revised
4/17/74 (39 FR 13776)
5/3/74 (39 FR 15396)
10/6/75 (40 FR 46250)
7/25/77 (42 FR 37936)
8/17/77 (42 FR 41424)
Subpart P - Primary Copper Smelte
Proposed/ effective
10/16/74 (39 FR 37040)
Promulgated
1/15/76 (41 FR 2331 )
Revised
2V2677C (41 FR 8346)
7/25/77 (42 FR 37936)
8/T/77 (42 FR 41424)
3/3/VS (43 FR 8800)
Affected
facility
Sludge incinerators
>10% from municipal
sewage treatment or
>2.205 Ib/day muni-
cipal sewage sludge
•s
Dryer
Roaster, smelting
furnace,* copper
converter
*Reverberatory furnaces
that process high- im-
purity feed materials
are exempt from SO?
standard
Pollutant
Partlculate
Opacity
Partlculate
Opacity
S02
Opacity
Emission level
1.30 Ib/ton
(0.65 g/kg)
20%
0.022 gr/dscf
(50 mg/dscm)
20%
0.065%
20%
Monitoring
requirement
No requirement
No requirement
Mass or volume of
sludge; mass of
any municipal
solid waste
No requirement
Continuous
Continuous
No requirement
Monthly record of
charge and weight
percent of ar-
senic, antimony,
lead, and zinc
-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES (Continued)
I
ro

Source category
Subpart Q - Primary Z1nc Smelters
Proposed/effective
10/16/74 (39 FR 37040)

Promulgated
1/51/76 (41 FR 2331)

Revised
7/25/77 (42 FR 37936)
8/17/77 (42 FR 41424)
3/3/78 (43 FR 8800)
Subpart R - Primary Lead Smelters
Proposed/effective
10/16/74 (39 FR 37040)

Promulgated
1/15/76 (41 FR 2331 )

Revised
7/25/77 (42 FR 37936)
8/17/77 (42 FR 41424)
3/3/78 (43 FR 8800)
Affected
facility

Sintering machine

Roaster

Blast or reverberatory
furnace, sintering
machine discharge end

Sintering machine,
electric smelting
furnace, converter

Pollutant

Particulate

Opaci ty

SOa
Opacity

Particulate

Opacity

S02
Opacity

Emission level

0.022 gr/dscf
(50 mg/dscm)
20%

0.065%
20%

0.022 gr/dscf
(50 mg/dscm)
20%

0.065%
20%

Monitoring
requirement

No requirement

Continuous

Continuous
No requirement

No requirement

Continuous

Continuous
No requirement

-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES (Continued)
Source category
Subpart S - Primary Aluminum
Reduction Plants
.Proposed/effect 1 ye
10/23/74 (39 FR 37730)
Promulgated
1/26/76 (41 FR 3825)
Revised
7/25/77 (42 FR 37936)
8/17/77 (42 FR 41424)
3/3/78 (43 FR 8800)
Subpart T - Phosphate Fertilizer
Industry
Proposed/effective
10/2Z/74 (39 FR 37602)
Promulgated
8/6/75 (40 FR 33152)
Revised
7/25/77 (42 FR 37936)
8/17/77 (42 FR 41424)
3/3/78 (43 FR 8800)
Affected
facility

Potroom group
Anode bake plants

Met process
phosphoric acid

Pollutant

Opacity
Total fluorides
(a) Soderberg
(b) Prebake
Total fluorides
Opacity

Total fluorides

Emission level

10%
2.0 Ib/ton
1.9 Ib/ton
0.1 Ib/ton
201

0.02 Ib/ton

Monitoring
requirement

No requirement
No requirement
No requirement
No requirement
No requirement
Dally weight, pro-
duction rate of
aluminum and anode
raw material feed
rate, cell or
pot line voltages

No requirement
Mass flow rate,
daily equivalent
PzOs feed, total
pressure drop
across scrubbing
system
-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES (Continued)
I
-pa

Source category
Subpart U - Phosphate Fertilizer
!n&.;scry
Proposed/effective
10/32/74 (39 FR 37602)
Promulgated
8/6/75 (40 FR 33152)

Revised
7725777 (42 FR 37936)
8/17/77 (42 FR 41424)
3/3/78 (43 FR 8800)
Subpart V - Phosphate Fertilizer
Industry
Proposed/effective
10/24/74 (39 FR 37602)

Promulgated
8/6/75 (40 FR 33152)

Revised
7/25/77 (42 FR 37936)
8/17/77 (42 FR 41424)
3/3/78 (43 FR 8800)
Affected
facility

Superphosphoric acid

Di ammonium phosphate

Pollutant

Total fluorides

Emission level

0.01 Ib/ton

0.06 Ib/ton

Monitoring
requirement

No requirement
Mass flow rate,
dally equivalent
?205 feed, total
pressure drop
across scrubbing
system

No requirement
Mass flow rate,
dally equivalent
P20s feed, total
pressure drop
across scrubbing
system

-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES (Continued)
en

Source category
Subpart U - Phosphate Fertilizer
Industry
Proposed/effective
10/22/74 (39 FR 37602)

Promulgated
8/6/75 (40 FR 33152)

Revised
7725777 (42 FR 37936)
8/17/77 (42 FR 41424)
3/3/78 (43 FR 8800)
Subpart X - Phosphate Fertilizer
Industry
Proposed/effective
10/22/74 (39 FR 37602)

Promulgated
8/6/75 (40 FR 33152)

Revised
7/25/77 (42 FR 37936)
8/17/77 (42 FR 41424)
3/3/78 (43 FR 8800)
Affected
facility

Triple superphosphate

Granular triple super-
phosphate

Pollutant

Total fluorides

Emission level

0.2 Ib/ton

5.0 x 10"4
Ib/hr/ton

Monitoring
requirement

No requirement

Mass flow rate.
dally equivalent
P205 feed, total
pressure drop
across scrubbing
system

No requirement
Mass flow rate.
dally equivalent
P20s feed, total
pressure drop
across scrubbing
system

-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES (Continued)
I
en
Source category
Subpart Y - Coal Preparation
Plants
Proposed/ ef f ectl ve
10/24/74 (39 FR 3792Z)
Promulgated
1/15/76 (41 FR 2232)
Revised
7/25777 (42 FR 37936)
8/17/77 (42 FR 41424)
9/7/77 (42 FR 44812)
3/3/78 (43 FR 8800)

Affected
facility

Thermal dryer
Pneumatic coal
cleaning equipment
Processing and convey-
ing equipment, storage
systems, transfer and
loading systens
Pollutant

Partlculate
Opacity
Partlculate
Opacity
Opacity
Emission level

0.031 gr/dscf
(0.070 g/dson)
20%
0.018 gr/dscf
(0.040 g/dscm)
10*
201
Monitoring
requirement

Temperature,
Scrubber
pressure loss.
Hater pressure
No requirement
No requirement
No requirement
No requirement
-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES (Continued)
Source category
Subpart Z - Ferroalloy Production
Facilities
Proposed/effective
10/21/74 (39 FR 37470)

Promulgated
5/4/76 (41 FR 18497)

Revised
5/20/7$ (41 FR 20659)
7/25/77 (42 FR 37936)
8/17/77 (42 FR 41424)
3/3/78 (43 FR 8800)

Affected
facility

Electric submerged arc
furnaces

Dust handling equip-
ment
Pollutant

Participate

Opacity
CO
Opacity

Emission level

0.99 Ib/W-hr
(0.45 kg/W-hr)
(•high silicon alloys*)
0.51 Ib/MU-hr
(0.23 kg/HH-hr)
(chrome and Manganese
alloys) .

No visible Missions
may escape furnace
capture system
No visible emission
may escape tapping
system for >40J of
each tapping period
15S
20J volume basis
10X

Monitoring
requirement

No requirement

Flowrate
monitoring In
hood
Flowrate
monitoring In
hood

Continuous
No requirement
No requirement

-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES (Continued)
00
Source category
Subpart AA - Steel Plants
Proposed/ef f ectl ve
10/21/74(39 FR 37466}
Promulgated
9/23/75 (40 FR 43850)
Revised
7725777 (40 FR 37936)
8/17/77 (42 FR 41424)
9/7/77 (42 FR 44812)
3/3/78 (43 FR 8800)
Affected
facility
Electric arc furnaces
Dust handling equip-
ment
Pollutant
Partlculate
Opacity
(a) control device
(b) shop roof
Opacity
Emission level
0.0052 gr/dscf
(12 •g/dscaO
3X
OX except
<20X-charg1ng
<40X- tapping
10X
Monitoring
requirement
No requirement
Continuous
Flowrate
monitoring In
capture hood.
Pressure
monitoring
In DSE system
No requirement
-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES (Continued)
I
_J

to
Source category
Subpart BB - Kraft Pulp Hills
Proposed/effective
9/24/76 (41 FR 42012)

Promulgated
2/23/78 (43 FR 7568)

Revised
87777S~(« FR 34784)

Affected
facility

Recovery furnace

Smelt dissolving tank

Lime kiln

Digester, brown stack
Masher, evaporator,
oxidation, or strip-
per systems

Pollutant

Paniculate

Opacity

TRS
(a) straight recovery

(b) cross recovery

Parti cul ate

TRS

Participate
(a) gaseous fuel

(b) liquid fuel

TRS

Emission level

0.044 gr/dscf
(0.10 g/dscm)
corrected to
8X oxygen

35*

5 ppm by volume
corrected to 8X
oxygen
25 ppm by volume
corrected to 8X
oxygen
0.2 Ib/ton
(0.1 g/kg
0.0168 Ib/ton
(0.0084 g/kg)
0.067 gr/dscf
(0.15 g/dson)
corrected to
10X oxygen
0.13 gr/dscf
(0.30 g/dscm)
corrected to
IDS oxygen
8 ppm by volume
corrected to 10X
oxygen
5 ppm by volume
corrected to 10X
oxygen*

•exceptions;
see standards

Monitoring
requirement

No requirement

Continuous

No requirement

Continuous

Continuous •

Effluent gas Incinera-
tion temperature; scrub-
ber liquid supply pres-
sure and gas stream
pressure loss
-------
STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES (Continued)
I
ro
o
Source category
Subpart DO - Grain Elevators
Proposed/effective
8/3/78 (43 FR 34349)
Promulgated
8/3/78 (43 FR 34340)

Subpart HH - L1me Manufacturing P
Proposed/effective
5/3/77 (42 FR ZZ506)

Promulgated
3/7/78 (43 FR 9452)
Affected
facility

Column and rack
dryers
Process equipment
other than dryers
Fugitive emissions:
Truck unloading;
railcar loading
or unloading
Grain handling
Truck loading
Barge, ship
loading
ants
Rotary Urae kiln

L1me hydrator
Pollutant

Opacity
Partlculate
Opacity
Opacity
Opacity
Opacity
Opacity

Partlculate
Opacity
Partlculate
Emission level

0%
0.01 gr/dscf
(0.023 g/dson)
0%
5X
OX
10X
20%

0.30 Ib/ton
(0.15 kg/Mg
10X
0.15 Ib/ton
(0.075 kg/Mg)
Monitoring
requirement

No requirement
No requirement
No requirement
No requirement
No requirement
No requirement
No requirement

No requirement
Continuous except
when using wet
scrubber
No requirement
Mass of feed to
rotary lime kiln
and hydrator
-------
Title 40—PROTECTION OF

ENVIRONMENT

Chapter I—Environmental Protection
Agency
SUBCHAPTER C—AIR PROGRAMS
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES'-1"

Subpart A—General Provisions
Sec.
60.1 Applicability.
60.2 Definitions.'
60.3 Abbreviations.
60.4 Address.
60.5 Determination of construction or
modification.
60.6 Review of plans.
60.7 Notification and record keeping.
60.8 Performance tests.
60.9 Availability of Information.
60.10 State authority.
60.11 Compliance with standards and
maintenance requirements.4
60.13 Circumvention.5
60.13 Monitoring requirements.
V8
60.14 Modification.
22
,22
60.15 Reconstruction/
Subpart B—Adoption and Submittnl of State
Plan* for Designated Facilities 21
Sec.
60.20 Applicability.
60.21 Definitions.
60.22 Publication of guideline documents,
emission guidelines, and final com-
pliance times.
60.23 Adoption and submlttal of State
plans; public hearings.
60.24 Emission standards and compliance
schedules.
60.26 Emission Inventories, source sur-
veillance, reports.
60.26 Legal authority.
60.27 Actions by the Administrator.
60.28 Plan revisions by the State.
60.29 Plan revisions by the Administrator.

Oubpart C—Emission OuMelmos cod
Compliance Time* 73
Sec. i
60.30 Scope.
•6.31 Definitions.
00.82 Designated facilities.
6043 Bmleslon guidelines.
60.34 Compliance times.

Subpert D—Stendcrds of Performance
for FoMH-Fuet-Flrtd Steam Generators
for Which Construction Is Commenced
After August 17,1871 98

60.40 Applicability and designation of af-
fected facility.
60.41 Definitions.
60.42 Standard for partlculate matter.
60.43 Standard for sulfur dioxide.
60.44 Standard for nitrogen oxldee.
60.46 Emission and fuel monitoring.
60.46 Test methods and procedures.
Subpart Do—Standard* of Performance for
Electric Utility Steam Generating Unit* for
Which Contraction li Commenced After Sep-
tember 10, 1970 "
Sec.
60.40& Applicability and designation of
affected facility.
60.41a Definition*.
60.42a Standard for particulate matter.
60.43a Standard for sulfur dioxide.
60.44a Standard for nitrogen oxides.
60.45a Commercial demonstration permit.
60.40a Compliance provisions.
60.47a Emission monitoring.
60.48a Compliance determination
procedures and methods.
60.49a Reporting requirements.

Subpart E—Standards of Performance for
Incinerators
60.50 Applicability and designation of af-
fected facility.
60.61 Definitions.
60.62 Standard for partlculate matter.
60.63 Monitoring of operations.
60.64 Test methods and procedures.

Subpart F—Standards of Performance fo>
Portland Cement Plants
60.60 Applicability and designation of
affected facility.
60.61 Definition*.
60.62 Standard for paniculate matter.
60.63 Monitoring of operations.
60.64 Test methods and procedures.

Subpart C—Standards of Performance for Nitric
* Add Plants
60.70 Applicability and designation of af-
fected facility.
60.71 Definitions.
60.72 Standard for nitrogen oxides.
60.73 Emission monitoring.
60.74 Test methods and procedure*.

Subpart H—Standards of Performance for Sulfurlc
Acid Plants
60.80 Applicability and designation of af-
fected facility.
60.81 Definitions.
60.82 Standard for sulfur dioxide.
60.83 Standard for acid mist.
60.84 Emission monitoring.
60.86 Test methods and procedures.

Subpart I—Standards of Performance for Asphalt
Concrete Plants 5
60.90 Applicability and designation of af-
fected facility.
60.91 Definitions.
60.92 Standard for partlculate matter.
60.93 Test methods and procedures.
Subpart J—Standards of Performance for
Petroleum Refineries5
60.100 Applicability and designation of af-
fected facility.
60.101 Definitions.
60.102 Standard for partlculate matter.
60.103 Standard for carbon monoxide.
60.104 Standard for sulfur dioxide.
60.105 Emission monitoring.
60.106 Test methods and procedures.

Subpart K—Standards of Performance for Storage
Vessels for Petroleum Uqulds 5
60.110 Applicability and designation of
affected facility.
60.111 Definitions.
60.112 Standard for hydrocarbons.
60.113 Monitoring of operations.

Subpart L—Standards of Performance for
Secondary Lead Smelters 5
Sec.
60.120 Applicability and designation of
affected facility.
60.121 Definitions.
60.122 Standard for partlculate matter.
60.123 Test methods and procedures.

Subpart M—Standards of Performance for Sec-
ondary Brass and Bronze Ingot Production Plants5
60.130 Applicability and designation of
affected faculty.
60.131 Definitions.
60.132 Standard for partlculate matter.
60.133 Test methods and procedures.

Subpart N—Standards of Performance for Iron
and Steel Plants 5
60.140 Applicability and designation of
affected facility.
60.141 Definitions.
60.142 Standard for partlculate matter.
60.143 (Reserved]
60.144 Test methods and procedures.
Subpart O—Standards of Performance for
Sewage Treatment Plants 5
60.160 Applicability and designation of
affected facility.
60.161 Definitions.
60.152 Standard for partlculate matter.
60.163 Monitoring of operations.
60.154 Test methods and procedures.

Subpart P—Standards of Performance for
Primary Copper Smelters 26
00.160 Applicability and designation of af-
fected facility.
60.161 Definitions.
60.162 Standard for partlculate matter.
60.163 Standard for sulfur dioxide.
60.164 Standard for visible emissions.
60.166 Monitoring of operations.
60.166 Test methods and procedures.
Subpart Q—Standards of Performance for
Primary Zinc Smelters 2 6
60.170 Applicability and designation of
affected facility.
60.171 Definitions.
60.172 Standard for partlculate matter.
60.173 Standard for sulfur dioxide.
60.174 Standard for visible emissions.
60.175 Monitoring of operations.
60.176 Test methods and procedures.

Subpart R—Standards of Performance for
Primary Lead Smelters 2*
60.180 Applicability and designation of
affected facility.
60.181 Definitions.
60.182 Standard for partlculate matter.
60.183 Standard for sulfur dioxide.
60.184 Standard for visible emissions.
60.185 Monitoring of operations.
60.186 Test methods and procedures.
Subpart S—Standards of Performance for
Primary Aluminum Reduction Plants'''
60.190 Applicability and designation of af-
fected facility.
60.191 Definitions.
60.192 Standard for fluorides.
60.193 Standard for visible emissions.
60.194 Monitoring of operations.
60.195 Test methods and procedures.
Subpart T—Standards of Performance for the
Phosphate Fertilizer Industry: Wet Process
Phosphoric Acid Plants ' 4
60.200 Applicability and designation of
affected facility.
60.201 Definitions.
60.202 Standard for fluorides.
60.203 Monitoring of operations.
60.204 Test methods and procedures.
Subpart U—Standards of Performance tor the
Phosphate Fertilizer Industry: Superphosphorlc
Acid Plants'4
60.210 Applicability and designation of
affected facility.
60.211 Definitions.
60.212 Standard for fluorides.
60.213 Monitoring of operations.
60.214 Test methods and procedures.
Subpart V—Standards of Performance for the
Phosphate Fertilizer Industry: Dlammonlum
Phosphate Plants'4
60.220 Applicability and designation of
affected facility.
III-l
-------
60.221 Definitions.
60.222 Standard for fluorides.
60.223 Monitoring of operations.
60.224 Test methods and procedures.
Subpart W—Standards of Performance for th«
Phosphate Fertilizer hidustry: Triple Super-
phosphate Plants'4
60.230 Applicability and designation of af-
fected facility.
60.231 Definitions.
60.232 Standard for fluorides.
60.233 Monitoring of operations.
60.234 Test methods and procedures.
Subpart X—Standards of Performance for th»
Phosphate Fertilizer Industry: Granular Triple
Superphosphate Storage Facilities '4
fin240 Applicability and designation of af-
fected facility.
60.241 Definitions.
H0.242 Standard for fluorides.
60.243 Monitoring of operations.
60.244 Test methods and procedures

Subpart V—Standards of Performance for Coal
Preparation Plants26
60.250 Applicability and designation of
affected facility.
60.251 Definitions.
60.262 Standards for partlculate matter.
60.253 Monitoring of operations.
60.254 Test methods and procedures.
Subpart Z—Standards of Performance for Ferro-
alloy Production Facilities 33
60.260 Applicability and designation of
affected facility.
60.261 Definitions.
60.262 Standard for partlculate matter.
60.263 Standard for carbon monoxide.
60.264 Emission monitoring.
60.265 Monitoring of operations.
60.266 Test methods and procedures.
Subpart AA—Standards of Performance for Steel
Plants: Electric Arc Furnaces' &
60.270 Applicability and designation of af-
fected facility.
60.271 Definitions.
60.272 Standard for partlculate matter.
60.273 Emission monitoring.
60.274 Monitoring of operations.
60.275 Test methods and procedures.

Subpart M—Standard! of Performance for
Kraft Pulp Mllli82

60.280 Applicability and designation of af-
fected facility.
60.281 Definitions.
60.282 Standard for partlculate matter.
60.283 Standard for total reduced sulfur
(TRS).
60.284 Monitoring of emissions and oper-
ations.
60.285 Test methods and procedures.
Subpart DO—Standard* of Performance for
Grain Elevator. 90

Sec.
60.300 Applicability and designation of af-
fected facility.
60.301 Definitions.
60.302 Standard for partlculate matter.
60.303 Test methods and procedures.
60.304 Modification.
Subpart HH—Standards of Perfor-
mance for Lime Manufacturing
Plant*85

Sec.
60.340 Applicability and designation of af-
fected facility.
60.341 Definitions.
60.342 Standard for paniculate matter.
60.343 Monitoring of emissions and oper-
ations.
60.344 Test methods and procedures.
Appendix A—Reference Methods
14
Method 1—Sample and velocity traverses for
stationary sources.
Method 2—Determination of stack gas ve-
locity and volumetric flow rate (Type 8
pltot tube).
Method 3—Gas analysis for carbon dioxide.
excess air. and dry molecular weight.
Method 4—Determination of moisture In
stack gases.
Method 5—Determination of partlculate
emissions from stationary sources.
Method 6—Determination of sulfur dioxide
emissions from stationary sources.
Method 7—Determination of nitrogen oxide
emissions from stationary sources.
Method 8—Determination of sulfurlc acid
mist and sulfur dioxide emissions from
stationary sources.
Method 9—Visual determination of the opac-
ity of emissions from stationary sources.
Method 10—Determination of carbon monox-
ide emissions from stationary sources.5
Method II—DETERMINATION OF HYDROGEN
SULFIDE CONTENT OP FUEL CAS STREAMS IN
PETROLEUM REFINERIES 79
Method 12—(Reserved]
Method ISA—Determination of total fluoride
emissions from stationary sources—
SPADNS Zirconium Lake Method.
Method 13B—Determination of total fluoride
emissions from stationary sources—Spe-
cific Ion Electrode Method.
Method 14—Determination of fluoride emis-
sions from potroom roof monitors of
primary aluminum plants.27

METHOD 15. DETERMINATION OF HYDROGEN
SULFIDE, CARBONYT. SDLFIDE, AND CARBON
DISULFIDE EMISSIONS FROM STATIONARY
SOURCES86

METHOD- 1«. SEMICONTINUOUS DETERMINATION
OF SULFUR EMISSIONS FROM STATIONARY
SOURCES 82

METHOD 17. DETERMINATION OF PARTICULATE
EMISSIONS FROM STATIONARY SOURCES (IN-
.iTACK FILTRATION METHOD)82
METHOD It. WTEMTlfATKm OF SQLFUlt-DIOX-
IDE REMOVAL ITFICIENCY AND PARTICULAR.
S0LFUB DIOXIDE AMD WmUXSW OXIDES EMIS-
SION BATC8 F«OM BLBCTWC UTILITY STEAM
GOIOtATOM
Appendix B—Performance Specifications18
Performance Specification 1—Performance
specifications and specification test proce-
dures for transmlssometer systems for con-
tinuous measurement of the opacity of stack
emissions.
Performance Specification 2—Performance
specifications and specification test proce-
dures for monitors of SO, and NO. from
stationary sources.
Performance Specification 3—Performance
specifications and specification test proce-
dures for monitors of CO, and O, from sta-
tionary sources.
Appendix c—Determination of Emission
Rate Change 2 2
Appendix D—Required Emission Inventory
Information 21
AUTHORITY: Sec. Ill, 301(a) of the Clean
Air Act as amended (42 UJB.C. 7411.
7601(a», unless otherwise noted. 68,83
III-2
-------
(SE) Hew Hampshire Air Pollution
Control Agency, Department of Health
ond Welfare. State Laboratory Building.
Hazen Drive. Concord, New Hampshire
(FF)—State of Hew Jersey: Net? Jersey De-
partment of Environmental Protection,
John Pitch Plaza. P.O. BOK 2£07. Trenton,
Nety Jerray CSS26.63

(GG) [reserved].

(KM)—Nou 'STorts: Kot? YorU Stoto Oo-
portment of Environmental Conservation, BO
Wolf Road. Woo Torts 12233. attention: Dlvl-
O5on of Air Hesourcea.'"
(II) North Caroline Environmental Man-
agement Commission. Department of Natural
and Economic Resources, Dlvlalon of Envi-
ronmental Management. P.O. Bos 273B7. Ra-
leigh, North Caroline 27611. Attention: Air
Quality Cectlon. 34
(JJ)- State of North Dakota, State Depart-
ment of Health, State Capitol, Bismarck
North Dakota 58501.47
(ESS) Ohio—
Medina, Summit and Portage Counties;
Director. Air Pollution Control. 177 South
Broadway, Akron. Ohio, 44303.
Stark County; Director, Air Pollution Con-
trol Division, Canton City Health Depart-
ment, City Hall, 218 Cleveland Avenue SW,
Canton, Ohio, 44702.
Butler, Ctermont, Hamilton and Warren
Counties; Superintendent, Division of Air
Pollution Control, 2400 Bee&man Street, Cin-
cinnati. Ohio, 46214.
Cuyahoga County; Commissioner, Division
of Air Pollution Control, Department of
Public Health and Welfare, 2735 Broadway
Avenue, Cleveland, Ohio, Oil 15.
Loreln County; Control Oacer, Division of
Air Pollution Control, 200 West Erie Avenue,
7th Floor, Loraln, Ohio, 44052.
Belmont, Carroll, Columblana, Harrison,
Jefferson, and Honroa Counties; Director,
North Ohio Valley Air Authority (NOVAA).
014 Adams Street, Steubenvllle, Ohio, 43052.
Cleric, Darte, Greene, Miami, Montgomery,
and Prsble Counties; Supervisor, Regional
Air Pollution Control Agency (RAPCA),
Montgomery County Health Department. 491
West Third Street, Dayton, Ohio, 45402.
Luces County and the City of Rossford (in
Wood County); EHrocto?, Totedo BoUutto
Control Agency. 26 Main Street, Toledo, Ohio,
-13869.
Adams, Broxrn, Lawrence. a*nd Scioto
Counties; Saglnear-Dlrector, Air Division.
Portsmouth city Health Department. 740
Eecond Street, Portsmouth, Ohio, 45662.
Allen, Ashland, Auglalze, Crawford, De-
fiance, Erie, Pulton, Hancock, H&rdln, Henry.
Huron, Knoz, Marlon, Mercer, Morrow.
Ottawa, Faulting, Putnam, EUchland, San-
fiuafcy, E3&3C&, Van Wert, Williams.
Wood (except City of Etossford), and Wyan-
dot Counties; Ohio Environmental Pro tec-
«ton- Agency, Northwest District OSce, ill
West Washington Street, Bowling Oreen,
Ohio. 43402.
Ashtabulo. Geauga. Lake, Mahonlug,
Tnimbull, and Wayne Counties; Ohio Envi-
ronmental Protection Agency, Northeast Dis-
trict OQce, 2110 Bast Aurora Road, Twins-
burg, Ohio. 44037.
Athens, Ooshocton, O&llla, Guernsey, Hlgh-
lond, Hcclrlng. Holmes. JocScon, Helgs
Morgan. tauoSlngum, Noble. Perry, Pl&e.
Boso. Tuscarawos, Vlnton, and Washington
Counties; Ohio Environmental Protection
/Vjency. SouQjeest District Offlce, Boute 3,
.Eon 603. Logan, Ohio. 43138.
Champaign. Clinton, Lagan. ™id Shelby
Counties; Ohio Bnvtronnsontal Protection
Agency, eau&rccjt District OQce, 7 Bast
Courth g&nxA. Bayion. Ohio. 0&S02.
FaSrScSd. Etoyotto, Fran&lln.
£2c£±a»n. IKc&OTTay, oafl VJsMon
QMo BaTiyossEJOffltcJ !?s«tocaon
Agency. Opnteal BZofertct Office. 889 East
Brood Sferen. Columbia. Cfcto, C3318.33
(LL) (rearved).
(MM) — Stats of Oregon, Department
of Environmental Quality, J23€ SWW
Morrison Street, Portland. Oregon 07205.
(NN)(a) City of Philadelphia: Philadelphia
Department of Public Health, Air Man-
caomont Eorvlca. C01 Arch Rf?eot. ipfcuo-
fislphla. Ponnoylvanla 10107.^
(OO) State of Rhode Island. Department
of Environmental Management, 83 Park
Street. Providence, R.I. 02908 '2
(FP) State of South Carolina, C3ce of
environmental Quality Control. Etsjiartzaant
of Health and Environmental Coate-ol, 2S&1
Bull Street. Columbia, South Carolina 28201?6
«QQ) State of South Dakota, Depart-
ment of Environmental Protection, Jos
Foss Building, Pierre, South Dakota
57501 32
(RRj (reserved).

(SS) State of Texas, Texas Air Con-
trol Board, 8520 Shoal Creek Boule-
vard. AusUa, Tesas 7S758.95
(TT) — State of Utah, Utah Air Con-
servation Committee, State Division of
Health, 44 Medical Drive, Salt Lake City,
Utah 84113. 3'
(O"U)— State of Vermont, Agoncy of Environ-
mental Protection. Eos ££3. Moatpollor.
Vermont 08302. ^
(W) Commonwealth of Virginia, Vir-
cinia State Air Pollution Control Board
Room 1106, Ninth Street Office Building
Richmond, Virginia 23219. 30
(WW) (1) Washington; State of Washing-
ton, Department of Ecology, Olympla, Wash-
ington 985O4.
( 11) Northwest Air Pollution Authority, 207
Pioneer Building, Second and Pine Streets.
Mount Vernon, Washington 98273.
(Ill) Puget Sound Air Pollution Control
Agency,' 410 West Harrison Street, Seattle,
Washington 881 19.
(Iv) Spoicane County Air Pollution Control
Authority, North Oil Jefferson, Spokane,
Washington 89201.
(v) Southtveot Air Pollution Control Au-
tSJOSity.-Siilta 7801 H. WE Hc^el Ctell Aveuus,
yaiicouvsr,. Washington BS836. lz<"
(vi) Olympic Air Pollution Control
Authority, 120 East State Avenue,
Olympia, WA 98501 ,97

OCX) (reserved).
(YY)
(a) When requested to do so by an
owner or operator, the Administrator
will make a determination of whether
action taken or intended to be taken by
such owner or operator constitutes con-
struction (including reconstruction) ox-
modification or the commencement
thereof within the meaning of this part.
(b) The Administrator will respond to
any request for a determination under
paragraph (a) of this section within 30
days of receipt of such request.
10=
(B) When requested to do so by aa
owner or operator, the Administrator wffl
review plans for construction or modfca=
cation for the purpose of providtas
technical advice to the owner or operator.
(b) (1) A separate request shall be sub-
mitted for each construction or modifi-
cation project. 5
(2) Each request shall Identify the lo-
cation of such project, end be accom-
panied by technical information describ-
ing the proposed nature, size, design, and
method of operation of each affected fa-
cility involved in such project, including
Information on any requipment to bs
used for measurement or control of emis-
sions. 5
(c) Neither a request for plans revise
Kjor advice furnished by the Administer
tor in response to such request snail (i>
relieve an owner or operator of
Responsibility for compliance with
v_ __ if too. H wv VMA &Mg 6>£*jyUl*2X*jWa>
State or local requirement, or (3) prewsafi
fche Administrator from implementing ®?
enforcing any provision of this p&rft
Acfe.
cm&
(B) Any owner or operator su&jesfi
the provisions of this parfe shall
Dsportsnoat of Woturol ffisaousxsss.
P.O. ®oa VB31. Mofllcon,
(22) State of Wyoming, Air Quality Ol-
vision of the Department of Environmental
Quality. Hathaway Building, Cheyenne, Wyo.

(AAA) (reserved).

(BBB) — Commonwealth of Puerto Rico
Commonwealth of Puerto Rico Environ-
mental Quality Board. P.O. Box 11786. San-
turce.P.R. 00910 n

•fiCCC)— US. Virein Xslands: VS. Vir-
gin Islands Department of Conservation
and Cultural Affairs, P.O. Sox 578, Char-
Jott® Amalie, St. Thomas, U.S. Virgin
Islands 00801. 4*

(ODD) (reserved).
follows:
(DA notification of the date construc-
tion (or reconstruction as defined under
9 60.15) of an affected facility is com-
menced postmarked no later than 30
days after such date. This requirement
shall not apply in the case of mass-pro-
duced facilities which are purchased in
completed form.22
(2) A notification of the anticipated
date of initial startup of an affected
facility postmarked not more than 60
days nor less than 30 days prior to such
date. 22
(3) A notification of the actual date
of initial startup of an affected facility
postmarked within 15 days after siicto
date. 22
- (4) A notification of any physical or
operational change to an existing facil-
ity^which may increase the emission rate
of any air pollutant to which a stand-
ard applies, unless that change Is spe-
cifically exempted under an applicable
III-5
-------
subpart or to 0 SO.H(e) arid the exemp-
tion to not denied under 0 SO.lO(d) (4).
This rastiCQ ahell be postmarked 80 days
or DS soon os practicable before the
change is commenced and shall include
information describing the precise na-
fcure of the change, present and proposed
omission control systems, productive
'©opacity of the facility before and after
4S»e change, and the expected comple-
tion date of the change. The Administra-
tor may request additional relevant In-
formation subsequent to this notice. «
(S) A notification of the date upon
which demonstration of the continuous
monitoring system performance com-
mences in accordance with i 60.13 (c) .
Notification shall be postmarked not less
than 30 days prior to such date. ' 8 '
(b) Any owner or operator subject to
the provisions of this part shall main-
tain records of the occurrence and dura-
tion of any startup, shutdown, or mal-
function in the operation of an affected
facility; any malfunction of the air pol-
lution control equipment; or any periods
during which a continuous monitoring.
system or monitoring device is inopera-
tive. 18
(c) Each owner or operator required
to install a continuous monitoring sys-
tem shall submit a written report of
excess emissions (as denned in applicable
oubparts) to the Administrator for every
calendar quarter. All quarterly reports
shall be postmarked by the 30th day fol-
lowing the -end of each calendar quarter
and shall include the following informa-
18
,(1) The magnitude of excess emissions
computed in accordance with § 60.13 (h),
any conversion factor(s) used, and the
date and time of commencement and
completion of each time period of excess
emissions. '8
(2) Specific identification of each
period of excess emissions that occurs
during startups, shutdowns, and mal-
functions of the affected facility. The
raeture and cause of any malfunction (if
bnown), the corrective action taken or
preventative measures adopted.19
(3) The date and time identifying each
period during which the continuous
monitoring system was inoperative ex-
cept for zero and span checks and the
nature of the system repairs or adjust-
ments. 18
(<3) When no excess emissions have
occurred or the continuous monitoring
system (s) have not been inoperative, re-
paired, or adjusted, such information
shall be stated in the report. 4, 18
(d) Any owner or operator subject to
the provisions of this part shall maintain
n flle of all measurements, including con-
tinuous monitoring system, monitoring
device, and performance testing meas-
urements; all continuous monitoring sys-
tem performance evaluations: all con-
tinuous monitoring system or monitoring
device calibration checks; adjustments
and maintenance performed on these
systems or devices; and all other infor-
mation required by this part recorded in
a permanent form suitable for Inspec-
tion. The flle shall be retained for at least
two years following the date of such
measurements, maintenance, reports, and
records. 3,10
(e> If notification substantially similar
to that in paragraph (a) of this section
Is required by any other State or local
agency, sending the Administrator a
copy of that notification will satisfy the
requirements of paragraph (a) of this
section.22
(Sec. 114. Clean Air Act is amended (42
U.S.C. 7414)). 68, 83

§ 60.® Perfonmamice SeoRo.
(a) Within 60 days after achieving ths
maximum production rat® at which ttea
affected facility will be operated, but not
later than 180 days after initial startup
of such facility and at such other times
as may be required by the Administrator
under section 114 of the Act, the owner
or operator of such facility shall conduct
performance test(s) and furnish the Ad-
ministrator a written report of the results
of suoh performance test(s).
(b) Performance tests shall be con-
ducted and data reduced in accordance
with the test methods and procedures
contained in each applicable subpart
unless the Administrator (1) specifies
os approves, in specific cases, the use c2
a reference method with minor changes
in methodology, (2) approves the use
of an equivalent method, (3) approves
the use of an alternative method the re-
sults of which he has determined to be
adequate for indicating whether a spe-
cific source is in compliance, or (4)
waives the requirement for performance
tests because the owner or operator of
& source has demonstrated by other
means to the Administrator's satisfac-
tion that the affected facility is in. com-
pliance with the standard. Nothing in
this paragraph shall be construed to
abrogate the Administrator's authority
to require testing under section 114 of
the Act.3
(c) Performance tests shall be con-
ducted under such conditions as the Ad-
ministrator shall specify to the plant
operator based on representative per-
formance of the affected facility. The
owner or operator shall make available
to the Administrator such records as may
be necessary to determine the conditions
of the performance tests. Operations
during periods of startup, shutdown, and
malfunction shall not constitute repre-
sentative conditions for the purpose of a
performance test nor shall emissions in
excess of the level of the applicable emis-
sion limit during periods of 'startup,
shutdown, and malfunction be con-
sidered a violation of the applicable
emission limit unless otherwise specified
in the applicable standard.4-74
(d) The owner or operator of an
affected facility shall provide the
Administrator at least 30 days prior
notice of any performance test, except
as specified under other oubparts, to
afford the Administrator the opportunity
to have an observer present.5-98
(e) The owner or operator of an
affected facility shall provide, or cause to
tea provided, performance testing fecM-
S&ea tas follows:

-------
Subpcrt D—Standards of Performance
for Fossll-Fuel-Fired Steam Generators
for Which Construction Is Commenced
Artor August 17,197198
§ 60.40 Applicability and designation of
affected facility. 8,49,44,94

(a) "Hie affected facilities to which the
provisions of this subpart apply are:
(1) Each fosstl-fuel-flred steam gen-
erating unit of more than 73 megawatts
heat input rate (250 million Btu per
hour).
(2) Each fossil-fuel and wood-resldue-
flred steam generating unit capable of
firing fossil fuel at a heat input rate of
more than 73 megawatts (250 million
Btu per hour).
(b) Any change to an existing fossll-
fuel-flred steam generating unit to
accommodate the use of combustible
materials, other than fossil fuels an
denned in this subpart, shall not brino
that unit under the applicability of this
subpart.
(c) Except as provided In paragraph
(d) of this section, any facility under
paragraph (a) of this section that com-
menced construction or modification
after August 17, 1971, is subject to the
requirements of this subpart.84
(d) Any facility covered under Subpart
Da is not covered under This Subpart.8498
§ 60.41 Definitions.8
As used in this subpart, all terms not
denned herein shall have the meaning
given them in the Act, and in Subpart A
of this part.
(a) "Fossil-fuel fired steam generat-
ing unit" means a furnace or boiler used
in the process of burning fossil fuel for
the purpose of producing steam by heat
transfer.
(b) "Fossil fuel" means natural gas.
petroleum, coal, and any form of solid,
liquid, or gaseous fuel derived from such
materials for the purpose of creating use-
ful heat.
(c) "Coal refuse" means waste-prod-
ucts of coal mining, cleaning, and coal
preparation operations (e.g. culm, gob,
etc.) containing coal, matrix material,
clay, and other organic and inorganic
material."
(d) "Fossil fuel and wood residue-fired
steam generating unit" means a furnace
or boiler used in the process of burning
fossil fuel and wood residue for the Pur-?
pose of producing steam by heat transfer.
(e) "Wood residue" means bark, saw-
dust, slabs, chips, shavings, mill trim,
and other wood products derived from
wood processing and forest management
operations.49
(f) "Coal" means all solid fuels clas-
sified as anthracite, bituminous, subbi-
tuminous. or lignite by the American
Society for Testing Material. Designa-
tion D 388-68.84
§ 60.42 Standard for participate matter.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
Into the atmosphere from any affected
facility any gases which:
(1) Contain particulate matter in ex-
cess of 43 nanograms per joule heat in-
put (0.10 Ib per million Btu) derived
from fossil fuel or fossil fuel and wood
residue.49
(2) Exhibit greater than 20 percent
opacity except for one six-minute pe-
riod per hour of not more than 27 per-
cent opacity.18'76
§ 60.43 Standard for sulfur dioxide.2'8
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility any gases which contain sulfur
dioxide in excess of:
(1) 340 nanograms per joule heat in-
put (0.80 Ib per million Btu) derived
from liquid fossil fuel or liquid fossil fuel
and wood residue.49
(2) 520 nanograms per joule heat in-
put (1.2 Ib per million Btu) derived from
solid fossil fuel or solid fossil fuel and
wood residue.40
(b) When different fossil fuels are
burned simultaneously in any combina-
tion, the applicable standard (in ng/J)
shall be determined by proration using
the following formula:
2/(340)+z(520)
from liquid fossil fuel or liquid fossil fuel
and wood residue.49
(3) 300 nanograms per joule heat in-
put (0.70 Ib per million Btu) derived
from solid fossil fuel or solid fossil fuel
and wood residue (except lignite or a
solid fossil fuel containing 25 percent,
by weight, or more of coal refuse) ."'4
(4) 260 nanograms per joule heat
Input (0.60 Ib per million Btu) derived
from lignite or lignite and wood resi-
due (except as provided under para-
graph (a)(5) of this section).84
(5) 340 nanograms per joule heat
Input (0.80 Ib per million Btu) derived
from lignite which is mined In North
Dakota, South Dakota, or Montana
and which is burned in a cyclone-fired
unit.84
(b) Except as provided under para-
graphs (c) and (d) of this section,
when different fossil fuels are burned
simultaneously in any combination,
the applicable standard (in ng/J) is de-
termined by proration using the fol-
lowing formula:

- ttX260)+K86)+lK130)+*300)
where:
where:

PSsoa is the prorated standard for sulfur
dioxide when burning different fuels
simultaneously, in nanograms per joule
heat input derived from all fossil fuels
fired or from all fossil fuels and wood
residue fired,
!/ is the percentage of total heat input de-
rived from liquid fossil fuel, and
z is the percentage of total heat input de-
rived from solid fossil fuel.49

(c) Compliance shall be based on the
total heat input from all fossil fuels
burned, Including gaseous fuels.
§ 60.44 Standard for nitrogen oxides.8
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility any gases which contain nitro-
gen oxides, expressed as NO2 in excess of:
(1) 86 nanograms per joule heat input
(0.20 Ib per million Btu) derived from
gaseous fossil fuel or gaseous fossil fuel
and wood residue.49
(2) 130 nanograms per joule heat in-
put (0.30 Ib per million Btu) derived
s the Prorated standard for nitro-
gen oxides when burning different
fuels simultaneously, in nanograms
per joule heat Input derived from all
fossil fuels fired or from all fossil fuels
and wood residue fired;
tc=ls the percentage of total heat input
derived from lignite;
x*-\s the percentage of total heat input
derived from gaseous fossil fuel;
V-ls the percentage of total heat input
derived from liquid fossil fuel; and
2- is the percentage of total heat Input de-
rived from solid fossil fuel (except lig-
nite). 'I.49.**
(c) When a fossil fuel containing at
least 25 percent, by weight, of coal
refuse is burned in combination with
gaseous, liquid, or other solid fossil
fuel or wood residue, the standard for
nitrogen oxides does not apply.84
(d) Cyclone-fired units which burn
fuels containing at least 25 percent of
lignite that is mined in North Dakota,
South Dakota, or Montana remain
subject to paragraph (a)(5) of this sec-
tion regardless of the types of fuel
combusted in combination with that
lignite.84

4, 8,18,
§ 60.45 Emission and fuel monitoring.
(a) Each owner or operator shall in-
stall, calibrate, maintain, and operate
continuous monitoring systems for meas-
uring the opacity of emissions, sulfur
dioxide emissions, nitrogen oxides emis-
sions, and either oxygen or carbon di-
oxide except as provided in paragraph
(b) of this section. &
(b) Certain of the continuous moni-
toring system requirements under para-
graph (a) of this section do not apply
to owners or operators under the follow-
ing conditions: 57
(1) For a fossil fuel-fired steam gen-
111-15
-------
erator that burns only gaseous fossil
fuel, continuous monitoring systems for
measuring the opacity of emissions and
sulfur dioxide emissions are not re-
quired.37
(2) JFtor & fossil fuel-flred steam gen-
erator that does not use a flue gas de-
sulfurization device, a continuous moni-
toring system for measuring sulfur di-
oxide emissions is not required if the
owner or operator monitors sulfur di-
oxide emissions by fuel sampling and
analysis under paragraph (d) of this
section.57
(3) Notwithstanding §60.13(to), in-
stallation of a continuous monitoring
system for nitrogen oxides may be de-
layed'Until after the initial performance
tests under § 60.8 have been conducted.
If the owner or operator demonstrates
during the performance test that emis-
sions of nitrogen oxides are less than 70
percent of the applicable standards in
8 60.44, & continuous monitoring system
for measuring nitrogen oxides emissions
is not required. If the initial performance
test results show that nitrogen oxide
emissions are greater than 70 percent of
the applicable standard, the owner or
operator shall install a continuous moni-
toring system for nitrogen oxides within
one year after the date of the Initial per-
formance tests under 8 60.3 and comply
with all other applicable monitoring re-
quirements under this part.37
(4) If an owner or operator does not
install any continuous monitoring sys-
tems for sulfur oxides and nitrogen ox-
ides, as provided under paragraphs (b)
(1) and (b)(3) or paragraphs (b) (2)
and (b) (3) of this section a continuous
monitoring system for measuring either
oxygen or carbon dioxide is not required.
(c) For performance -evaluations un-
der 8 60.13 (c) and calibration checks
under 8 60.13(d), the following proce-
dures shall be used:57
, (1) Reference Methods S or ?, as ap-
plicable,-shall be used for conducting
performance evaluations of sulfur diox-
ide and nitrogen oxides continuous mon-
itoring systems.57
(2) Sulfur dioxide or nitric oxide, as
applicable, shall be used for preparing
calibration gas mixtures under Perform-
ance Specification 2 of Appendix S to
ails part.57
(3) For affected facilities burning fos-
sil fuel(s), the span value for a continu-
ous monitoring system measuring the
opacity of emissions shall be 80, 90, or
100 percent and for g, continuous moni-
toring system measuring sulfur oxides or
nitrogen osides the span value shall bs
determined as follows:
|In parts per million]
Fossil fuel
Gas -
Liquid
Solid
Combinations..
Span value for
sulfur dioxide
Span value for
nitrogen oxides
W 1.000
1,500
l,000l/+l,500z
500
500
500
500U+!/)+l,OOOj
E=tho fraction of total neat Input derived
from gaseous fossil fuel, and
y=the fraction of total beat Input derives
from liquid fossil fuel, cad
2= the fraction of total hoot input derived
from colld fcSsl ffuol.57
(4) All span values computed under
paragraph (c) (3) of this section for
burning combinations of fossil fuels shall
be rounded to the nearest 500 ppm.57
(5) For a fossil fuel-fired steam gen-
erator that simultaneously burns fossil
fuel and nonfossil fuel, the span value
of all continuous monitoring systems
shall be subject to the Administrator's
approval.57
(d) [Reserved)57
(e) For any continuous monitoring
system installed under paragraph (a) of
£hls section, the following conversion
procedures shall be used to convert the
continuous monitoring data into units of
the applicable standards (ng/J, Ib/mil-
lionBtu):49-57
(1) When .a continuous monitoring
system for measuring oxygen is selected,
the measurement of the pollutant con-
centration and oxygen concentration
shall each be on a consistent basis (wet
or dry). -Alternative procedures ap-
proved by the Administrator shall be'
used when measurements are on a wet
basis. When measurements are on a dry
basis, the following conversion procedure
shall be used:

s=-rf r 20-9 1
L 20.9—percent O8J

where:
E, C, F, and %0, are determined under pcro-
grapn (f) of thlsesctton. 57

(2) When a continuous monitortag
system for measuring carbon dioxide te
selected, the measurement of £he gsol-
Jutant concentration and carbon dtosifi®
concentration shall each be on c, ooa=
sistsnt basis (wet or Sry) and the fol-
lowing conversion procedure shall tee
used:
100 "I
percent CO»J
where:
S, C, Ft and %COj ore determined under
paragraph (f) of this section.37

(f) The values used In the equations
under paragraphs (e) (1) and (2) of tSjia
section are derived as follows:
(1) £=pollutanfc emissions, ng/J (lb/
million Btu).
(2) C=pollutant concentration, ng/
dscm (Ib/dscf), determined by multiply-
ing the average concentration (ppm) for
each one-hour period by 4.15x10* M ng/
dscm per ppm (2.59x10-° M Ib/dscf
~per ppm) where JW=pollutant molecu-
lar weight, g/g-mole (Ib/lb-mole). M=
34.07 for sulfur dioxide and 03.01 for ni-
trogen osddes.49
(3) %O», %CO2= oxygen or carbon
dioxide volume (expressed as percent),
determined with equipment specified un-
der paragraph (d) of this section.
(4) F, Fc= a factor representing a
ratio of the volume of dry flue gases
generated to the calorific value of the
fuel combusted (F), and a factor repre-
senting a ratio of the volume of carbpn
H'nxide gpriomt-oH to the calorific value
of of the fuel combusted (Fc), respective-
ly. Values of F and Fc are given as folr
lows:
(i) For anthracite coal as classified
according to A.S.T.M. D 388-66, F=
2.723x10'' dscm/J (10.HO dscf/million
Btu) and £",=0532x10-' scm CO,/J
0,880 scf CO,/million Bfcu).49
(ii) For subbitumlnous and bituminous
coal as classified according to A.S.T.M. D
S'88-66. F=2.637X10-7 dscm/J (9,820
dscf/million Btu) and ^=0.486X10-',,
ccm COs/J (1,810 scf COz/milllon Btu).
(ill) For liquid fossil fuels including
crude, residual, and distillate oils,
£•=2.476x10-' dscm/J (9.220 dscf/mil-
lion Btu) and F.=0.38«S) of this sectioa:49
[227.2 (pet. H)+65.5 (pet. Q+35.6 (pot. S)-f 8.? (pet. N)-28.? (pcfe. <
GCV
(S! units)
' Not applicable.

where:
(English units)
111-16
-------
a.oxio-*(pct. o
GCV

(81 units)

, _321X10'(%C)
GCV
(English units)
73,49,67
(1) H, C, 8, N, and O are content by
weight of hydrogen, carbon, sulfur, ni-
trogen, and oxygen (expressed as per-
cent) , respectively, as determined on the
same basis as GCV by ultimate analysis
of the fuel fired, using A.S.T.M. method
D3178-74 or D3176 (solid fuels) , or com-
puted from results using A.S.T.M. meth-
ods D1137-53(70). D1945-64(73). or
01946-67(72) (gaseous fuels) as applica-
ble.
(ii) GCV is the gross calorific value
(kJ/kg, Btu/lb) of the fuel combusted,
determined by the A.S.T.M. test methods
D 2015-66(72) for solid fuels and D 1826-
64(70) for gaseous fuels as applicable.49
(ill) For affected facilities which flre
both fossil fuels and nonfossil fuels, the
F or Fc value shall be subject to the
Administrator's approval.49
(6) For affected facilities firing com-
binations of fossil fuels or fossil fuels and
wood residue, the F or Fc factors deter-
mined by paragraphs (f ) (4) or (f ) (5) of
this section shall be prorated in accord-
ance with the applicable formula as fol-
lows:
(=1 i = l
where:
Xi=the fraction of total heat Input
derived from each type of fuel
(e.g. natural gas, bituminous
coal, wood residue, etc.)
Ft or (Fc) i =the applicable F or Fc factor for
each fuel type determined In
accordance with paragraphs
(f)(4) and (f)(5) of this
section.
n=the number of fuels being
burned In combination. 49

(g) For the purpose of reports required
under § 60.7(c) , periods of excess emis-
sions that shall be reported are defined
as follows:
(1) Opacity. Excess emissions are de-
fined as any six-minute period during
which the average opacity of emissions
exceeds 20 percent opacity, except that
one six-minute average per hour of up
to 27 percent opacity need not be re-
ported.76
(2) Sulfur dioxide. Excess emissions
for affected facilities are defined as:
(1) Any three-hour period during
which the average emissions (arithmetic
average of three contiguous one-hour pe-
riods) of sulfur dioxide as measured by a
continuous monitoring system exceed the
applicable standard under § 60.43.
(3) Nitrogen oxides. Excess emissions
for affected facilities using a continuous
monitoring system for measuring nitro-
gen oxides are defined as any three-hour
period during which the average emis-
sions (arithmetic average of three con-
tiguous one-hour periods) exceed the ap-
plicable standards under § 60.44.
(Sec. 114. Clean Air Act Is amended (42
U.S.C. 7414)).6fl. 83
§ 60.46 Test methods and procedures.8'18
(a) The reference methods in Appen-
dix A of this part, except as provided in
§ 60.8 (b) , shall be used to determine com-
pliance with the standards as prescribed
in §§ 60.42, 60.43, and 60.44 as follows:
(1) Method 1 for selection of sampling
site and sample traverses.
(2) Method 3 for gas analysis to be
used when applying Reference Methods
5, 6 and 7.
(3 ) Method 5 for concentration of par-
ticulate matter and the associated mois-
ture content.
(4) Method 6 for concentration of SO*
and
(5) Method 7 for concentration of
NOx.
(b) For Method 5, Method 1 shall be
used to select the sampling site and the
number of traverse sampling points. The
sampling time for each run shall be at
least 60 minutes and the minimum
sampling volume shall be 0.85 dscm (30
dscf ) except that smaller sampling times
or volumes, when necessitated by process
variables or other factors, may be ap-
proved by the Administrator. The probe
and filter holder heating systems in the
sampling train shall be set to provide a
gas temperature no greater than 433 K
(320°F) ,49
(c) For Methods 6 and 7, the sampling
site shall be the same as that selected
for Method 5. The sampling point In the
duct shall be at the centrold of the cross
section or at a point no closer to the
walls than 1 m (3.28 ft) . For Method 6,
the sample shall be extracted at a rate
proportional to the gas velocity at the
sampling point.
(d) For Method 6, the minimum sam-
pling time shall be 20 minutes and the
minimum sampling volume 0.02 dscm
(0.71 dscf) for each sample. The arith-
metic mean of two samples shall con-
stitute one run. Samples shall be taken
at approximately 30-mlnute Intervals.
(e) For Method 7, each run shall con-
sist of at least four grab samples taken
at approximately 15-mlnute Intervals.
The arithmetic mean of the samples
shall constitute the run value.
(f) For each run using the methods
specified by paragraphs (a)(3), (a) (4),
and (a) (5) of this section, the emissions
expressed in ng/J (Ib/million Btu) shall
be determined by the following pro-
cedure :
(3) Percent (X=oxygen content by
volume (expressed as percent), dry basis.
Percent oxygen shall be determined by
using the integrated or grab sampling
and anaylsis procedures of Method 3 as
applicable.

The sample shall be obtained as follows:
(1) For determination of sulfur diox-
ide and nitrogen oxides emissions, the
oxygen sample shall be obtained simul-
taneously at the same point in the duct
as used to obtain the samples for Meth-
ods 6 and 7 determinations, respectively
[§ 60.46(c)]. For Method 7, the oxygen
sample shall be obtained using the grab
sampling and analysis procedures of
Method 3.
(11) For determination of particulate
emissions, the oxygen sample shall be
obtained simultaneously by traversing
the duct at the same sampling location
used for each run of Method 5 under
paragraph (b) of this section. Method 1
shall be used for selection of the number
of traverse points except that no more
than 12 sample points are required.
(4) F = a factor as determined In
paragraphs (f) (4), (5) or (6) of § 60.45.
(g) When combinations of fossil fuels
or fossil fuel and wood residue are fired,
the heat input, expressed in watts (Btu/
hr), is determined during each testing
period by multiplying the gross calorific
value of each fuel fired (in J/kg or
Btu/lb) by the rate of each fuel burned
(in kg/sec or Ib/hr). Gross calorific
values are determined in accordance with
A.S.T.M. methods D 2015-66(72) (solid
fuels), D 240-64(73) (liquid fuels), or D
1826-64(7) (gaseous fuels) as applicable.
The method used to determine calorific
value of wood residue must be approved
by the Administrator. The owner or oper-
ator shall determine the rate of fuels
burned during each testing period by
suitable methods and shall confirm the
rate by a material balance over the steam
generation system.49

(Sec. 114. Clean Air Act is amended (42
U.S.C. 7414)).68'83
f-CF
20.9— percent O2
(1) E=pollutant emision ng/J (lb/
million Btu) .
(2 ) C=pollutant concentration, ng/
dscm (lb/ dscf ) , determined by method 5,
6, or 7.
36 FR 24876, 12/23/71 (1)

as amended

37 FR 14877, 7/26/72 (2)
38 FR 28564, 10/15/73 (4)
39 FR 20790, 6/14/74 (8)
40 FR 2803, 1/16/75 (11)
40 FR 46250, 10/6/75 (18)
40 FR 59204, 12/22/75 (23)
41 FR 51397, 11/22/76 (49)
42 FR 5936, 1/31/77 (57)
42 FR 37936, 7/25/77 (64)
42 FR 41122, 8/15/77 (67)
42 FR 41424, 8/17/77 (68)
42 FR 61537, 12/5/77 (76)
43 FR 8800, 3/3/78 (83)
43 FR 9276, 3/7/78 (84)
44 FR 3491, 1/17/79 (94)
44 FR 33580, 6/11/79 (98)
111-17
-------
Subpart Da—Standards of
Performance for Electric Utility Steam
Generating Units for Which
Construction Is Commenced After
September W, 187* 98
|60.40a AppncaMRymd designation of
affected facility.
(a) The affected facility to which this
subpart applies is each electric utility
steam generating unit:
(1) That is capable of combusting
more than 73 megawatts (250 million
Btu/hour) heat input of fossil fuel (either
alone or in combination with any other
fuel); and
(2) For which construction or
modification is commenced after
September 18,1978.
(b) This subpart applies to electric
utility combined cycle gas turbines that
are capable of combusting more than 73
megawatts (250 million Btu/hour) heat
input of fossil fuel in the steam
generator. Only emissions resulting from
combustion of fuels in the steam
generating unit are subject to this
subpart. (The gas turbine emissions are
subject to Subpart CO.)
(c) Any change to an existing fossil-
fuel-fired steam generating unit to
accommodate the use of combustible
materials, other than fossil fuels, shall
not bring that unit under the
applicability of this subpart
(d) Any change to an existing steam
generating unit originally designed to
fire gaseous or liquid fossil fuels, to
accommodate the use of any other fuel
(fossil or nonfossil) shall not bring that
unit under the applicability of this
subpart.
f 80.41s Deftnroona.
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.
"Steam generating unit" means any
furnace, boiler, or other device osed EOT
combusting fuel for the purpose of
producing steam (including fossil-fuel-
fired steam generators associated with
combined cycle gas turbines; nuclear
steam generators are not included).
"Electric utility.steam generating unit"
means any steam electric generating
unit that is constructed for the purpose
of supplying more than one-third of its
potential electric output capacity and •
more than 25 MW electrical output to
any utility power distribution system for
sale. Any steam supplied to a steam
distribution system for the purpose of
providing steam to a steam-electric
generator that would produce electrical
energy for sale is also considered in
determining the electrical energy output
capacity of the affected facility.
"Fossil fuel" means natural gas,
petroleum, coal, and any form of solid,
liquid, or gaseous fuel derived from sach
material for the purpose of creating
useful heat.
"Sobbihuninous coal" means coal that
is classified as subbitammon* A, B, or C
according to the American Society of
Testing and Materials' (ASTM)
Standard Specification for Classification
of Coals by Rank D388-66.
"Lignite" means coal that is classified
as lignite A or B according to the
American Society of Testing and
Materials' (ASTM) Standard
Specification for Classification of Coals
by Rank D388-68.
"Coal refuse" means waste products
of coal mining, physical coal cleaning,
and coal preparation operations (e.g.
culm, gob, etc.) containing coal, matrix
material, clay, and other organic and
inorganic material.
"Potential combustion concentration**
means the theoretical emissions (ng/J,
Ib/million Btu heat input) that would
result from combustion of a fuel in an
uncleaned state 9without emission
control systems) and:
(a) For particulate matter is:
(1) 3,000 ng/J (7Q Ib/million Btu) heat
input for solid fuel; and
(2) 75 ng/J (0.17 Ib/million Btu) heat
input for liquid fuels.
(b) For sulfur dioxide is determined
under § 60.48a(b).
(c) For nitrogen oxides is:
(1) 290 ng/I (0.87 Ib/million Btu) heat
input for gaseous fuels;
(2) 310 ng/J (0.72 Ib/million Btu) heat
input for liquid fuels; and
(3) 990 ng/I (2.30 Ib/million Btu) heat
input for solid fuels.
"Combined cycle gas turbine" means
a stationary turbine combustion system
where heat from the turbine exhaust
gases is recovered fay a steam
generating unit
"Interconnected" means that two or
more electric generating units are
electrically tied together by a network of
power transmission lines, and other
power transmission equipment
"Electric utility company" means the
largest interconnected organization,
business, or governmental entity that
generates electric power for sale (e^ a
holding company with operating
subsidiary companies).
"Principal company" means the
electric utility company or companies
which own the affected facility.
"Neighboring company" means any
one of those electric utility companies '
wtth one or more electric power
interconnections to the principal
company and which have
geographically adjoining service areas.
"Net system capacity" sneans the sum
of the net electric generating capability
(not necessarily equal to rated capacity)
of all electric generating equipment
owned by an electric utility company
(including steam generating units,
internal combustion engines, gas
tarbines. nuclear units, hydroelectric
units, and all other electric generating
equipment) plus firm contracted
purchases that are interconnected to the
affected facility that has the
malfunctioning flue gas desulfurizatton
system. The electric generating
capability of equipment under multiple
ownership is prorated based on
ownership unless the proportional
entitlement to electric output is
otherwise established by contractual
arrangement
"System load" means the entire
electric demand of an electric utility
company's service area interconnected
with the affected facility that has the
malfunctioning flue gas desuUnrization
system phis firm contractual sales to
other electric utility companies. Sales to
other electric utility companies (&%.,
emergency power) not on a firm
contractual basis may also be included
in the system load when no available
system capacity exists in the electric
utility company to which the power is
supplied for sale.
"System emergency reserves" means
an amount of electric generating
capacity equivalent to the rated
capacity of the single largest electric
generating unit in the electric utility
company (including steam generating
units, internal combustion engines, gas
turbines, nuclear units, hydroelectric
units, and all other electric generating
equipment) which is interconnected with
the affected facility that has the
malfunctioning flue gas desnlfurization
system. The electric generating
capability of equipment under multiple
ownership is prorated based on
ownership unless the proportional
entitlement to electric output is
otherwise established by contractual
arrangement.
"Available system capacity" means
the capacity determined by subtracting
the system load and the system
emergency reserves from the net system
capacity.
"Spinning reserve" means the sum of
the unutilized net generating capability
of all units of the electric utility
company that are synchronized to the
power distribution system and that are
capable of immediately accepting
-------
additional load. The electric generating
capability of equfpment under multiple
ownership is prorated based on
ownership unless the proportional
entitlement to electric output is
otherwise established by contractual
arrangement.
"Available purchase power" means
the lesser of the following:
(a) The sum of available system
capacity in all neighboring companies.
(b) The sum of the rated capacities of
the power interconnection devices
between the principal company and all
neighboring companies, minus the sum
of the electric power load on these
interconnections.
(c) The rated capacity, of the power
transmission lines between the power
interconnection devices and the electric
generating units (the unit in the principal
company that has the malfunctioning
flue gas desulfurization system and the
unit(s) in the neighboring company
supplying replacement electrical power)
less the electric power load on these
transmission lines.
"Spare flue gas desulfurization system
module" means a separate system of
•ulfur -dioxide emission control
equipment capable of treating an /
amount of flue gas equal to the total
amount of flue gas generated by an
affected facility when operated at
maximum capacity divided by the total
number of nonspare flue gas
desulfurization modules in the system.
"Emergency condition" means that
period of time when:
(a] The electric generation output of
an affected facility with a
malfunctioning flue gas desulfurization
system cannot be reduced or electrical
output must be increased because:
(1) All available system capacity in
the principal company interconnected
with the affected facility is being
operated, and
(2) All available purchase power
interconnected with the affected facility
is being obtained, or
(b) The electric generation demand is
being shifted as quickly as possible from
an affected facility with a
malfunctioning flue gas desulfurization
system to one or more electrical
generating units held in reserve by the
principal company or by a neighboring
company, or
(cj An affected facility with a
malfunctioning flue gas desulfurization •
system becomes the only available unit
to maintain a part or all of the principal
company's system emergency reserves
and the unit is operated in spinning
reserve at the lowest practical electric
generation load consistent with not
causing significant physical damage to
the unit. If the unit is operated at a
higher load to meet load demand, an
emergency condition would not exist
unless the conditions under (a) of this
definition apply.
"Electric utility combined cycle gas
turbine" means any combined cycle gas
turbine used for electric generation that
is constructed for the purpose of
supplying more than one-third of its
potential electric output capacity and
more than 25 MW electrical output to
any utility power distribution system for
sale. Any steam distribution system that
is constructed for the purpose of
providing steam to a steam electric
generator that would produce electrical
power for sale is also considered in
determining the electrical energy output
capacity of the affected facility.
"Potential electrical output capacity"
is defined as 33 percent of the maximum
design heat input capacity of the steam
generating unit {e.g., a steam generating
unit with a 100-MW (340 million Btu/hr)
fossil-fuel heat input capacity would
have a 33-MW potential electrical
output capacity). For electric utility
combined cycle gas turbines the
potential electrical output capacity is
determined on the basis of the fossil-fuel
firing capacity of the steam generator
exclusive of the heat input and electrical
power contribution by the gas turbine.
"Anthracite" means coal that is
classified as anthracite according to the
American Society of Testing and
Materials' (ASTM) Standard
Specification for Classification of Coals
by Rank D38&-66.
"Solid-derived fuel" means any solid,
liquid, or gaseous fuel derived from solid
fuel for the purpose of creating useful -
heat and includes, but is not limited to,
solvent refined coal, liquified coal, and
gasified coal.
"24-hour period" means the period of
time between 12:01 a.m. and 12:00
midnight.
"Resource recovery unit" means a
facility that combusts more than 75
percent non-fossil fuel on a quarterly
(calendar) heat input basis.
"Noncontinental area" means the
State of Hawaii, the Virgin Islands,
Guam, American Samoa, the
Commonwealth of Puerto Rico, or the
Northern Mariana Islands.
"Boiler operating day" means a 24-
hour period during which fossil fuel is
combusted in a steam generating unit for
the entire 24 hours.

8 60.42a Standard for paniculate matter.
(a) On and after the date on which the
performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility any gases which
contain paniculate matter in excess of:
(1) 13 ng/J (0.03 Ib/million Btu) heat
input derived from the combustion of
solid, liquid, or gaseous fuel;
(2) 1 percent of the potential
combustion concentration (99 percent
reduction) when combusting solid fuel;
and
(3) 30 percent of potential combustion
concentration (70 percent reduction)
when combusting liquid fuej.
(b) On and after the date the
particulate matter performance test
required to be conducted under § 60.8 is
completed, no owner or operator subject
to the provisions of this subpart shall
cause to be discharged into the
atmosphere from any affected facility
any gases which exhibit greater than 20
percent opacity (6-minute average),
except for one 6-minute period per hour
of not more than 27 percent opacity.

860.43a Standard for sulfur dioxide.
(a) On and after the date on which the
initial performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility which combusts
solid fuel or solid-derived fuel, except as
provided under paragraphs (c), (d), (f) or
(h) of this section, any gases which
contain sulfur dioxide in excess of:
(1) 520 ng/J (1.20 Ib/million Btu) heat
input and 10 percent of the potential
combustion concentration (90 percent
reduction), or
(2) 30 percent of the potential
combustion concentration (70 percent
reduction), when emissions are less than
260 ng/J (0.60 Ib/million Btu) heat input.
(b) On and after the date on which the
initial performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility which combusfs
liquid or gaseous fuels (except for liquid
or gaseous fuels derived from solid fuels
and as provided under paragraphs (e) or
(h) of this section), any gases which
contain sulfur dioxide in excess of:
(1) 340 ng/J (0.80 Ib/million Btu) heat
input and 10 percent of the potential
combustion concentration (90 percent
reduction), or
(2) 100 percent of the potential
combustion concentration (zero percent
reduction) when emissions are less than
86 ng/J (0.20 Ib/million Btu) heat input.
(c) On and after the date on which the
initial performance test required to be
-------
conducted under § 60.8 is complete, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility which combusts
solid solvent refined coal (SRC-I) any
gases which contain sulfur dioxide in
excess of 520 ng/J (1.20 Ib/million Btu)
heat input and 15 percent of the
potential combustion concentration (85
percent reduction) except as provided
under paragraph (f) of this section;
compliance with the emission limitation
is determined on a 30-day rolling
average basis and compliance with the
percent reduction requirement is
determined on a 24-hour basis.
(d) Sulfur dioxide emissions are
limited to 520 ng/J (1.20 Ib/million Btu)
heat input from any affected facility
which:
(1) Combusts 100 percent anthracite,
(2) Is classified as a resource recovery
facility, or
(3) Is located in a noncontinental area
and combusts solid fuel or solid-derived
fuel.
(e) Sulfur dixoide emissions are
limited to 340 ng/J (0.80 Ib/million Btu)
heat input from any affected facility
which is located in a noncontinental
area and combusts liquid or gaseous
fuels (excluding solid-derived fuels).
(f) The emission reduction
requirements under this section do not
apply to any affected facility that is
operated under an SO« commercial
demonstration permit issued by the
Administrator in accordance with the
provisions of § 60.45a.
(g) Compliance with the emission
limitation and percent reduction
requirements under this section are both
determined on a 30-day rolling average
basis except as provided under
paragraph (c) of this section.
(h) When different fuels are
combusted simultaneously, the
applicable standard is determined by
proration using the following formula:
(1) If emissions of sulfur dioxide to the
atmosphere are greater than 260 ng/J
(0.60 Ib/million Btu) heat input
Ego, = [340 x + 520 y]/100 and
Pso, = 10 percent

(2) It emissions of sulfur dioxide to the
atmosphere are equal to or less than 260
ng/J (0.60 Ib/million Btu) heat input:
Ego, = [340 x + 520 y)/100 and
Pso, = (90 x + 70 y]/100
where:
Ego, is the prorated sulfur dioxide emission
limit (ng/J heat input),
Pso, is the percentage of potential sulfur
dioxide emission allowed (percent
reduction required = 100—Pgo,),
x IB the percentage of total heat Input derived
from the combustion of liquid or gaseous
fuels (excluding solid-derived fuels)
y is the percentage of total heat input derived
from the combustion of solid fuel
(including solid-derived fuels)

( 60.44a Standard for nitrogen oxides.
(a) On and after the date on which the
initial performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility, except as provided
under paragraph (b) of this section, any
gases which contain nitrogen oxides in
excess of the following emission limits,
based on a 30-day rolling average.
(1) NO, Emission Limits—
Fuel typo
Emission limn
ng/J (Ib/million Btu)
heat Input
Gaseous Fuels: -
Coal-derived fuels -
AD other fuels
Liquid Fuels:
CoaWertvedluets..
210
86
210
(0.50)
(0.20)
All other fuels...
Sold Fuels:
(0.50)
(0.50)
130 (0.30)
Coal-derived fuels
Any fuel containing more than
25%, by weight, coal refuse ..

Any fuel containing more than
25%, by weight, lignite U the
lignite is mined in North
Dakota. South Dakota, or
Montana, and is combusted
In a slag tap furnace .._ H
Lignite not subject to the 340
ng/J heat input emission limit
Subbituminous coal ..«..««..«.».
RjtiifnirmM ryMl
Anthracite coal
All other fuels .._
210 (0.50)

Exempt from NO.
standards and NO,
monitoring
requirements

340 (0.80)

260 (0.60)
210 (0.50)
260 (0.60)
260 (0.60)
260 (0.60)
(2) NO, reduction requirements—
Fuel type
Percent reduction
of potential
combustion
concentration
Gaseous fuels.
Liquid fuels
Solid fuels
25%
30%
65%
(b) The emission limitations under
paragraph (a) of this section do not
apply to any affected facility which is
combusting coal-derived liquid fuel and
is operating under a commercial
demonstration permit issued by the
Administrator in accordance with the
provisions of S 60.45a.
(c) When two or more fuels are
combusted simultaneously, the
applicable standard is determined by
proration using the following formula:
Em, =[66 w+130 x+210 y+260 z]/100
where:
END, Is the applicable standard for nitrogen
oxides when multiple fuels are
combusted simultaneously (ng/J heat
input);
w is the percentage of total heat input
derived from the combustion of fuels
subject to the 86 ng/J heat input
standard;
x Is the percentage of total heat input derived
from the combustion of fuels subject to
the 130 ng/J heat input standard;
y is the percentage of total heat input derived
from the combustion of fuels subject to
the 210 ng/J heat input standard; and
z is the percentage of total heat input derived
from the combustion of fuels subject to
the 260 ng/J heat input standard.

$ 60.4Sa Commercial demonstration
permit
(a) An owner or operator of an
affected facility proposing to
demonstrate an emerging technology
may apply to the Administrator for a
commercial demonstration permit. The
Administrator will issue a commercial
demonstration permit in accordance
with paragraph (e) of this section.
Commercial demonstration permits may
be issued only by the Administrator,
and this authority will not be delegated.
(b) An owner or operator of an
affected facility that combusts solid
solvent refined coal (SRC-I) and who is
issued a commercial demonstration
permit by the Administrator is hot
subject to the SO* emission reduction
requirements under § 60.43a(c) but must,
as a minimum, reduce SO» emissions to
20 percent of the potential combustion
concentration (80 percent reduction) for
each 24-hour period of steam generator
operation and to less than 520 ng/J (1.20
Ib/million Btu) heat input on a 30-day
rolling average basis.
(c) An owner or operator of a fluidized
bed combustion electric utility steam
generator (atmospheric or pressurized)
who is issued a commercial
demonstration permit by the
Administrator is not subject to the SO,
emission reduction requirements under
$ 60.43a(a) but must, as a minimum,
reduce SO» emissions to 15 percent of
the potential combustion concentration
(85 percent reduction) on a 30-day
rolling average basis and to less than
520 ng/J (1.20 Ib/million Btu) heat input
on a 30-day rolling average basis.
(d) The owner or operator of an
affected facility that combusts coal-
derived liquid fuel and who is issued a
commercial demonstration permit by the
Administrator is not subject to the
applicable NO, emission limitation and
percent reduction under § 60.44a(a) but
must, as a minimum, reduce emissions
to less than 300 ng/J (0.70 Ib/million Btu)
III-17C
-------
heat input on a 30-day rolling average
(e) Commercial deBionotration permits
mey not exceed the following equivalent
MW electrical generation capacity for
any one technology category, and the
jtotal equivalent MW electrical
generation capacity for all commercial
demonstration plants may not exceed
1S.CDO MW.
dcctrod
erpccily
Boa csJvcnl iclicd cod

-------
potential sulfur dioxide emissions in
place of a continuous sulfur dioxide
emission monitor at the inlet to the
sulfur dioxide control device as required
under paragraph (b)(l) of this section.
(c) The owner or operator of an
affected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring
nitrogen oxides emissions discharged to
the atmosphere.
(d) The owner or operator of an
affected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring the
oxygen or carbon dioxide content of the
flue gases at each location where sulfur
dioxide or nitrogen oxides emissions are
monitored.
(e) The continuous monitoring
systems under paragraphs (b), (c), and
(d) of this section are operated and data
recorded during all periods of operation
of the affected facility including periods
of startup, shutdown, malfunction or
emergency conditions, except for
continuous monitoring system
breakdowns, repairs, calibration checks,
and zero and span adjustments.
(f) When 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 other monitoring
systems as approved by the
Administrator or the reference methods
es described in paragraph (h) of this
section to provide emission data for a
minimum of 18 hours in at least 22 out of
30 successive boiler operating days.
(g) The 1-hour averages required
under paragraph § 60.13(h) are
expressed in ng/J (Ibs/million Btu) heat
input and used to calculate the average
emission rates under § 6Q.48a. The 1-
hour averages are calculated using the
data points required under § 60.13(b). At
least two data points must be used to
calculate the 1-hour averages.
(h) Reference methods used to
supplement continuous monitoring
system data to meet the minimum data
requirements in paragraph § 60.47a(f)
will be used as specified below or
otherwise approved by the
Administrator.
(1) Reference Methods 3,8, and 7, as
applicable, are used. The sampling
location(s) are the same as those used
for the continuous monitoring system.
(2] For Method 6, the minimum
sampling time is 20 minutes and the
minimum sampling volume is 0.02 dscm
(0.71 docf) for each sample. Samples are
intervals. Each sample represents a 1-
hour average.
(3) For Method 7, samples are taken at
approximately 30-minute intervals. The
arithmetic average of these two
consective samples represent a 1-hour
average.
(4) For Method 3, the oxygen or
carbon dioxide sample is to be taken for
each hour when continuous SO* and
NOn data are taken or when Methods 6
and 7 are required. Each sample shall be
taken for a minimum of 30 minutes in
each hour using the integrated bag
method specified in Method 3. Each
sample represents a 1-hour average.
(5) For each 1-hour average, the
emissions expressed in ng/J (Ib/million
Btu) heat input are determined and used
as needed to achieve the minimum data
requirements of paragraph (f) of this
section.
(i) The following procedures are used
to conduct monitoring system
performance evaluations under
§ 60.13{c) and calibration checks under
8 80.13{d).
(1) Reference method 6 or 7, as
applicable, is used for conducting
performance evaluations of sulfur
dioxide and nitrogen oxides continuous
monitoring systems.
(2) Sulfur dioxide or nitrogen oxides,
as applicable, is used for preparing
calibration gas mixtures under
performance specification 2 of appendix
B tp this part.
(3) For affected facilities burning only
fossil fuel, the span value for a
continuous monitoring system for
measuring opacity is between 60 and 80
percent and for a continuous monitoring
system measuring nitrogen oxides is
determined as follows:
Span valuator
nitrogen oxntes (ppm)
Utped
Soled
Combination..
600
SCO
1,000
600 fr+y)+1,000s
where:
x is the fraction of total heat input derived
from gaseous fossil fuel,
y is the fraction of total heat input derived
from liquid fossil fuel, and
s is the fraction of total heat input derived
from solid fossil fuel.

(4) All span values computed under
paragraph (b)(3) of this section for
burning combinations of fossil fuels are
rounded to the nearest 500 ppm.
(5) For affected facilities burning fossil
fuel, alone or in combination with non-
fossil fuel, the span value of the sulfur
dioxide continuous monitoring system at
the inlet to the sulfur dioxide control
device is 125 percent of the maximum
estimated hourly potential emissions of
the fuel fired, and the outlet of the sulfur
dioxide control device is 50 percent of
maximum estimated hourly potential
emissions of the fuel fired.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414).)
{a) The following procedures and
reference methods are used to determine
compliance with the standards for
particulate matter under B 80.42a.
(1) Method 3 is used for gas analysis
when applying method 5 or method 17.
(2) Method 5 is used for determining
particulate matter emissions and
associated moisture content. Method 17
may be used for stack gas temperatures
less than 160 C (320 F).
(3) For Methods 5 or 17. Method 1 is
used to select the sampling site and the
number of traverse sampling points. The
sampling time for each run is at least 120
minutes and the minimum sampling
volume is 1.7 dscm (60 dscf) except that
smaller sampling times or volumes,
when necessitated by process variables
or other factors, may be approved by the
Administrator.
(4) For Method 5. the probe and filter
holder heating system in the sampling
train is set to provide a gas temperature
no greater than 160°C (32°F).
(5] For determination of particulate
emissions, the oxygen or carbon-dioxide
sample is obtained simultaneously with
each run of Methods 5 or 17 by
traversing the duct at the same sampling
location. Method 1 is used for selection
of the number of traverse points except
that no more than 12 sample points are
required.
(6) For each run using Methods 5 or 17,
the emission rate expressed in ng/J heat
input is determined using the oxygen or
carbon-dioxide measurements and
particulate matter measurements
obtained under this section, the dry
basis Fc-factor and the dry basis
emission rate calculation procedure
contained in Method 19 (Appendix A).
(7) Prior to the Administrator's
issuance of a particulate matter
reference method that does not
experience sulfuric acid mist
interference problems, particulate
matter emissions may be sampled prior
to a wet flue gas desulfurization system.
(b) The following procedures and
methods are used to determine
compliance with the sulfur dioxide
standards under § 80.<33a.
(1) Determine the percent of potential
combustion concentration (percent PCC)
omitted to the atmosphere as follows:
-------
(1) Fuel Pretreatment (% Rf):
Determine the percent reduction
achieved by any fuel pretreatment using
the procedures in Method 19 (Appendix
A). Calculate the average percent
reduction for fuel pretreatment on a
quarterly basis using fuel analysis data.
The determination of percent Rf to
calculate the percent of potential
combustion concentration emitted to the
atmosphere is optional. For purposes of
determining compliance with any
[percent reduction requirements under
% 60.438, any reduction in potential SOa
emissiona resulting from the following
processes may be credited:
(A) Fuel pretreatment (physical coal
cleaning, hydrodesulfurization of fuel
oil, etc.),
(B) Coal pulverizers, and
(C) Bottom and flyash interactions.
(ii) Sulfur Dioxide Control System (%
Kg): Determine the percent sulfur
dioxide reduction achieved by any
oulfur dioxide control system using
' emission rates measured before and
after the control system, following the
procedures in Method 19 (Appendix A);
of, a combination of an "as fired" fuel
monitor and emission rates measured
after the control system, following the
procedures in Method 19 (Appendix A).
When the "as fired" fuel monitor is
used, the percent reduction is calculated
using the average emission rate from the
sulfur dioxide control device and the
average SOS input rate from the "as
Sred" fuel analysis for 30 successive
boiler operating days.
(in) Overall percent reduction (% Raj:
Determine the overall percent reduction
using the results obtained in paragraphs
(b)(l) (i) and (ii) of this section following
the procedures in Method 19 (Appendix
A). Results are calculated for each 30-
day period using the quarterly average
percent sulfur reduction determined for
fuel pretreatment from the previous
quarter and the sulfur dioxide reduction
' achieved by a sulfur dioxide control
system for each 30-day period in the
current quarter.
(iv) Percent emitted (% PCC):
Calculate the percent of potential '
combustion concentration emitted to the
atmosphere using the following
equation: Percent PCC=100-Percent RQ
(2) Determine the sulfur dioxide
emission rates following the procedures
in Method 19 (Appendix A).
(c) The procedures and methods
outlined in Method 19 (Appendix A) are
used in conjunction with the 30-day
nitrogen-oxides emission data collected
under § 60.47a to determine compliance
with the applicable nitrogen oxides
standard under g BOM.
(d) Electric utility combined cycle gas
turbines are performance tested for
jparticulate matter, sulfur dioxide, and
nitrogen oxides using the procedures of
Method 19 (Appendix A). The sulfur
dioxide and nitrogen oxides emission
rates from the gas turbine used in
Method 19 (Appendix A) calculations
are determined when the gas turbine is
performance tested under subpart GG.
The potential uncontrolled particulate
matter emission rate from a gas turbine
is defined as 17 ng/J (0.04 Ib/million Btu]
heat input.
(a) For sulfur dioxide, nitrogen oxides,
and particulate matter emissions, the
performance test data from the initial
performance test and from the
performance evaluation of the
continuous monitors (including the
dransmissometer) are submitted to the
Administrator
(b) For sulfur dioxide and nitrogen
oxides the following information is
reported to the Administrator for each
24-hour period.
(1) Calendar date.
(2) The average sulfur dioxide and
nitrogen oxide emission rates (ng/J or
Ib/million Btu) for each 30 successive
boiler operating days, ending with the
last 30-day period in the quarter;
reasons for non-compliance with the
emission standards; and, description of
corrective actions taken.
(3) Percent reduction of the potential
combustion concentration of sulfur
dioxide for each 30 successive boiler
operating days, ending with the last 30-
day period in the quarter; reasons for
non-compliance with the standard; and,
description of corrective actions taken.
(4) Identification of the boiler
operating days for which pollutant or
dilutent data have not been obtained by
an approved method for at least 18 '
hours of operation of the facility;
justification for not obtaining sufficient
data; and description of corrective
actions taken.
(5) Identification of the times when
emissions data have been excluded from
the calculation of average emission
rates because of startup, shutdown,
malfunction (NOZ only), emergency
conditions (SOS only), or other reasons,
and justification for excluding data for
reasons other than startup, shutdown,
malfunction, or emergency conditions.
(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
(8) Identification of the times when
the pollutant concentration exceeded
full span of the continuous monitoring
oystem.
(9) Description of any modifications to
the continuous monitoring system which
could affect the ability of the continuous
monitoring system to comply with
Performance Specifications 2 or 3.
(c) If the minimum quantity of
emission data as required by § 60.47a is
not obtained for any 30 successive
boiler operating days, the following
information obtained under the
requirements of § 60.46a(h) is reported
to the Administrator for that 30-day
period:
(1) The number of hourly averages
available for outlet emission rates (nj
and inlet emission rates (n,) as
applicable.
(2) The standard deviation of hourly
-averages for outlet emission rates (s0)
and inlet emission rates (s,) as
applicable.
(3) The lower confidence limit for the
mean outlet emission rate (E0°) and the
upper confidence limit for the mean inlet
emission rate (£**) as applicable.
(4) The applicable potential
combustion concentration.
(5) The ratio of the upper confidence
limit for the mean outlet emission rate
(EO") and the allowable emission rate
(Eotd) as applicable.
(d) If any standards under § 60.43a are
exceeded during emergency conditions
because of control system malfunction,
the owner or operator of the affected
facility shall submit a signed statement:
(1) Indicating if'emergency conditions
existed and requirements under
i 60.46a(d) were met during each period,
and
(2) Listing the following information:
(i) Time periods the emergency
condition existed;
(ii) Electrical output and demand on
the owner or operator's electric utility
system and the affected facility:
' (iii) Amount of power purchased from
interconnected neighboring utility
companies during the emergency period;
(iv) Percent reduction in emissions
achieved;
(v) Atmospheric emission rate fng/J)
of the pollutant discharged; and
(vi) Actions taken to correct control
system malfunction.
(e) If fuel pretreatment credit toward
the sulfur dioxide emission standard
under § 60.43a is claimed, the owner or
operator of the affected facility shall
submit a signed statement:
(1) Indicating what percentage
cleaning credit was taken for the
calendar quarter, and whether the credit
was determined in accordance with the
-------
provisions of § 60.48a and Method 19
(Appendix A); and
(2) Listing the quantity, heat content.
and date each pretreated fuel shipment
was received during the previous
quarter; the name and location of thie
fuel pretreatment facility; and the total
quantity and total heat content of all
fuels received at the affected facility
during the previous quarter.
(f) For any periods for which opacity,
sulfur dioxide or nitrogen oxides
emissions data are not available, the
owner or operator of the affected facility
shall submit a signed statement
indicating if any changes were made in
operation of the emission control system
during the period of data unavailability.
Operations of the control system and ~
affected facility during periods of data
unavailability are to be compared with
operation of the control system and
affected facility before and following the
period of data unavailability.
(g) The owner or operator of the
affected facility shall submit a signed
statement indicating whether:
(1) The required continuous
monitoring system calibration, span, and
drift checks or other periodic audits
have or have not been performed as
specified.
(2) The data used to $how compliance
was or was not obtained in accordance
with approved methods and procedures
of this part and is representative of
plant performance.
(3) The minimum data requirements
have or have not been met; or, the
minimum data requirements have not
been met for errors that were
unavoidable. v
(4) Compliance with the standards has
or has not been achieved during the
reporting period.
(h) For the purposes of the reports
required under § 60.7, periods of excess
emissions are defined as all 6-minute
periods during which the average
opacity exceeds the applicable opacity
standards under § 60.42a(b). Opacity
levels in excess of the applicable
opacity standard and the date of such
excesses are to be submitted to the
Administrator each calendar quarter.
(i) The owner or operator of an
affected facility shall submit the written
reports required under this section and
subpart A to the Administrator for every
calendar quarter. All quarterly reports
shall be postmarked by the 30th day
following the end of each calendar
quarter.
(Sec. 114. Clean Air Act as amended (42
U.S.C. 7414).)
36 FR 24876, 12/23/71 (1)
as amended
44 FR 33580, 6/11/79 (98)
-------
-------
Subpart E—Standards of Performance
for Incinerators

§ 60.50 Applicability and designation of
affected futility. 8, 64
(a) The provisions of tills subpart are
applicable to each incinerator of more
than 45 metric tons per day charging
rate (50 tons/day), which is the affected
faciUty.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after August 17,
1971, Is subject to the requirements of
this oubpart.

§ 60.51 Definitions.
As used In this subpart, all terms not
denned herein shall have the meaning
given them in the Act and In Subpart A
of this part.
(a) "Incinerator" means any furnace
used in the process of burning solid waste
for the purpose of reducing the volume
of the waste by removing combustible
matter.8
(b) "Solid waste" means refuse, more
than 50 percent of which is municipal
type waste consisting of a mixture of
paper, wood, yard wastes, food wastes,
plastics, leather, rubber, and other com-
bustibles, and noncombustlble materials
such as glass and rock.
per-
centage using the following equation:
and outlet sampling sites using equation
3-1 in Appendix A to this part.
(lii) Calculate the adjusted CO, per-
centage using the following equation:
COi)uj = (
(Qtt/Qt.)
«——•««•
where:
( % CO,) tti is the adjusted outlet CO> per-
centage,
(%CO«)di Is the percentage of COi meas-
ured before the scrubber, dry
basis,
( % EA) i Is the percentage of excess air
at the Inlet, and
( % EA) o is the percentage of excess air
at the outlet.
(d) Particulate matter emissions, ex-
pressed In g/dscm, shall be corrected to
12 percent CO, by using the following
formula:
120

%00i
where:
Cu Is the concentration of partlculato
matter corrected to 12 percent
CO,.
o is the concentration of partloulato
matter as measured by Method B.
and
% COi la the percentage of COi as meas-
ured by Method 3. or when ap-
plicable, the adjusted outlet CO,
percentage as determined by
paragraph (c) of this section.
where:
( % CO>) ««i is the adjusted COi percentage
which removes the effect of
COt absorption and dilution
air.
( % COa) an integrated gas sample
according to Method 3, traversing the
three sample points and sampling for
equal Increments of time at each point.
Conduct the runs at both the Inlet and
outlet sampling sites.
(11) After completing the analysis of
the gas sample, calculate the percentage
of excess air ( % EA) for both the Inlet
Act
(42
36 FR 24876, 12/23/71 (1)

as amended

39 FR 20790, 6/14/74 (8)
42 FR 37936, 7/25/77 (64)
42 FR 41424, 8/17/77 (68)
43 FR 8800, 3/3/78 (83)
111-18
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Subpart
Standards of Performance for
Petroleum Refineries5
$60.100 Applicability and designation of
affected facility.64.86
(a) The provisions of this subpart
are applicable to the following affect-
ed facilities in petroleum refineries:
fluid catalytic cracking unit catalyst
regenerators, fuel gas combustion de-
vices, and all Glaus sulfur recovery
plants except Claus plants of 20 long
tons per day (LTD) or less associated
with a small petroleum refinery. The
Claus sulfur recovery plant need not
be physically located within the
boundaries of a petroleum refinery to
be an affected facility, provided it pro-
cesses gases produced within a petro-
leum refinery.
(b) Any fluid catalytic cracking unit
catalyst regenerator of fuel gas com-
bustion device under paragraph (a) of
this section which commences con-
struction or modification after June
11, 1973, or any Claus sulfur recovery
plant under paragraph (a) of this sec-
tion which commences construction or
modification after October 4, 1976, is
subject to the requirements of this
part.
§ 60.101 Definitions.
As used In this subpart, all terms not
denned herein shall have the meaning
given them in the Act and in Subpart A.
(a) "Petroleum refinery" means any
facility engaged in producing gasoline,
kerosene, distillate fuel oils, residual fuel
oils, lubricants, or other products
through distillation of petroleum or
through redistillation, cracking or re-
forming of unfinished petroleum
derivatives.
(b) "Petroleum" means the crude oil
removed from the earth and the oils de-
rived from tar sands, shale, and coal.
(c) "Process gas" means any gas gen-
erated by a petroleum refinery process
unit, except fuel gas and process upset
gas as defined in this section.
(d) "Fuel gas" means natural gas or
any gas generated by a petroleum re-
finery process unit which is combusted
separately or in any combination. Fuel
gas does not include gases generated
by catalytic cracking unit catalyst re-
generators and fluid coking unit coke
burners.96
(e) "Process upset gas" means any gas
generated by a petroleum refinery process
unit as a result of start-up, shut-down,
upset or malfunction.
(f) "Refinery process unit" means any
segment of the petroleum refinery in
which a specific processing operation la
conducted.
(g) "Fuel gas combustion device"
means any equipment, such as process
heaters, boilers, and flares used to
combust fuel gas, except facilities in
which gases are combusted to produce
sulfur or sulfuric add.96
(h) "Coke burn-off" means the coke
removed from the surface of the fluid
catalytic cracking unit catalyst by com-
bustion in the catalyst regenerator. The
rate of coke burn-off is calculated by the
formula specified in § 60.106.
(i) "Claus sulfur recovery plant"
means a process unit which recovers
sulfur from hydrogen sulfide by a
vapor-phase catalytic reaction of
sulfur dioxide and hydrogen sulfide.86
(j) "Oxidation control system"
means an emission control system
which reduces emissions from sulfur
recovery plants by converting these
emissions to sulfur dioxide.86
(k) "Reduction control system"
means an emission control system
which reduces emissions from sulfur
recovery plants by converting these
emissions to hydrogen sulfide.86
(1) "Reduced sulfur compounds"
mean hydrogen sulfide (HiS), carbonyl
sulfide (COS) and carbon disulfide
(CS,).86
(m) "Small petroleum refinery"
means a petroleum refinery which has
a crude oil processing capacity of
50,000 barrels per stream day or less,
and which is owned or controlled by a
refinery with a total combined crude
oil processing capacity of 137,500 bar-
rels per stream day or less.84

§ 60.102 Standard for particulate matter.
(a) On and after the date on which
the performance test required to be
conducted by §60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall discharge or
cause the discharge into the atmos-
phere from any fluid catalytic crack-
ing unit catalyst regenerator:86
(1) Particulate matter in excess of
1.0 kg/1000 kg (1.0 lb/1000 Ib) of coke
burn-off in the catalyst regenerator.
(2) Oases exhibiting greater than 30
percent opacity, except for one six-min-
ute average opacity reading in any one
hour period. I8'6t-66
(b) Where the gases discharged by
the fluid catalytic cracking unit cata-
lyst regenerator pass through an in-
cinerator or waste heat boiler in which
auxiliary or supplemental liquid or
sold fossil fuel is burned, particulate
matter in excess of that permitted by
paragraph (aXl) of this section may
be emitted to the atmosphere, except
that the incremental rate of particu-
late matter emissions shall not exceed
43.0 g/MJ (0.10 Ib/million Btu) of
heat input attributable to such liquid
or solid fossil fuel.86

§ 60.103 Standard for carbon monoxide.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall discharge or cause the
discharge into the atmosphere from the
fluid catalytic cracking unit catalyst
regenerator any gases which contain car-
boa monoxide in excess of 0.050 percent
by volume.
§ 60.104 Standard for sulfur dioxide.86
(a) On and after the date on which
the performance test required to be
conducted by §60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall:
(1) Burn in any fuel gas combustion
device any fuel gas which contains hy-
drogen sulfide in excess of 230 mg/
dscm (0.10 gr/dscf), except that the
gases resulting from the combustion of
fuel gas may. be treated to control
sulfur dioxide emissions provided the
owner or operator demonstrates to the
satisfaction of the Administrator that
this is as effective in preventing sulfur
dioxide emissions to the atmosphere
as restricting the Hj concentration in
the fuel gas to 230 mg/dscm or less.
The combustion in a flare of process
upset gas, or fuel gas which is released
to the flare as a result of relief valve
leakage, is exempt from this para-
graph.
(2) Discharge or cause the discharge
of any gases into the atmosphere from
any Claus sulfur recovery plant con-
taining in excess of:
(i) 0.025 percent by volume of sulfur
dioxide at zero percent oxygen on a
dry basis if emissions are controlled by
an oxidation control system, or a re-
duction control system followed by in-
cineration, or
(ii) 0.030 percent by volume of re-
duced sulfur compounds and 0.0010
percent by volume of hydrogen sulfide
calculated as sulfur dioxide at zero
percent oxygen on a dry basis if emis-
sions are controlled by a reduction
control system not followed by incin-
eration.
(b) [Reserved]
§ 60.105 Emission monitoring.'8
(a) Continuous monitoring systems
shall be installed, calibrated, maintained,
and operated by the owner or operator as
follows:
(1) A continuous monitoring system
for the measurement of the opacity of
emissions discharged into the atmosphere
from the fluid catalytic cracking unit cat-
alyst regenerator. The continuous moni-
toring system shall be spanned at 60, 70,
or 80 percent opacity.
(2) An instrument for continuously
monitoring and recording the concen-
tration of carbon monoxide in gases
discharged into the atmosphere from
fluid catalytic cracking unit catalyst
regenerators. The span of this con-
tinuous monitoring system shall be
1.000 ppm.86
(3) A continuous monitoring system
for the measurement of sulfur dioxide in
the gases discharged into the atmosphere
from the combustion of fuel gases (ex-
cept where a continuous monitoring sys-
tem for the measurement of hydrogen
sulfide is installed under paragraph (a)
(4) of this section). The pollutant gas
used to prepare calibration gas mixtures
under paragraph 2.1, Performance Speci-
111-23
-------
flcation 2 and for calibration checks un-
der §60.13(d), shall be sulfur dioxide
(SOz). The span shall be set at 100 ppm.
For conducting monitoring system per-
formance evaluations under § 60.13 (c),
Reference Method 6 shall be used.
(4) An instrument for continuously
monitoring and recording concentra-
tions of hydrogen sulfide in fuel gases
burned in any fuel gas combustion
device, if compliance with
§60.104(a)(l) is achieved by removing
HjS from the fuel gas before it is
burned; fuel gas combustion devices
having a common source of fuel gas
may be monitored at one location, if
monitoring at this location accurately
represents the concentration of HiS in
the fuel gas burned. The span of this
continuous monitoring system shall be
300 ppm.86
(5) An instrument for continuously
monitoring and recording concentra-
tions of SO2 in the gases discharged
into the atmosphere from any Claus
sulfur recovery plant if compliance
with §60.104(a)(2) is achieved through
the use of an oxidation control system
or a reduction control system followed
by incineration. The span of this con-
tinuous monitoring system shall be
sent at 500 ppm.86
6) An instrument(s) for continuous-
ly monitoring and recording the con-
centration of HaS and reduced sulfur
compounds in the gases discharged
into the atmosphere from any Claus
sulfur recovery plant if compliance
with §60.104(a)(2) is achieved through
the use of a reduction control system
not followed by incineration. The
span(s) of this continuous monitoring
system(s) shall be set at 20 ppm for
monitoring and recording the concen-
tration of H,S and 600 ppm for moni-
toring and recording the concentration
of reduced sulfur compounds.86
(b) [Reserved]
(c) The average coke burn-off rate
(thousands of kilogram/hr) and hours of
operation for any fluid catalytic crack-
Ing unit catalyst regenerator subject to
§ 60.102 or § 60.103 shall be recorded
daily.
(d) For any fluid catalytic cracking
unit catalyst regenerator which is subject
to § 60.102 and which utilizes an inciner-
ator-waste heat boiler to combust the
exhaust gases from the catalyst regen-
erator, the owner or operator shall re-
cord daily the rate of combustion of
liquid or solid fossil fuels (liters/hr or
kilograms/hr) and the hours of opera-
tion during which liquid or solid fossil
fuels are combusted in the incinerator-
waste heat boiler.
(e) For the purpose of reports under
§ 60.7(c), periods of excess emissions that
shall be reported are denned as follows:
(1) Opacity.
All one- hour periods which
contain two or more six-minute periods
during which the average opacity as
measured by the continuous monitoring
system exceeds 30 percent.6 •**
(2) Carbon monoxide. All hourly pe-
riods during which the average carbon
monoxide concentration in the gases
discharged into the atmosphere from
any fluid catalytic cracking unit cata-
lyst regenerator subject to § 60.103 ex-
ceeds 0.050 percent by volume.86
(3) Sulfur dioxide, (i) Any three-
hour period during which the average
concentration of H,S in any fuel gas
combusted in any fuel gas combustion
device subject to §60.104(a)(l) exceeds
230 mg/dscm (0.10 gr/dscf). If compli-
ance is achieved by removing H,S from
the fuel gas before it is burned; or any
three-hour period during which the
average concentration of SO» in the
gases discharged into the atmosphere
from any fuel gas combustion device
subject to §60.104(a)(l) exceeds the
level specified in §60.104(a)(l), if com-
pliance is achieved by removing SO,
from the combusted fuel gases.86
(ii) Any twelve-hour period during
which the average concentration of
SO, In the gases discharged into the
atmosphere from any Claus sulfur re-
covery plant subject to §60.104(a)(2)
exceeds 250 ppm at zero percent
oxygen on a dry basis if compliance
with §60.104(b) is achieved through
the use of an oxidation control system
or a reduction control system followed
by incineration; or any twelve-hour
period during which the average con-
centration of H2S, or reduced sulfur
compounds in the gases discharged
into the atmosphere of any Claus
sulfur plant subject to §60.104(a)(2)
(b) exceeds 10 ppm or 300 ppm, respec-
tively, at zero percent oxygen and on a
dry basis if compliance is achieved
through the use of a reduction control
system not followed by incineration.86
(4) Any six-hour period during which
the average emissions (arithmetic aver.
age of six contiguous one-hour periods)
of sulfur dioxide as measured by a con-
tinuous monitoring system exceed the
standard under § 60.104.

(Sec. 114. Clewj Air Act is amended (42
U.S.C. 7414)>.°8. 83
§ 60.106 Test methods and procedure*.
(a) For the purpose of determining
compliance with § 60.102(a) (1). the fol-
lowing reference methods and calcula-
tion procedures shall be used:
(1) For gases released to the atmos-
phere from the fluid catalytic cracking
unit catalyst regenerator:
(i) Method 5 for the concentration of
participate matter and moisture con-
tent,
(11) Method 1 for sample and velocity
traverses, and
(lii) Method 2 for velocity and volu-
metric flow rate.
(2) For Method 5, the sampling time
for each run shall be at least 60 minutes
and the sampling rate shall be at least
0.015 dscm/mln (0.53 dscf/min), except
that shorter sampling times may be ap-
proved by the Administrator when proc-
ess variables or other factors preclude
sampling for at least 60 minutes.
(3) For exhaust gases from the fluid
catalytic cracking unit catalyst regenera-
tor prior to the emission control system:
the Integrated sample techniques of
Method 3 and Method 4 for gas analysis
and moisture content, respectively;
Method 1 for velocity traverses; and
Method 2 for velocity and volumetric flow
rate.
(4) Coke burn-off rate shall be deter-
mined by the following formula:
R.=0.2982 QBE (%COi+%CO)+2.088 Q.RA-0.0994 QBE (~^+%COt+%Ot^ (Metric Units)

R.=0.0188 QBB (%COH-%CO)+0.1303 QRA-0.0062 QBE (^y^+%COt+%Oi) (English Units)

where:
Kc=coke burn-ofl rate, kg/hr (English units: Ib/hr).
0.2982=metrtc units material balance factor divided by 100, kg-min/hr-m'.
0.0188=English units material balance factor divided by 100, lb-mln/hr-ff.
QRE=fluid catalytic cracking unit catalyst regenerator exhaust gas flow rate before entering the emission
control system, as determined by method 2, dscm/niin (English units: dscf/mln).
%COi=percent carbon dioxide by volume, dry basis, as determined by Method 3.
% CO=percent carbon monoxide by volume, dry basis, as determined by Method 3.
% Oi=percent oxygen by volume, dry basis, as determined by Method 3.
2.088=metric units material balance factor divided by 100, kg-mln/hr-m*.
0.1303=Engllsh units material balance factor divided by 100, Ib-min/hr-ft'.
QRA=alr rate to fluid catalytic cracking unit catalyst regenerator, as determined from fluid'catalytlc cracking
unit control room Instrumentation, dscm/mln (English units: dscf/mln).
0.0994=me trie units material balance factor divided by 100, kg-mln/hr-m'.
0.0062=English units material balance factor divided by 100, lb-mln/hr-ff.

(5) Participate emissions shall be determined by the following equation:

RE=(60X10-«)QBvC. (Metric Units)

RB=(S.67X10-«)QHvC. (English Units)
where:
RE=partlculate emission rate, kg/hr (English units: Ib/hr).
80X10~*=metrle units conversion factor, mln-kg/hr-mg.
8.67X10-'=EngUsh units conversion factor, min-lb/hr-gr.
QRv=volumetrlc flow rate of gases discharged Into the atmosphere from the fluid catalytic cracking unit
catalyst regenerator folloving the emission control system, as determined by Method 2, dscm/mln
(English unite: dscf/min).
C.=partlculate emission concentration discharged into the atmosphere, as determined by Method 8,
mg/dscm (English units: gr/dscf).
111-24
-------
(6) For each run, <»miartnn« expressed in kg/1000 kg (English units: lb/1000 Ib)
of coke burn-off in the catalyst regenerator shall be determined by the following
equation:

E.=1000^l! (Metric or English Units)
Ac
whore:
R.=partlculate emission rate, kg/1000 kg (English units: lb/1000 Ib) of coke burn-off In the fluid catalytic crack-
Ing unit catalyst regenerator.
1000=converslon factor, kg to 1000 kg (English units: Ib to 1000 Ib).
Ri-parttculate emission rate, kg/or (English units: Ib/hr).
R.—ooke bum-oil rate, kg/hr (English units: Ib/hr).

(7) in those instances In which auxiliary liquid or solid fossil fuels are burned
In an incinerator-waste heat boiler, the rate of participate matter emissions per-
mitted under ! 60.102 (b) must be determined. Auxiliary fuel heat input, expressed
In mflHo"s of cal/hr (English units: Millions of Btu/hr) shall be calculated for
each run by fuel flow rate measurement and analysis of the liquid or solid auxiliary
fossil fuels. For each run, the rate of participate emissions permitted under
S 60.102 (b) shall be calculated from the following equation :

(Metric Units)
fto
vbere:
R.=

1.0=

0.18=
0.10=
H=
R.=
allowable participate emission rate, kg/1000 kg (English units: lb/1000 Ib) of coke burn-off in the
fluid catalytic cracking unit catalyst regenerator.
emission standard, 1.0 kg/1000 kg (English units: 1.0 lb/1000 Ib) of coke burn-off in the fluid catalytic
cracking unit catalyst regenerator.
metric units maximum allowable incremental rate of paniculate emissions, g/milllon cat.
English units maximum allowable incremental rate of paniculate emissions, Ib/mlllion Btu.
heat input from solid or liquid fossil fuel, million cal/hr (English units: million Btu/hr).
coke burn-off rate, kg/hr (English units: Ib/hr).
(b) For the purpose of determining
compliance with § 60.103, the Integrated
sample technique of Method 10 shall be
used. The sample shall be extracted at a
rate proportional to the gas velocity at a
sampling point near the centrold of the
duct. The sampling time shall not be less
than 60 minutes
(c) For the purpose of determining
compliance with §60.104(a)(l).
Method 11 shall be used to determine
the concentration of. H2S and Method
6 shall be used to determine the con-
centration of SO,.86
(1) If Method 11 is used, the gases
sampled shall be introduced into the
sampling train at approximately atmo-
spheric pressure. Where refinery fuel
gas lines are operating at pressures
substantially above atmosphere, this
may be accomplished with a flow con-
trol valve. If the line pressure is high
enough to operate the sampling train
without a vacuum pump, the pump
may be eliminated from the sampling
train. The sample shall be drawn from
a point near the centroid of the fuel
gas line. The minimum sampling time
shall be 10 minutes and the minimum
sampling volume 0.01 dscm (0.35 dscf)
for each sample. The arithmetic aver-
age of two samples of equal sampling
time shall constitute one run. Samples
shall be taken at approximately 1-
hour Intervals. For most fuel gases,
sample times exceeding 20 minutes
may result in depletion of the collect-
ing solution, although fuel gases con-
taining low concentrations of hydro-
gen sulfide may necessitate sampling
for longer periods of time.86
(2) If Method 6 is used. Method. 1
shall be used for velocity traverses and
Method 2 for determining velocity and
volumetric flow rate. The sampling
site for determining SOa concentration
by Method 6 shall be the same as for
determining volumetric flow rate by
Method 2. The sampling point in the
duct for determining SO, concentra-
tion by Method 6 shall be at the cen-
troid of the cross section if the cross
sectional area is less than 5 m* (54 ft1)
or at a point no closer to the walls
than 1 m (39 inches) if the cross sec-
tional area is 5 m' or more and the
centroid is more than one meter from
the wall. The sample shall be extract-
ed at a rate proportional to the gas ve-
locity at the sampling point. The mini-
mum sampling t(me shall be 10 min-
utes and the minimum sampling
volume 0.01 dscm (0.35 dscf) for each
sample. The arithmetic average of two
samples of equal sampling time shall
constitute one run. Samples shall be
taken at approximately 1-hour inter-
vals.86
(d) For the purpose of determining
compliance with §60.104(a)(2).
Method 6 shall be used to determine
the concentration of SO, and Method
15 shall be used to determine the con-
centration of H2S and reduced sulfur
compounds.86
(1) If Method 6 is used, the proce-
dure outlined in paragraph (c)(2) of
this section shall be followed except
that each run shall span a minimum
of four consecutive hours of continu-
ous sampling. A number of separate
samples may be taken for each run,
provided the total sampling time of
these samples adds up to a minimum
of four consecutive hours. Where more
than one sample is used, the average
SO, concentration for the run shall be
calculated as the time weighted aver-
age of the SO, concentration for each
sample according to the formula:
tf
Where:
C« = SO, concentration for the run.
JV=Number of samples.
CS, = SO, concentration for sample t.
&,= Continuous sampling time of sample t.
T= Total continuous sampling time of all
N samples. 86
(2) If Method 15 is used, each run
shall consist of 16 samples taken over
a minimum of three hours. The sam-
pling point shall be at the centroid of
the cross section of the duct if the
cross sectional area is less than 5 m'
(54 ft2) or at a point no closer to the
walls than 1 m (39 inches) if the cross
sectional area is 5 m2 or more and the
centroid is more than 1 meter from
the wall. To insure minimum residence
time for the sample inside the sample
lines, the sampling rate shall be at
least 3 liters/minute (0.1 ft'/min). The
SOi equivalent for each run shall be
calculated as the .arithmetic average of
the SO, equivalent of each sample
during the run. Reference Method 4
shall be used to determine the mois-
ture content of the gases. The sam-
pling point for Method 4 shall be adja-
cent to the sampling point for Method
15. The sample shall be extracted at a
rate proportional to the gas velocity at
the sampling point. Each run shall
span a minimum of four consecutive
hours of continuous sampling. A
number of separate samples may be
taken for each run provided the total
sampling time of these samples adds
up to a minimum of four consecutive
hours. Where more than one sample is
used, the average moisture content for
the run shall be calculated as the time
weighted average of the moisture con-
tent of each sample according to the
formula:
Bm=Proportion by volume of water vapor
in the gas stream for the run.
N=Number of samples.
&,=Proportion by volume of water vapor
in the gas stream for the sample t.
t,, = Continuous sampling time for sample
t.
T= Total continuous sampling time of all
N samples.

(Sec. 114 of the Clean Air Act, as amended
[42U.S.C. 7414]). 86
36 FR 24876, 12/23/71 (?)

as amended

39 FR 9308, 3/8/74 (5)
40 FR 46250, 10/6/75 (18)
42 FR 32426, 6/24/77 (61)
42 FR 37936, 7/25/77 (64)
42 FR 39389, 8/4/77 (66)
42 FR 41424, 8/17/77 (68)
43 FR 8800, 3/3/78 (83)
43 FR 10866, 3/15/78 (86)
44 FR 13480, 3/12/79 (96)
III-24a
-------
III-24b
-------
system which Is heated to 120' C must be ca-
pable of a minimum of 9:1 dilution of
sample. Equipment used in the dilution
system is listed below:
12.1.2.1 Dilution Pump. Model A-1SO Koh-
myhr Teflon positive displacement type,
nonadj us table ISO cc/mln. ±2.0 percent, or
equivalent, per dilution stage. A 9:1 dilution
of sample is accomplished by combining 150
cc of sample with 1350 cc of clean dry air as
shown in Figure 15-2.
12.1.2.2 Valves. Three-way Teflon solenoid
or manual type.
12.1.2.3 Tubing. Teflon tubing and fittings
&re used throughout from the sample probe
to the GC/PPD to present an inert surface
for sample gas.
12.1.2.4 Box. Insulated box, heated and
maintained at 120' C, of sufficient dimen-
sions to house dilution apparatus.
12.1.2.5 Flowmeters. Rotameters or equiv-
alent to measure flow from 0 to 1500 ml/
mln. ±1 percent per dilution stage.
12.1.3.0 Oas Chromatograph.
12.1.3.1 Column—1.83 m (6 ft.) length of
Teflon tubing. 2.16 mm (0.085 in.) Inside di-
ameter, packed with deactivated silica gel,
or equivalent.
12.1.3.2 Sample Valve. Teflon six port gas
sampling valve, equipped with a 1 ml sample
loop, actuated by compressed air (Figure 15-
1).
12.1.3.3 Oven. For containing sample
valve, stripper column and separation
column. The oven should be capable of
maintaining an elevated temperature rang-
ing from ambient to 100* C. constant within
±rc.
12.1.3.4 Temperature Monitor. Thermo-
couple pyrometer to measure column oven.
detector, and exhaust temperature ±1* C.
12.1.3.5 Flow System. Gas metering
system to measure sample flow, hydrogen
flow, oxygen flow and nitrogen carrier gas
flow.
12.1.3.6 Detector. Flame photometric de-
tector.
12.1.3.7 Electrometer. Capable of full scale
amplification of linear ranges of 10"'to 10~*
amperes full scale.
12.1.3.8 Power Supply. Capable of deliver-
ing up to 750 volts.
12.1.3.9 Recorder. Compatible with the
output voltage range of the electrometer.
12.1.4 Calibration. Permeation tube
system (Figure 15-3).
12.1.4.1 Tube Chamber. Glass chamber of
sufficient dimensions to house permeation
tubes.
12.1.4.2 Mass Flowmeters. Two mass flow-
meters in the range 0-3 1/mln. and 0-10 I/
mln. to measure air flow over permeation
tubes at ±2 percent. These flowmeters shall
be cross-calibrated at the beginning of each
test. Using a convenient flow rate In the
measuring range of both flowmeters, set
and monitor the flow rate of gas over the
permeation tubes. Injection of calibration
gas generated at this flow rate as measured
by one flowmeter followed by Injection of
calibration gas at the same flow rate as mea-
sured by the other flowmeter should agree
within the specified precision limits. If they
do not, then there is a problem with the
mass flow measurement. Each mass flow-
meter shall be calibrated prior to the first
test with a wet test meter and thereafter at
least once each year.
12.1.4.3 Constant Temperature Bath. Ca-
pable of maintaining permeation
-------
METHOD 16. SEMICONTINUOU8 DETERMINATION
OF SULFUR EMISSIONS FROM STATIONARY
SOURCES 82

Introduction

The method described below uses the
principle of gas chromatographic separation
and flame photometric detection. Since
there are many systems or sets of operating
conditions that represent usable methods of
determining sulfur emissions, all systems
which employ this principle, but differ only
In details of equipment and operation, may
be used as alternative methods, provided
that the criteria set below are met.
1. Principle and Applicability.
1.1 Principle. A gas sample is extracted
from the emission source and diluted with
clean dry air. An aliquot of the diluted
sample is then analyzed for hydrogen sul-
flde (H.S), methyl mercaptan (MeSH), di-
methyl sulfide (DMS) and dimethyl disul-
fide (DMDS) by gas chromatographic (OC)
separation and flame photometric detection
(PPD). These four compounds are known
collectively as total reduced sulfur (TRS).
1.2 Applicability. This method is applica-
ble for determination of TRS compounds
from recovery furnaces, lime kilns, and
smelt dissolving tanks at kraft pulp mills
2. Range and Sensitivity.
2.1 Range. Coupled with a gas chromato-
graphic system utilizing a ten milllliter
sample size, the maximum limit of the FPD
for each sulfur compound is approximately
1 ppm. This limit is expanded by dilution of
the sample gas before analysis. Kraft mill
gas samples are normally diluted tenfold
(9:1), resulting in an upper limit of about 10
ppm for each compound.
For sources with emission levels between
10 and 100 ppm, the measuring range can be
best extended by reducing the sample size
to 1 mllliliter.
2.2 Using the sample size, the minimum
detectable concentration is approximately
50 ppb.
3. Interferences.
3.1 Moisture Condensation. Moisture
condensation in the sample delivery system,
the analytical column, or the FPD burner
block can cause losses or interferences. This
potential is eliminated by heating the
sample line, and by conditioning the sample
with dry dilution air to lower its dew point
below the operating temperature of the
OC/FPD analytical system prior to analysis.
3.2 Carbon Monoxide and Carbon Diox-
ide. CO and CO, have substantial desensitiz-
ing effect on the flame photometric detec-
tor even after 9:1 dilution. Acceptable sys-
tems must demonstrate that they have
eliminated this interference by some proce-
dure such as eluting these compounds
before any of the compounds to be mea-
sured. Compliance with this requirement
can be demonstrated by submitting chroma-
tograms of calibration gases with and with-
out CO, In the diluent gas. The CO, level
should be approximately 10 percent for the
case with CO, present. The two chromato-
graphs should show agreement within the
precision limits of Section 4.1.
3.3 Paniculate Matter. Particulate
matter in gas samples can cause Interfer-
ence by eventual clogging of the analytical
system. This interference must be eliminat-
ed by use of a probe filter.
3.4 Sulfur Dioxide. SO, Is not a specific
Interferent but may be present in such large
amounts that It cannot be effectively sepa-
rated from other compounds of interest.
The procedure must be designed to elimi-
nate this proble.ni either by the choice of
separation columns or by removal of SO,
from the sample, in the example
system, SO, is removed by a citrate
buffer solution prior to GC injection.
This scrubber will be used when SO,
levels are high enough to prevent
baseline separation from the reduced
sulfur compounds. 93
Compliance with this section can be dem-
onstrated by submitting chromatographs of
calibration gases with SO, present In the
same quantities expected from the emission
source to be tested. Acceptable systems
shall show baseline separation with the am-
plifier attenuation set so that the reduced
sulfur compound of concern is at least 50
percent of full scale. Base line separation Is
defined as a return to zero ± percent In the
interval between peaks.
4. Precision and Accuracy.
4.1 OC/FPD and Dilution System Cali-
bration Precision. A series of three consecu-
tive injections of the same calibration gas,
at any dilution, shall produce results which
do not vary by more than ± 6 percent from
the mean of the three injections.9 3
4.2 GC/FPD and Dilution System Cali-
bration Drift. The calibration drift deter-
mined from the mean of three injections
made at the beginning and end of any 8-
hour period shall not exceed ± percent.
4.3 System Calibration Accuracy.
Losses through the sample transport
system must be measured and a cor-
rection factor developed to adjust the
calibration accuracy to 100 percent.93
5. Apparatut (See Figure 16-1).
5.1. Sampling.93
5.1.1 Probe. The probe must be made of
inert material such as stainless steel or
glass. It should be designed to Incorporate a
filter and to allow calibration gas to enter
the probe at or near the sample entry point.
Any portion of the probe not exposed to the
stack gas must be heated to prevent mois-
ture condensation.
5.1.2 Sample Line. The sample line must
be made of Teflon,1 no greater than 1.3 cm
(ft) inside diameter. All parts from the
probe to the dilution system must be ther-
mostatically heated to 120* C.
5.1.3 Sample Pump. The sample pump
shall be a leakless Teflon-coated diaphragm
type or equivalent. If the pump is upstream
of the dilution system, the pump head must
be heated to 120* C.
5.2 Dilution System. The dilution system
must be constructed such that all sample
contacts are made of Inert materials (e.g.,
stainless steel or Teflon). It must be heated
to 120' C. and be capable of approximately a
9:1 dilution of the sample.
5.3 SO, Scrubber. The
Sd scrubber is a midget impinger
packed with glass wool to eliminate
entrained mist and charged with po-
tassium citrate-citric acid buffer.5*3
5.4 Oas Chromatograph. The gas chro-
matograph must have at least the following
components: '3
5.4.1 Oven. Capable of maintaining the
separation column at the proper operating
temperature ±1' C.93
5.4.2 Temperature Gauge. To monitor
column oven, detector, and exhaust tem-
perature ±1'C.93
5.4.3 Flow System. Oas metering system
to measure sample, fuel, combustion gas,
and carrier gas flows. 93
'Mention of trade names or specific-pro* •
ucts does not constitute endorsement by the
Environmental Protection Agency.
5.4.4 Flame Photometric Detector. 93
5.4.4.1 Electrometer. Capable of full scale
amplification of linear ranges of 10~' to 10~<
amperes full scale.93
6.4.4.2 Power Supply. Capable of deliver-
ing up to 750 volts. 93
6.4.4.3 Recorder. Compatible with the
output voltage range of the electrometer. 9 3
5.6 Oas Chromatograph Columns. The
column system must be demonstrated to be
capble of resolving the four major reduced
sulfur compounds: H£. MeSH, DMS, and
DMDS. It must also demonstrate freedom
from known Interferences.93
To demonstrate that adequate resolution
has been achieved, the tester must submit a
Chromatograph of a calibration gas contain-
ing all four of the TRS compounds in the
concentration range of the applicable stan-
dard. Adequate resolution will be defined as
base line separation of adjacent peaks when
the amplifier attenuation Is set so that the
smaller peak Is at least 50 percent of full
scale. Base line separation Is defined In Sec-
tion 3.4. Systems not meeting this criteria
may be considered alternate methods sub-
ject to the approval of the Administrator. 93
5.5.1 Calibration System. The calibration
system must contain the following compo-
nents. 93
6.5.2 Tube Chamber. Chamber of glass or
Teflon of sufficient dimensions to house
permeation tubes. 93
.5.5.3 Flow System. To measure air flow
over permeation tubes at ±2 percent. Each
flowmeter shall be calibrated after a com-
plete test series with a wet test meter. If the
flow measuring device differs from the wet
test meter by 5 percent, the completed test
shall be discarded. Alternatively, the tester
may elect to use the flow data that would
yield the lower flow measurement. Calibra-
tion with a wet test meter before a test is
optional.93
6.5.4 Constant Temperature Bath. Device
capable of maintaining the permeation
tubes at the calibration temperature within
±0.1° C.93
5.5.5 Temperature Gauge. Thermometer
or equivalent to monitor bath temperature
within ±1'C.93
6. Reagents.
6.1 Fuel. Hydrogen (Hi) prepurlfied
grade or better.
6.2 Combustion Gas. Oxygen (O,) or air,
research purity or better.
6.3 Carrier Gas. Prepurlfied grade or
better.
6.4 Diluent. Air containing less than 50
ppb total sulfur compounds and less than 10
ppm each of moisture and total hydrocar-
bons. This gas must be heated prior to
mixing with the sample to avoid water con-
densation at the point of contact.
6.5 Calibration Gases. Permeation tubes.
one each of H.S, MeSH. DMS, and DMDS,
agravlmetrically calibrated and certified at
some convenient operating temperature.
These tubes consist of hermetically sealed
FEP Teflon tubing in which a liquified gas-
eous substance is enclosed. The enclosed gas
permeates through the tubing wall at a con-
stant rate. When the temperature is con-
stant, calibration gases Governing a wide
range of known concentrations can be gen-
erated by varying and accurately measuring
the flow rate of diluent gas passing over the
tubes. These calibration gases are used to
calibrate the GC/FPD system and the dilu-
tion system.
6.6 Citrate Buffer. Dis-
solve 300 grams ol potassium .citrate
and 41 grams of anhydrous citric acid
In 1 liter of deionized water. 284 grams
of sodium citrate may be substituted
for the potassium citrate. 93
Ill-Appendix A-60
-------
7. Pretest IPros&iwrea. The following proce-
dures are optional but t?ould be helpful In
preventing any problem which might occur
later oafl Invalidate the entire test.
7.1 After the complete measurement
system has been oet up at the site and
deemed to be operational, the following pro-
cedures should be completed before sam-
pllna is initiated.
7.1.1 Leak Test. Appropriate leak test
procedures should be employed to verify the
Integrity of all components, sample lines,
and connections. The following leak test
procedure is suggested: For components up-
stream of the sample pump, attach the
probe end of the sample line to a me- no-
meter or vacuum cause, start the pump and
pull greater than SO mm (2 In.) Hg vacuum,
close off the pump outlet, end then stop the
pump and ascertain that there is no leak for
1 minute. For components after the pump,
apply a slight positive pressure and check
for leaks by applying a liquid (detergent In
water, for example) at each joint. Bubbling
indicates the presence of a leak.
7.1.2 System Performance. Since the
complete system Is calibrated following each
test, the precise calibration of each compo-
aent is not critical. However, these compo-
nents should be verified to be operating
properly. This verification can be performed
by observing the response of flowmeters or
of the GC output to changes In flow rates or
calibration gas concentrations and ascer-
taining the response to be within predicted
limits. In any component, or if the complete
system falls to respond in a normal and pre-
dictable manner, the source of the discrep-
ancy should be identified and corrected
before proceeding.
8. Calibration. Prior to any sampling run,
calibrate the system using the following
procedures. (If more than one run is per-
formed during'any 24-hour period, a calibra-
tion need not be performed prior to the
cecond and any subsequent runs. The cali-
bration must, however, be verified as pre-
scribed in Section 10. after the last run
made within the 24-hour period.)
8.1 General Considerations. This section
outlines steps to be followed for use of the
OC/FPD and the dilution system. The pro-
cedure does not Include detailed instruc-
tions because the operation of these systems
io complex, and it requires a understanding
of the individual system being used. Each
system should Include a written operating
manual describing in detail the operating
procedures associated with each component
in the measurement system. In addition, the
operator should be familiar with the operat-
ing principles of the components; particular-
ly the GC/FPD. The citations in the Bib-
liography at the end of this method are rec-
ommended for review for this purpose.
3.2 Calibration Procedure. Insert the per-
meation tubes into the tube chamber.
Check the bath temperature to assure
agreement with the calibration temperature
of the tubes within ±0.1* C. Allow 24 hours
for the tubes to equilibrate. Alternatively
equilibration may be verified by Injecting
samples of calibration gas at 1-hour inter-
vals. The permeation tubes can be assumed
to have reached equilibrium when consecu-
tive hourly samples agree within the preci-
sion limits of Section 4.1.
Vary the amount of air flowing over the
tubes to produce the desired concentrations
for calibrating the analytical and dilution
systems. The air flow across the tubes must
at all times exceed the flow requirement of
the analytical systems. The concentration in
ports per million generated by a tube con-
taining a specific permeant can be calculat-
ed as follows: p

c ' K HT
Equation 16-1
where:

C= Concentration of permeant produced in
ppm.
P,=Permeation rate of the tube in pg/min.
M=Molecular weight of the permeant (g/g-
mole).
LoFlow rate, 1/min, of air over permeant @
20' C, 760 mm Hg.
K=Gas constant at 20* C and 760 mm
Hg=24.04 1/gmole.

8.3 Calibration of analysis system. Gen-
erate a series of three or more known con-
centrations spanning the linear range of the
FPD (approximately 0.05 to 1.0 ppm) for
each of the four major sulfur compounds.
Bypassing the dilution system, but using
the SO, scrubber, inject these
standards into the GC/FPD analyzers and
monitor the responses. Three injects for
each concentration must yield the precision
described in Section 4.1. Failure to attain
this precision is an indication of a problem
in the calibration or analytical system. Any
such problem must be identified and cor-
rected before proceeding.93
8.4 Calibration Curves. Plot the OC/FPD
response in current (amperes) versus their
causative concentrations in ppm on log-log
coordinate graph paper for each sulfur com-
pound. Alternatively, a least squares equa-
tion may be generated from the calibration
data.
8.5 Calibration of Dilution System. Gen-
erate a known concentration of hydrogen
sulfide using the permeation tube system.
Adjust the flow rate of diluent air for the
first dilution stage so that the desired level
of dilution Is approximated. Inject the dilut-
ed calibration gas Into the GC/FPD system
and monitor its response. Three injections
for each dilution must yield the precision
described in Section 4.1. Failure to attain
this precision in this step is an Indication of
a problem in the dilution system. Any such
problem must be identified and corrected
before proceeding. Using the calibration
data for H>S (developed under 8.3) deter-
mine the diluted calibration gas concentra-
tion in ppm. Then calculate the dilution
factor as the ratio of the calibration gas
concentration before dilution to the diluted
calibration gas concentration determined
under this paragraph. Repeat this proce-
dure for each stage of dilution required. Al-
ternatively, the GC/FPD system may be
calibrated by generating a series of three or
more concentrations of each sulfur com-
pound and diluting these samples before in-
jecting them into the GC/FPD system. This
data will then serve as the calibration data
for the unknown samples and a separate de-
termination of the dilution factor will not
bs necessary. However, the precision re-
quirements of Section 4.1 are still applica-
ble.
8. Sampling and Analysis Procedure.
9.1 Sampling. Insert the sampling probe
Into the test port making certain that no di-
lution air enters the stack through the port.
Begin sampling and dilute the sample ap-
proximtely 9:1 using the dilution system.
Note that the precise dilution factor is that
which is determined In paragraph 8.5. Con-
dition the entire system with sample for a
minimum of 15 minutes prior to commenc-
ing analysis.
8.2 Analysis. Aliquots of dilut-

ed sample pass through the SO, scrub-
ber, and then are injected into the
GC/FPD analyzer for analysis.93
9.2.1 Sample Run. A sample "run is com-
posed of 16 individual analyses (injects) pf
formed over a period of not less than 3
hours or more than 6 hours.
9.2.2 Observation for Clogging of Probe.
If reductions in sample concentrations are
observed during a sample run that cannot
be explained by process conditions, the sam-
pling must be Interrupted to determine if
the sample probe is clogged with particulate
matter. If the probe Is found to be clogged,
the test must be stopped and the results up
to that point discarded. Testing may resume
after cleaning the probe or replacing It with
a clean one. After each run, the sample
probe must be inspected and, if necessary,
dismantled and cleaned.
10. Post-Test Procedures.

10.1 Sample line loss. A known concen-
tration of hydrogen sulfide at the level of
!i..- applicable standard, ± 20 percent, ir i-1
be introduced into the sampling system in
(sufficient quantities to insure that there is
on excess of sample which must be vented
to the atmosphere. The sample must be in-
troduced Immediately after the probe and
filter and transported through the remain-
der of the sampling system to the measure-
ment system in the normal manner. The re-
sulting measured concentration should be
compared to the known value to determine
the sampling system loss.91
For sampling losses greater than 20 per-
cent in a sample run, the sample run is not
to be used when determining the arithmetic
mean of the performance test. For sampling
losses of 0-20 percent, the sample concen-
tration must be corrected by dividing the
sample concentration by the fraction of re-
covery. The fraction of recovery is equal to
one minus the ratio of the measured con-
;entration to the known concentration of
hydrogen sulfide in the sample line loss pro-
cedure. The known gas sample may be gen-
erated using permeation tubes. Alternative-
ly, cylinders of hydrogen sulfide mixed in
air may be used provided they are traceable
to permeation tubes. The optional pretest
procedures provide a good guideline for de-
termining if there are leaks in the sampling
system."

10.2 Recalibration. After each run, or
after a series of runs made within a 24-hour
period, perform a partial recalibration using
the procedures In Section 8. Only H,S (or
other permeant) need be used to recalibrate
the GC/FPD analysis system (8.3) and the
dilution system (8.5).

10.3 Determination of Calibration Drift.
Compare the calibration curves obtained
prior to the runs, to the calibration cunes
obtained under paragraph 10.1. The calibra-
tion drift should not exceed the limits set
forth insubseclion4.2. if the drift exceeds
this limit, the intervening run or runs
should be considered not valid. The tester,
however, may instead have the option of
choosing the calibration data set which
would give the highest sample values. 93
11. Calculations.

11.1 Determine the concentrations of
each reduced sulfur compound detected di-
rectly from the calibration curves. Alterna-
tively, the concentrations may be calculated
using the equation for the least square line.
11.2 Calculation of TRS. Total reduced
sulfur will be determined for each anaylsis
made by summing the concentrations of
each reduced sulfur compound resolved
-ing a given analysis.
, MeSH, DMS, 2DMDS)d

Equation 16 2
Ill-Appendix A-61
-------
where:

TRS-Total reduced sulfur In ppm, wet
basis.
HiS** Hydrogen sulfide, ppm.
MeSH = Methyl mercaptan, ppm.
DMS=Dimethyl sulfide, ppm.
DMDS=Dimethyl disulfide. ppm.
d-Dilution factor, dlmenclonless.
11.3 Average TRS. The average TRS will
be determined u follows:
N
I TRS
Average TRS.
Average TRS -Average total reduced suflur
In ppm, dry basis.
TRS, = Total reduced sulfur In ppm as deter-
mined by Equation 16-2.
N- Number of samples.
B,.- Fraction of volume of water vapor in
the BOS stream as determined by Refer
ence method 4 --Determination of 93
Moisture in Stack Oases (36 FR 248B7).
11.4 Average concentration of individual
reduced sulfur compounds.
N
I s,
i = 1
Equation 16-3
where:

8,=Concentration of any reduced sulfur
compound from the ith sample injec-
tion, ppm.
C=Average concentration of any one of the
reduced sulfur compounds for the entire
run, ppm.
N=Number of injections in any run period.

12. Example System. Described below is a
system utilized by EPA in gathering NSPS
data. This system does not now reflect all
the latest developments In equipment and
column technology, but it does represent
one system that has been demonstrated to
work.
12.1 Apparatus.
12.1.1 Sampling System.
12.1.1.1 Probe. Figure 16-1 illustrates the
probe used in lime kilns and other sources
where significant amounts of particulate
matter are present, the probe is designed
with the deflector shield placed between the
sample and the gas inlet holes and the glass
wool plugs to reduce clogging of the filter
and possible adsorption of sample gas. The
exposed portion of the probe between the
sampling port and the sample line is heated
with heating tape.
12.1.1.2 Sample Line Vi« inch inside diam-
eter Tenon tubing, heated to 120' C. This
temperature is controlled by a thermostatic
heater.
12.1.1.3 Sample Pump. Leakless Tetter
coated diaphragm type or equivalent. Th
pump head is heated to 120" C by enclosing
It in the sample dilution box (12.1.2.4 below).
12.1.2 Dilution System. A schematic dia-
gram of the dynamic dilution system is
given in Figure 16-2. The dilution system is
constructed such that all sample contacts
are made of inert materials. The dilution
system which is heated to 120' C must be ca-
pable of a minimum of 9:1 dilution of
sample. Equipment used in the dilution
system is listed below: 93
12.1.2.1 Dilution Pump. Model A-150
Kohmyhr Teflon positive displacement
type, nonadjustable 150 cc/mln. ±2.0 per-
cent, or equivalent, per dilution stage. A 9:1
dilution of sample is accomplished by com-
bining 150 cc of sample with 1,350 ec of
clean dry air as shown in Figure 16-2.
12.1.2.2 Valves. Three-way Teflon sole-
noid or manual type.
12.1.2.3 Tubing. Teflon tubing and fit-
tings are used throughout from the sample
probe to the QC/FPD to present an inert
surface for sample gas.,
12.1.2.4 Box. Insulated "box, heated and
maintained at 120* C, of sufficient dimen-
sions to house dilution apparatus.
12.1.2.5 Flowmeters. Rotometers or
equivalent to measure flow from 0 to 1500
ml 'mln ± I percent per dilution stage.
is.l.3 SO, Scrub-
ber. Midget impinger with 15 ml of po-
tassium citrate buffer to absorb SO, in
the sample.93
12.1.4 Qas Chroiaatograph Columns.
Two types of columns are used for separa-
tion of low and high molecular weight
sulfur compounds: 93
12.1.4.1 Low Molecular Weight Sulfur
Compounds Column GC/FPD-I.93
12.1.4.l.lSeparatiori Column. 11 m by 2.16
mm (36 ft by 0.085 in) Inside diameter
Teflon tubing packed with 30/60 mesh
Teflon coated with 5 percent polyphenyl
ether and 0.05 percent orthophosphoric
acid, or equivalent (see Figure 16-3).
12.1.4.1.2 Stripper or Precolumn. 0.6 m
by 2.16 mm (2 ft by 0.085 In) inside diameter
Teflon tubing.93
12.1.4.1.3 Sample Valve. Teflon 10-port
gas sampling valve, equipped with a 10 ml
sample loop, actuated by compressed air
(Figure 16-3).93
12.1.4.1.4 Oven. For containing sample
valve, stripper column and separation
column. The oven should be capable of
maintaining an elevated temperature rang-
ing from ambient to 100* C, constant within
±1' C. 93
12.1.4.1.5 Temperature Monitor. Thermo-
couple pyrometer to measure column oven,
detector, and exhaust temperature ±1* C.93
12.1.4.1.6 Flow System. Gas metering
system to measure sample flow, hydrogen
flow, and oxygen flow (and nitrogen carrier
gas flow).93
12.1.4.1.7 Detector. Flame photometric
detector.93
12.1.4.1.8 Electrometer. Capable of full
scale amplification of linear ranges of 10~*
to 10"' amperes full scale.93 -•
12.1.4.1.9 Power Supply. Capable of deli-
vering up to 750 volts. 93
12.1.4.1.10 Recorder. Compatible with
the output voltage range of the electrom-
eter.93
12.1.4.2 High Molecular Weight .Com-
pounds Column (OC/FPD-II).93
12.1.4.2.1. Separation Column. 3.05 m by
2.16 mm (10 ft by 0.0885 in) inside diameter
Teflon tubing packed with 30/60 mesh
Teflon coated with 10 percent Triton X-305,
or equivalent.93
12.1.4.2.2 Sample Valve. Teflon 6-port gas
sampling valve equipped with a 10 ml
sample loop, actuated by compressed air
(Figure 16-3).93
12.1.4.2.3 Other Components. All compo-
nents same as In 12.1 4.1 5 to 12.1.4.1.10.
12.).5 Calibration. Permeation tijho
system (figure 16-4).93
12.1.5.1 Tube Chamber. Olass chamber
of sufficient dimensions to house perme-
ation tubes.93
12.1.5.2 Mass Flowmeters. Two mass
flowmeters In the range 0-3 1/min. and 0-10
1/mln. to measure air flow over permeation
tubes at ±2 percent. These flowmeters shall
be cross-calibrated at the beginning of each
test. Using a convenient now rate in the
measuring range of both flowmeters. set
and monitor the now rate of gas over the
permeation tubes. Injection of calibration
gas generated at this now rate as measured
by one flowmeter followed by injection of
calibration gas at the same now rate as mea-
sured by the other nowmeter should agree
within the specified precision limits. If they
do not, then there is a problem with the
mass flow measurement. Each mass now-
meter shall be calibrated prior to the first
teat with a wet test meter and thereafter, at
least once each year.
12.1.5.3 Constant Temperature Bath. Ca-
pable of maintaining permeation tubes at
certification temperature of 30* C. within
±0.1' C.
13.2 Reagents
12.2.1 Fuel. Hydrogen (Hi) prepurlfied
grade or better.
12.2.2. Combustion Oas. Oxygen (O,) re-
search purity or better.
12.2.3 Carrier Oas. Nitrogen (N,) prepuri-
fied grade or better.
12.2.4 Diluent. Air containing less than
50 ppb total sulfur compounds and less than
10 ppm each of moisture and total hydro-
carbons, and filtered using MSA filters
46727 and 79030, or equivalent. Removal of
sulfur compounds can be verified by Inject-
ing dilution air only, described in Section
8.3.
12.2.5 Compressed Air. 60 psig for GC
valve actuation.
12.2.6 Calibrated Gases. Permeation
tubes gravimetrically calibrated and certi-
fied at 30.0' C.
12.2.7 . Citrate
Buffer. Dissolve 300 grams of potas-
sium citrate and 41 grams of anhy-
drous citric acid in 1 liter of deionized
water. 284 grams of sodium citrate
may be substituted for the potassium
citrate.93
12.3 Operating Parameters.
12.3.1 Low-Molecular Weight Sulfur
' Compounds. The operating parameters for
the GC/FPD system used for low molecular
weight compounds are as follows: nitrogen
carrier gas now rate of 50 cc/min, exhaust
temperature of 110' C, detector temperature
of 105* C, oven temperature of 40' C, hydro-
gen now rate of 80 cc/mln, oxygen now rate
of 20 cc/min, and sample now rate between
20 and 80 cc/mln.
12.3.2 High-Molecular "Weight Sulfur
Compounds. The operating parameters for
the GC/FPD system for high molecular
weight compounds are the same as in 12.3.1
except: oven temperature of 70' C, and ni-
trogen carrier gas now of 100 cc/mln.
12.4 Analysis Procedure.
12.4.1 Analysis. Aliquots of diluted
sampje are injected simultaneously into
both GC/FPD analyzers for analysis. GC/
FPD-I is used to measure the low-molecular
weight reduced sulfur compounds. The low
molecular weight compounds include hydro-
gen sulfide, methyl mercaptan, and di-
methyl sulfide. GC/FPD-II is used to re-
solve the high-molecular weight compound.
The high-molecular weight compound is di-
methyl disulfide.
12.4.1.1 Analysis of Low-Molecular
Weight Sulfur Compounds. The sample
valve is actuated for 3 minutes in which
time an aliquot of diluted sample Is injected
into the stripper column and analytical
column. The valve is then deactivated for
approximately 12 minutes in which time,
the analytical column continues to be fore-
Ill-Appendix A-62
-------
flushed, the stripper column is backflushed.
and the sample loop Is refilled. Monitor the
responses. The eiutlon time for each com-
pound will be determined during calibra-
tion.
12.4.1.2 Analysis of High-Molecular
Weight Sulfur Compounds. The procedure
is essentially the same as above except that
no stripper column is needed.
13. Bibliography.
13.1 O'Keeffe. A. E. and O. C. Ortman.
"Primary Standards for Trace Oas Analy-
sis." Analytical Chemical Journal, 38,760
(1966).
13.2 Stevens, R. K., A. E. O'Keeffe. and
O. C. Ortman. "Absolute Calibration of a
Flame Photometric Detector to Volatile
Sulfur Compounds_at Sub-Part-Per-Million
Levels." Environmental Science and Tech-
nology. 3:7 (July, 1969).
13.3 Mullck, J. D., R. K. Stevens, and R.
Baumgardner. "An Analytical System De-
signed to Measure Multiple Malodorous
Compounds Related to Kraft Mill Activi-
ties." Presented at the 12th Conference on
13.6 General Reference. Standard Meth-
ods of Chemical Analysis Volume III A and
B Instrumental Methods. Sixth Edition.
Van Nostrand Reinhold Co 93
\
1
\
Methods in Air Pollution and Industrial Hy
glene Studies, University of Southern Call
fornla, Los Angeles, CA. April 6-8. 1971.

13.4 Devonald, R. H.. R. S. Serenlus, and
.A. D. Mclntyre. "Evaluation of the Flame
Photometric Detector for Analysis of Sulfur
Compounds." Pulp and Paper Magazine of
Canada, 73.3 (March, 1972).
13.5 Orimley. K. W.. W. S. Smith, and R..
M. Martin. "The Use of a Dynamic Dilution.
System in the Conditioning of Stack Gases
for Automated Analysis by a Mobile Sam-
pling Van." Presented at the 63rd Annual
APCA Meeting in St. Louis, Mo. June 14-19,
1970.
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III-Appendix A-63
-------
I
t!
(D
H-
X
PROSE
STACK
\W.'. ! '
TO GC/FPD ANALYZERS

10:1 102:1
FILTER
(GLASS WOOL)
FILTER
HEATED
SAMPLE
LINE
PuSiTivt
DISPLACEMENT
- PUMP
PERMEATION
TUBE
CALIBRATION
GAS
U
-*H-
DIAPHRAGM
PUMP
(HEATED)
^
d
DILUTION BOX HEATED
TO 100°C

VENT
DILUENT AIR

•WAY
fv VALVE _
x I/
-or

1350 cc/
1 1

id
-1 F

1
25 PS
CLEA
DRYfl

FLOWMETER
Figure 16-"2. Sampling and dilution apparatus.
-------
Method 19. Determination of Sulfur
Dioxide Removal Efficiency and
Particulate, Sulfur Dioxide and Nitrogen
Oxides Emission Rates From Electric
Utility Steam Generators96
1. Principle and Applicability
4.1 Principle.
1.1.1 Fuel samples from before and
after fuel pretreatment systems are
collected and analyzed for sulfur and
heat content, and the percent sulfur
dioxide (ng/Joule, Ib/million Btu)
reduction is calculated on a dry basis.
. (Optional Procedure.)
• 1.1.2 Sulfur dioxide and oxygen or
carbon dioxide concentration data
obtained from sampling emissions
upstream and downstream of sulfur
dioxide control devices are used to
calculate sulfur dioxide removal
efficiencies. (Minimum Requirement.) As
an alternative to sulfur dioxide
monitoring upstream of sulfur dioxide
control devices, fuel samples may be
collected in an as-fired condition and
analyzed for sulfur and heat content.
(Optional Procedure.)
1.1.3 An overall sulfur dioxide
emission reduction efficiency is
calculated from the efficiency of fuel
pretreatment systems and the efficiency
of sulfur dioxide control devices.
1.1.4 Particulate, sulfur dioxide,
nitrogen oxides, and oxygen or carbon
dioxide concentration data obtained
from sampling emissions downstream
from sulfur dioxide control devices are
used along with F factors to calculate
participate, sulfur dioxide, and nitrogen
oxides emission rates. F factors are
values relating combustion gas volume
to the heat content of fuels.
1.2 Applicability. This method is
applicable for determining sulfur
removal efficiencies of fuel pretreatment
and sulfur dioxide control devices and
the overall reduction of potential sulfur
dioxide emissions from electric utility
oteam generators. This method is also
applicable for the determination of
particulate, sulfur dioxide, and nitrogen
oxides emission rates.
2. Determination of Sulfur Dioxide
Removal Efficiency of Fuel
Pretreatment Systems
2.1 Solid Fossil Fuel.
2.1.1 Sample Increment Collection.
Use ASTM D 2234', Type I, conditions
A, B, or C, and systematic spacing.
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 D
2234'. Collect one gross sample for each
raw coal lot and one gross sample for
each product coal lot.
2.1.2 ASTM Lot Size. For the purpose
of Section 2.1.1, the product coal lot size
is defined as the weight of product coal
produced from one type of raw coal. The
raw coal lot size is the weight of raw
coal used to produce one product coal
lot. Typically, the lot size is the weight
of coal processsed in a 1-day (24 hours)
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 specific power plant
may be used if representative sampling
can be conducted for the raw coal and
product coal.
Note.—Alternate definitions of fuel lot
sizes may be specified subject to prior
approval of the Administrator.
2.1.3 Gross Sample Analysis.
Determine the percent sulfur content
(%S) and gross calorific value (GCV) of
the solid fuel on a dry basis for each
gross sample. Use ASTM 2013 ' for
sample preparation, ASTM D 3177 ' for
sulfur analysis, and ASTM D 3173 ' for
moisture analysis. Use ASTM D 3176 '
for gross calorific value determination.
2.2 Liquid Fossil Fuel.
2.2.1 Sample Collection. Use ASTM
D 270 * following the practices outlined
• for continuous sampling for each gross
sample representing each fuel lot.
223 Lot Size. For the purposes of
Section 2.2.1, the weight of product fuel
from one pretreatment facility and
intended as one shipment (ship load,
barge load, etc.] is defined as one
product fuel lot. The weight of each
crude liquid fuel type used to produce
one product fuel lot is defined as one
inlet fuel lot.
Note.— Alternate definitions of fuel lot
sizes may be specified subject to prior
approval of the Administrator.
Note.— For the purposes of this method,
raw or inlet fuel (coal or oil) is defined as the
fuel delivered to the desulfurization
pretreatment facility or to the steam
generating plant. Forpretreated oil the input
oil,to the oil desulfurization process (e.g.
hydrotreatment emitted) is sampled.
2.2.3 Sample Analysis. Determine
the percent sulfur content (%S) and
gross calorific value (GCV). Use ASTMD
240 ' for the sample analysis. This value
can be assumed to be on a dry basis.
2.3 Calculation of Sulfur Dioxide
Removal Efficiency Due to Fuel
Pretreatment. Calculate the percent
sulfur dioxide reduction due to fuel
pretreatment using the following
equation:
100
SSi/GCVj
Where:
%Rf= Sulfur dioxide removal efficiency due
pretreatment; percent.
%S0=Sulfur content of the product fuel lot on
a dry basis; weight percent.
%Si=Sulfur content of the inlet fuel lot on a
dry basis; weight percent.
GCV0=Gross calorific value for the outlet
fuel lot on a dry basis; k]/kg (Btu/lb).
GCV,=Gross calorific value for the inlet fuel
lot on a dry basis; kj/kg (Btu/lb).

Note.—If more than one fuel type is used to
produce the product fuel, use the following
equation to calculate the sulfur contents per
unit of heat content of the total fuel lot, %S/
GCV:
XS/GCV
k-1
Where:
Yk=The fraction of total mass input derived
from each type, k, of fuel.
%S»=Sulfur content of each fuel type, k,'on a
dry basis; weight percent
GCVk=Gross calorific, value for each fuel
type, k, on a dry basis; kj/kg (Btu/lb).
n=The number of different types of fuels.
'Use the moit recent revision or designation of
the ASTM procedure specified
'Use the most recent revision or designation of
the ASTM procedure specified.
Ill-Appendix A-79
-------
3. Determination of Sulfur Removal
Efficiency ofthe^ Sulfur Dioxide Control
Device
3.1 Sampling. Determine SOt
emission rates at the inlet and outlet of
the sulfur dioxide control system
according to methods specified in the
applicable subpart of the regulations
and the procedures specified in Section
5. The inlet sulfur dioxide emission rate
may be determined through fuel analysis
(Optional, see Section 3.3.)
3.2. Calculation. Calculate the
percent removal efficiency using the
following equation:
~flL • 100 x (1.0 •
Where:
%R, = Sulfur dioxide removal efficiency of
the sulfur dioxide control system using
inlet and outlet monitoring data; percent.
En 0=Sulfur dioxide emission rate from the
outlet of the sulfur dioxide control
system; ng/J (Ib/million Btu).
EM i=Sulfur dioxide emission rate to the
outlet of the sulfur dioxide control
system; ng/J (Ib/million Btu).
3.3 As-fired Fuel Analysis (Optional
Procedure). If the owner or operator of
an electric utility steam generator
chooses to determine the sulfur dioxide
imput rate at the inlet to the sulfur .
dioxide control device through an as-
fired fuel analysis in lieu of data from a
sulfur dioxide control system inlet gas
monitor, fuel samples must be collected
in accordance with applicable
paragraph in Section 2. The sampling
can be conducted upstream of any fuel
processing, e.g., plant coal pulverization.
For the purposes of this section, a fuel
lot size is defined as the weight of fuel
consumed in 1 day (24 hours) and is
directly related to the exhaust gas
monitoring data at the outlet of the
sulfur dioxide control system.
3.3.1 Fuel Analysis. Fuel samples
must be analyzed for sulfur content and
gross calorific value. The ASTM
procedures for determining sulfur
content are defined in the applicable
paragraphs of Section 2.
3.3.2 Calculation of Sulfur Dioxide
Input Rate. The sulfur dioxide imput rate
determined from fuel analysis is
calculated by:
2.011SJ
10 °r S- x- un1ts'
2.0(XSf) .
I$ » S(LV T x 10* for English units.

Where:

I • Sulfur dioxide Input rate from as-fired fuel analysis,

ng/J (Ib/mllllon Btu).

tSf • Sulfur content of as-fired fuel, on a dry basis; weight

percent.

GCV • Gross calorific value for as-fired fuel, on a dry basis;

kj/kg (Btu/lb).

3.3.3 - Calculation of Sulfur Dioxide 3.3.2 and the sulfur dioxide emission
Emission Reduction Using As-fired Fuel rate, ESOI. determined in the applicable
Analysis. The sulfur dioxide emission paragraph of Section 5.3. The equation
reduction efficiency is calculated using for sulfur dioxide emission reduction
the sulfur imput rate from paragraph ' efficiency is:
« -100 X (1.0 -
Where:
*Rg(f) " Su1fur
removal efficiency of the sulfur

dioxide control system using as-fired fuel analysis

data; percent.
E§0 • Sulfur dioxide emission rate from sulfur dioxide control
. 2
system; ng/J (Ib/mllllon Btu).

I, • Sulfur dioxide Input rate from as-fired fuel analysis;

ng/J (Ib/mUllon Btu).
III-Appendix A-80
-------
4. Calculation of Overall Reduction in
Potential Sulfur Dioxide Emission
4.1 The overall percent sulfur
dioxide reduction calculation uses the
sulfur dioxide concentration at the inlet
to the sulfur dioxide control device as
looci.o- (i.o -
the base value. Any sulfur reduction
realized through fuel cleaning is
introduced into the equation as an
average percent reduction, %R,.
4.2 Calculate the overall percent
sulfur reduction IK
O.o.
Where:

SRQ • Overall sulfur dioxide reduction; percent.

XR« » Sulfur dioxide removal efficiency of fuel pretreatment

from Section 2; percent. Refer to applicable subpart

for definition of applicable averaging period.

XR « Sulfur dioxide removal efficiency of sulfur dioxide control

device either 0- or CO, - based calculation or calculated

fro* fuel analysts and emission data, from Section 3;

percent. Refer to applicable subpart for definition of

applicable averaging period.

5. Calculation of Particulate, Sulfur
Dioxide, and Nitrogen Oxides Emission
Rates
and oxygen concentrations have been
determined in Section 5.1, wet or dry F
factors are used. (Fw) factors and
associated emission calculation
procedures are not applicable and may
not be used after wet scrubbers; (FJ or
(F*) factors and associated emission
calculation procedures are used after
wet scrubbers.) When pollutant and
carbon dioxide concentrations have
been determined in Section 5.1, Fc
factors are used.
5.2.1 Average F Factors. Table 1
shows average Fd, F,, and Fc factors
(scm/J, scf/million Btu) determined for
commonly used fuels. For fuels not
listed in Table 1, die F factors are
calculated according to the procedures
outlined in Section 5.2.2 of this section.
5.2.2 Calculating an F Factor. If the
fuel burned is not listed in Table 1 or if
the owner or operator chooses to
determine an F factor rather than use
the tabulated data, F factors are
calculated using the equations below.
.The sampling and analysis procedures
followed in obtaining data for these
calculations are subject to the approval
of the Administrator and the
Administrator should be consulted prior
to data collection.
5.1 Sampling. Use the outlet SOa or
Ot or CO* concentrations data obtained
in Section 3.1. Determine the paniculate,
NO,, and Oi or CO, concentrations
according to methods specified in an
applicable subpart of the regulations.
5.2 Determination of an F Factor.
Select an average F factor (Section 5.2.1)
or calculate an applicable F factor
(Section 5.2.2.). If combined fuels are
fired, the selected or calculated F factors
are prorated using the procedures in
Section 5.2.3. F factors are ratios of the
gas volume released during combustion
of a fuel divided by the heat content of
the fuel A dry F factor (FJ is the ratio of
the volume of dry flue gases generated
to the calorific value of the fuel
combusted: a wet F factor (Fv) is the
ratio of the volume of wet flue gases
generated to the calorific value of the
fuel combusted; and the carbon F factor
(FJ is the ratio of the volume of carbon
dioxide generated to the calorific value
of the fuel combusted. When pollutant
For SI Units:
2Z7.0(BQ + 9S.7(tC) + 35.4(15) + 8.6(tN) - 28.5QO)
. GCV .

347.4(XH)+95.7(SC)+35.4(SS)+8.6(H<)-2S.5(»0)+13.0(W20)"*
SCV7
20.0(tC
For English Onits:
106E5.57(tH) * 1.53(»C) * O.S7(tS) * O.U(KQ - 0.46(10)1
106[5.57{XH)+1.$3(SC)40.S7(SS)+0.14(Ht)-0.46(JO)+0.
6CV..
Sv
The SHjO tera My be omitted if SH and 10 Include the unavailable
hydrogen and oxygen (n the fora of M-0.
Ill-Appendix A-81
-------
Where:
Fa, F,, and F. have the units of scm/J, or set/
million Btu; «H. %C. %S, %N. %O, and
%HiO are the concentrations by weight
(expressed in percent) of hydrogen,
carbon, sulfur, nitrogen, oxygen, and
water from an ultimate analysis of the
fuel; and GCV is the gross calorific value
of the fuel in kj/kg or Btu/lb and
consistent with the ultimate analysis.
Follow ASTM D 2015* for solid fuels, D
240* for liquid fuels, and D 1826* for
gaseo.. s fuels as applicable in '
determining GCV.

5.2.3 Combined Fuel Firing F Factor.
For affected facilities firing
combinations of fossil fuels or fossil
. fuels and wood residue, the Fd, Fw, or Fe
factors determined by Sections 5.2.1 or
5.2.2 of this section shall be prorated in
accordance with applicable formula as
follows:
,.!, Xk Fdk
n
Z x
k-1
k Fwk
or
or
Fc • I xk F ,
c w k c*

-Where:
Xk=The fraction of total heat input derived
from each type of fuel, K.
n=The number of fuels being burned in.
combination.

5.3 Calculation of Emission Rate.
Select from the following paragraphs the
applicab'. calculation procedure and
calculate the particulate, SO., and NO,
emission rate. The values in the
equations are defined as:
E=Pollutant emission rate, ng/I Ob/million
Btu).
C=Pollutant concentration, ng/scm (Ib/scf).
Note.—It is necessary in some cases to
convert measured concentration units to
other units for these calculations.
Use the following table for such
conversions:
Conversion Factors for Concentration
From— To— Multiply by—

g/scm —
Ib/SC).
ppmlSOJ....,
ppm(NOJ_,
ppm/(SOJ.,
ppm/(NOJ.
5.3.1 Oxygen-Based F Factor
Procedure.
5.3.1.1 Dry Basis. When both percent
oxygen ('.\>O*d) and the pollutant
concentration (CJ are measured in the
flue gas on a dry basis, the following
equation is applicable:
CF r -
Vd LZ0.9 -
U2d
5.3.1.2 Wet Basis. When both the
percent oxygen (%Ot.) and the pollutant
concentration (C.) are measured in the
flue gas on a wet basis, the following
equations are applicable: (Note: Fw
factors are not applicable after wet
scrubbers.)
(t)
20.9
rw 120.9(1 - B-t) -
Where:
8,,= Proportion by volume of water vapor in
the ambient air.
In lieu of actual measurement, B,,
may be estimated as follows:
Note.— The following estimating factors are
selected to assure that any negative error
. introduced in the term:
(.
20.9
will not be larger than -1.5 percent
However, positive errors, or over-
estimation of emissions, of as much as 5
percent may be introduced depending
upon the geographic location of the
facility and the associated range of
ambient mositure.
(i) Bw,=0.027. This factor may be used
as a constant value at any location.
(ii) B,.=Highest monthly average of
6*1 which occurred within a calendar
year at the nearest Weather Service
Station.
(iii) Bw.=Highest daily average of B^
which occurred within a calendar month
at the nearest Weather Service Station,
calculated from the data for the past 3
years. This factor shall be calculated for
each month and may be used as an
estimating factor for the respective
calendar month.
(b)
F- t,
" C» rd '•ZO.i (1 -
°2w
Where:
Bw,= Proportion by volume of water vapor in
the stack gas.

5.3.1.3 Dry/Wet Basis. When the
pollutant concentration (C*) is measured
on a wet basis and the oxygen
concentration (%Oid) or measured on a
dry basis, the following equation is
applicable:
C7
20.9
12079^XO,
'2d

When the pollutant concentration (Co)
is measured on a dry basis and the
oxygen concentration (%OM) is
measured on a wet basis, the following
equation is applicable:.
C«Fd
20.9
20.9 -
"2w
MS
5.3.2 Carbon Dioxide-Based F Factor
Procedure.
5.3.2.1 Dry Basis. When both the
percent carbon dioxide (%COU) and the
pollutant concentration (Cd] are
measured in the flue gas on a dry basis,
the following equation is applicable:

r - f e
E " c F
5.3.2.2 Wet Bast's. When both the
percent carbon dioxide (%COtw) and the
pollutant concentration (C«) are
measured on a wet basis, the following
equation is applicable:
S, '«
5.3.2.3 Dry/Wet Basis. When the
pollutant concentration (C*) is measured
on a wet basis and the percent carbon
dioxide (%COa
-------
4. Calculation of Overall Reduction in
Potential Sulfur Dioxide Emission
4.1 The overall percent sulfur
dioxide reduction calculation uses the
Bttlfur dioxide concentration at the inlet
to the sulfur dioxide control device as
«
Where:
loorj.o
the base value. Any sulfur reduction
realized through fuel cleaning is
introduced into the equation as an
average percent reduction, %R,.
4.2 Calculate the overall percent
sulfur reduction as:
(i.o-
!RQ • Overall sulfur dioxide reduction; percent.

Xftf • Sulfur dioxide removal, efficiency of fuel pretreatatent

from Section 2; percent. Refer to applicable subpart

for definition of applicable averaging period.

SR « Sulfur dioxide removal efficiency of sulfur dioxide control

device either 02 or CO* - based calculation or calculated

fro* fuel analysts and emission data, from Section 3;

percent. Refer to applicable subpart for definition of

applicable averaging period.

6. Calculation of Particulate, Sulfur
Dioxide, and Nitrogen Oxides Emission
Rates
and oxygen concentrations have been
determined in Section 5.1, wet or dry F
factors are used. (Fw) factors and
associated emission calculation
procedures are not applicable and may
not be used after wet scrubbers; (FJ or
(Fd) factors and associated emission
calculation procedures are used after
wet scrubbers.) When pollutant and
carbon dioxide concentrations have
been determined in Section 5.1, Fe
factors are used.
5.2.1 A verage F Factors. Table 1
shows average Fd, F«, and Fc factors
(scm/J, scf/million Btu) determined for
commonly used fuels. For fuels not
listed in Table 1, the F factors are
calculated according to the procedures
outlined in Section 5.2.2 of this section.
5.2.2 Calculating an F Factor. If the
fuel burned is not listed in Table 1 or if
the owner or operator chooses to
determine an F factor rather than use
the tabulated data, F factors are
calculated using the equations below.
.The sampling and analysis procedures
followed in obtaining data for these
calculations are subject to the approval
of the Administrator and the
Administrator should be consulted prior
to data collection.
5J Sampling. Use the outlet SO» or
Oi or COx concentrations data obtained
in Section 3.1. Determine the particulate,
NO,, and Ot or COi concentrations
according to methods specified in an
applicable subpart of the regulations.
5.2 Determination of an F Factor.
Select an average F factor (Section 5.2.1)
or calculate an applicable F factor
(Section 5.2.2,). If combined fuels are
fired, the selected or calculated F factors
are prorated using the procedures in
Section 5.2.3. F factors are ratios of the
gas volume released during combustion
of a fuel divided by the heat content of
the fuel A dry F factor (FJ is the ratio of
the volume of dry flue gases generated
to the calorific value of the fuel
combusted: a wet F factor (FJ Is the
ratio of the volume of wet flue gases
generated to the calorific value of the
fuel combusted; and the carbon F factor
(Fe) is the ratio of the volume of carbon
dioxide generated to the calorific value
of the fuel combusted. When pollutant
For SI Units:
227.0(») * 95.7(tC) * 35.4(»S) * 8.6(tN) - 28.5(80}
ecv

347.4(XH)+95.7(XC)-»-35.4(SS)+8.6(SN)-28.5(SO)+13.0(*H20)"
__.
For English Units:
106[5.57(*H) * 1.53(*C) + 0.57(»S)
GCV

106[5.57(XH)-M.53(SC)*0.57(*S)+0.14(aO-0.46(«0)+0.
The JHjO tern My be omitted if ZH and U Include the unavailable
hydrogen and oxygen in the fora of M-0.
Ill-Appendix A-83
-------
Where:
E^=Pollutant emission rate from steam
generator effluent, ng/J (Ib/million Btu).
Ec=Pol)utant emission rate in combined
cycle effluent; ng/J (Ib/million Btu).
Ep=Pollutant emission rate from gas turbine
effluent; ng/J (Ib/million Btu).
X^csFraction of total heat input from
•upplemental fuel fired to the steam
generator.
Xct=Fraction of total heat input from gas
turbine exhaust gases.
Note.—The total heat input to the steam
generator is the sum of the heat input from
supplemental fuel fired to the steam
generator and the heat input to the steam
generator from the exhaust gases from the
gas turbine.
5.5 Effect of Wet Scrubber Exhaust.
Direct-Fired Reheat Fuel Burning. Some
wet scrubber systems require that the
temperature of the exhaust gas be raised
above the moisture dew-point prior to
the gas entering the stack. One method
used to accomplish this is directfiring of
an auxiliary burner into the exhaust gas.
The heat required for such burners is
from 1 to 2 percent of total heat input of
the steam generating plant. The effect of
this fuel burning on the exhaust gas
components will be less than ±1.0
percent and will have a similar effect on
emission rate'calculations. Because of
this small effect, a determination of
effluent gas constituents from direct-
fired reheat burners for correction of
•tack gas concentrations is not
necessary.
Tcbto M-\.—F Factors for Vtrious fuels'
Where:
•.^Standard deviation of the average outlet
hourly average emission rates for the
reporting period; ng/J (Ib/million Btu).
§,=Standard deviation of the average inlet
hourly average emission rates for the
reporting period; ng/J (Ib/million Btu).
6.3 Confidence Limits. Calculate the
lower confidence limit for the mean
outlet emission rates for SOt and NO.
and, if applicable, the upper confidence
limit for the mean inlet emission rate for
SOt using the following equations:

E.*=E.-t..,»8.
E,*=E,+U.i,8,
Where:
Eo'nThe lower confidence limit for the mean
outlet emission rates; ng/J (Ib/million
Btu).
E,* =The upper confidence limit for the mean
inlet emission rate; ng/J (Ib/million Btu).
U*e=Values shown below for the indicated
number of available data points (n):
Values for t»«
Fuel type
dscm
J
decf
10* Btu
WKf
10* Btu
•cm
J
tcf
10-Btu
Coal:
Anthr^rlto" , „
Bituminous*
Ugrtte
Gac
Natural.

Butane.- ..... _
Wood... *
w«rfB«rt ,...,;..,.„ , „

2 71 X 10"'
2.63x10'*
2.65x10-'
2.47x10"*
2.43x10"'
234x10"*
........ 234x10"'
248x10"*
2.58X10-'

(10100)
(8780)
(8860)
(8180)
(8710)
(8710)
(8710)
(8240)
(8600) .

2*3x10-'
2.86x10"'
3-21x10"'
177x10-'
2*5x10-'
^74x10-'
2.78x10-'

(10540)
(10640)
(11850)
(10320)
(10810)
(10200)
(10380)

0.530x10"'
0.484x10"'
0.513x10"'
0-383x10"'
0.287x10-'
0.321x10"'
^0.337*10-'
0.492x10"'
0.487x10"'
(1870)
(1800)
(1810)
(1420)
(1040)
(1180)
(1250)
(1830)
(1650)
• At classified accordng to ASTM D 388-66.
• Crude, residual, or dtetniate.
«Determined at ttandant conditions: 20' C (68' F) and 760 mm Hg (28.82 h. Hg).
10
11
12-16
17-21
22-26
27-31
32-51
52-81
82-151
152 or more
In,
6.31
2.42
2.35
2.13
2.02
1.84
1.88
1.86
1.83
1*1
1.77
1.73
1.71
1.70
1.68
1.67
1.66
1.65
6. Calculation of Confidence Limits for
Inlet and Outlet Monitoring Data

6.1 Mean Emission Rates. Calculate
the mean emission rates using hourly
averages in ng/J (Ib/million Btu) for SO.
and NO, outlet data and, if applicable,
SO. inlet data using the following
equations:
I x.
I x.
Where:
Eo=Mean outlet emission rate; ng/J (lb/
million Btu).
E,=Mean Inlet emission rate; ng/J (Ib/million
Btu).
x,,=Hourly average outlet emission rate; ng/J
(Ib/million Btu).
Xi=Hourly average in let emission rate; ng/j
(Ib/million Btu).
n0=Number of outlet hourly averages
available for the reporting period.
n,=Number of inlet hourly averages
available for reporting period.
6.2 Standard Deviation of Hourly
Emission Rates. Calculate the standard
deviation of the available outlet hourly
average emission rates for SO. and NOX
and, if applicable, the available inlet
hourly average emission rates for SO.
using the following equations:
PCC
PCC
Where:
The values of this table are corrected for
n-1 degrees of freedom. Use n equal to
the number of hourly average data
points.

7. Calculation to Demonstrate
Compliance When Available
Monitoring Data Are Less Than the
Required Minimum
7.1 Determine Potential Combustion
Concentration (PCC) for SO*.
7.1.1 When the removal efficiency
due to fuel pretreatment (% R,) is
included in the overall reduction in
potential sulfur dioxide emissions (% RJ
and the "as-fired" fuel analysis is not
used, the potential combustion
concentration (PCC) is determined as
follows:
ng/J
Ib/million Btu.
Potential emissions removed by the pretreatment
process, using the fuel parameters defined In
section 2.3; ng/J (Ib/mllllon Btu).
Ill-Appendix A-84
-------
7.1.2 When the "as-fired" fuel
analysis is used and the removal
efficiency due to fuel pretreatment (% RJ
is not included in the overall reduction
in potential sulfur dioxide emissions (%
RO), the potential combustion
concentration (PCC] is determined as
follows:
PCC=I.
PCC
PCC
I. + 2
I. '* 2
7.1.4 When inlet monitoring data are
used and the removal efficiency due to
fuel pretreatment (% Rf) is not included
in the overall redaction in potential
sulfur dioxide emissions (% RO), the
potential combustion concentration
(PCC) is detennined as follows:
PCC = Ei*
Where:
EI* = The upper confidence limit of the mean
inlet emission rate, as determined in
section 6.3.

7.2 Determine Allowable Emission
Rates (Eua).
7.2.1 NO*. Use the allowable
emission rates for NO, as directly
defined by the applicable standard in
terms of ng/J (Ib/million Bra).
7.2.2 SO,. Use the potential
combustion concentration (PCC) for SOi
as detennined in section 7.1. to
determine the applicable emission
standard. If the applicable standard is
an allowable emission rate in ng/J (lb/
million Btu), the allowable emission rate
When:
I. «c The sulfur dJmdde input rate u defined
in lection 3 J
7.1.3 When die "as-fired" fuel
analysis is used and the removal
efficiency due to fuel pretreatment (% RJ
to included in the overall reduction (%
RO), the potential combustion
concentration (PCC] is determined as
follows:
ng/J
1b/irill1on Btu.

is used as E.U. If the applicable standard
is an allowable percent emission,
calculate the allowable emission rate
(E.U) using the following equation:
Where:
% PCC = Allowable percent emission as
defined by the applicable standard;
percent.
73 Calculate Eo* lEua. To determine
compliance for the reporting period
calculate the ratio:
Where:
EC* = The lower confidence limit for the
mean outlet emission rates, as defined in
section 6.3; ng/J (Ib/million Btu).
E^ = Allowable emission rate as defined in
section 7.2; ng/J (Ib/million Btu).
If EO*/EK<] is equal to or less than 1.0, the
facility is in compliance; if E^/E^n is greater
than 1.0, the facility is not In compliance for
the reporting period.
III-Appendix A-85
-------
93. 44 FR 2578, 1/12/79 - Amendments to Appendix A - Reference
Method 16. 279

94. 44 FR 3491, 1/17/79 - Wood Residue-Fired Steam Generators;
Applicability Determination. 280

95. 44 FR 7714, 2/7/79 - Delegation of Authority to State of Texas. 282

96. 44 FR 13480, 3/12/79 - Petroleum Refineries - Clarifying
Amendment. 282

44 FR 15742, 3/15/79 - Review of Performance Standards for
Sulfuric Acid Plants.

44 FR 17120, 3/20/79 - Proposed Amendment to Petroleum Refinery
Claus Sulfur Recovery Plants.

44 FR 17460, 3/21/79 - Review of Standards for Iron & Steel
Plants Basic Oxygen Furnaces.

44 FR 21754, 4/11/79 - Primary Aluminum Plants; Draft Guideline
Document; Availability.

97. 44 FR 23221, 4/19/79 - Delegation of Authority to Washington
Local Agency 284

44 FR 29828, 5/22/79 - Kraft Pulp Mills; Final Guideline Doc-
ument; Availability.

44 FR 31596, 5/31/79 - Definition of "Commenced" for Standards
of Performance for New Stationary Sources.

98. 44 FR 33580, 6/11/79 - Standards of Performance Promulgated
for Electric Utility Steam Generating Units. 285

44 FR 34193, 6/14/79 - Air Pollution Prevention and Control;
Addition to the List of Categories of Stationary Sources.

44 FR 34840, 6/15/79 - Proposed Standards of Performance for
New Stationary Sources; Glass Manufacturing Plants.

44 FR 35265, 6/19/79 - Review of Performance Standards: Nitric
Acid Plants.

44 FR 35953, 6/19/79 - Review of Performance Standards: Sec-
ondary Brass and Bronze Ingot Production.

44 FR 37632, 6/28/79 - Fossil-Fuel-Fired Industrial Steam
Generators; Advanced Notice of Proposed Rulemaking.

44 FR 37960, 6/29/79 - Proposed Adjustment of Opacity Standard
for Fossil-Fuel-Fired Steam Generator.

xi
-------
93

Title 40—Protection of Environment

CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY

[FRL 1012-2]

PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES
Appendix A—Reference Method 16
AGENCY: Environmental Protection
Agency.
ACTION: Amendment.
SUMMARY: This action amends Ref-
erence Method 16 for determining
total reduced sulfur emissions from
stationary sources. The amendment
corrects several typographical errors
and improves the reference method by
requiring the use of a scrubber to pre-
vent potential interference from high
SOi concentrations. These changes
assure more accurate measurement of
total reduced sulfur (TRS) emissions
but do not substantially change the
reference method.
SUPPLEMENTARY INFORMATION:
On Pebrurary 23, 1978 (43 PR 7575),
Appendix A—Reference Method 16 ap-
peared with several typographical
errors or omissions. Subsequent com-
ments noted these and also suggested
that the problem of high SO, concen-
trations could be corrected by using a
scrubber to remove these high concen-
trations. This amendment corrects the
errors of the original publication and
slightly modifies Reference Method 16
by requiring the use of a scrubber to
prevent potential Interference from
high SO, concentrations.
Reference Method 16 is the refer-
ence method specified for use in deter-
mining compliance with the promul-
gated standards of performance for
kraft pulp mills. The data base used to
develop the standards for kraft pulp
mills has been examined and this addi-
tional requirement to use a scrubber
to prevent potential Interference from
high SOi concentrations does not re-
quire any change to these standards of
performance. The data used to develop
these standards was not gathered from
kraft pulp mills with high SO, concen-
trations; thus, the problem of SO, in-
terference was not present in the data
base. The use of a scrubber to prevent
this potential interference in the
future, therefore, is completely con-
sistent with this data base and the
promulgated standards.
RULES AND REGULATIONS
The increase in the cost of determin-
ing compliance with the standards of
performance for kraft pulp mills, as a
result of this additional requirement
to use a scrubber in Reference Method
16, is negligible. At most, this addition-
al requirement could increase the cost
of a performance test by about 50 dol-
lars.
Because these corrections and addi-
tions to Reference Method 16 are
minor In nature, impose no additional
substantive requirements, or do not re-
quire a change In the promulgated
standards of performance for kraft
pulp mills, these amendments are pro-
mulgated directly.
EFFECTIVE DATE: January 12, 1979.
FOR FURTHER INFORMATION
CONTACT:
Don R. Goodwin, Director. Emission
Standards and Engineering Division,
(MD-13) Environmental Protection
Agency, Research Triangle Park,
North Carolina 27711, telephone
number 919-541-5271.
Dated: January 2,1979.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amend-
ed as follows: •
APPENDIX A—REFERENCE METHODS
In Method 16 of Appendix A, Sec-
tions 3.4, 4.1, 4.3, 5. 5.5.2, 6, 8.3, 9.2,
10.3, 11.3, 12.1, 12.1.1.3, 12.1.3.1,
12.1.3.1.2. 12.1.3.2, 12.1.3.2.3, and 12.2
are amended as follows:
1. In subsection 3.4, at the end of the
first paragraph, add: "In the example
system, SO, is removed by a citrate
buffer solution prior to GC injection.
This scrubber will be used when SO,
levels are high enough to prevent
baseline separation from the reduced
sulfur compounds."
2. In subsection 4.1, change "± 3 per-
cent" to "± 5 percent."
3. In subsection 4.3, delete both sen-
tences and replace with the following:
"Losses through the sample transport
system must be measured and a cor-
rection factor developed to adjust the
calibration accuracy to 100 percent."
4. After Section 5 and before subsec-
tion 5.1.1 insert "5.1. Sampling."
5. In Section 5, add the following
subsection: "5.3 SOZ Scrubber. The
SO, scrubber is a midget impinger
packed with glass wool to eliminate
entrained mist and charged with po-
tassium citrate-citric acid buffer."
Then Increase all numbers from 5.3 up
to and Including 5.5.4 by 0.1, e.g.,
chartge 5.3 to 5.4, etc.
6. In subsection 5.5.2, the word
"lowest" in the fourth sentence Is re-
placed with "lower."
7. In Section 6, add the following
subsection: "6.6 Citrate Buffer. Dis-
solve 300 grams of potassium citrate
and 41 grams of anhydrous citric acid
In 1 liter of deionized water. 284 grams
of sodium citrate may be substituted
for the potassium citrate."
8. In subsection 8.3, In the second
sentence, after "Bypassing the dilu-
tion system," Insert "but using the SO,
scrubber," before finishing the sen-
tence.
9. In subsection 9.2, replace sentence
with the following: "Aliquots~of dilut-
ed sample pass through the SO, scrub-
ber, and then are injected into the
GC/FPD analyzer for analysis."
10. In subsection 10.3, "paragraph"
In the second sentence Is corrected
with "subsection."
11. In subsection 11.3 under Bwo defi-
nition, insert "Reference" before
"Method 4."
12. In subsection 12.1,1.3 "(12.2.4
below)" Is corrected to "(12.1.2.4
below)."
13. In subsection 12.1, add the fol-
lowing subsection: "12.1.3 SO, Scrub-
ber. Midget impinger with 15 ml of po-
tassium citrate buffer to absorb SO, in
the sample." Then renumber existing
section 12.1.3 and following subsec-
tions through and including 12.1.4.3 as
12.1.4 through 12.1.5.3.
14. The second subsection listed as
"12.1.3.1" (before corrected in above
amendment) should be "12.1.4.1.1."
15. In subsection 12.1.3.1 (amended
above to 12.1.4.1) correct "GC/FPD-1
to "GC/FPD-I."
16. In subsection 12.1.3.1.2 (amended
above to 12.1.4.1.2) omit "Packed as in
5.3.1." and put a period after "tubing."
17. In subsection 12.1.3.2 (amended
above to 12.1.4.2) correct "GC/FPD-
11" to "GC/FPD-II."
18. In subsection 12.1.3.2.3 (amended
above to 12.1.4.2.3) the phrase
"12.1.3.1.4. to 12.1.3.1.10" is corrected
to read "12.1.4.1.5 to 12.1.4.1.10."
19. In subsection 12.2, add the fol-
lowing subsection: "12.2.7 Citrate
Buffer. Dissolve 300 grams of potas-
sium citrate and 41 grams of anhy-
drous citric acid in 1 liter of deionized
water. 284 grams of sodium citrate
may be substituted for the potassium
citrate."
(Sec. Ill, 301».
[PR Doc. 79-1047 Filed 1-11-79; 8:45 am]
FEDERAL REGISTER, VOL 44, NO. 9—FRIDAY, JANUARY 13, 1979
IV-279
-------
MOB AMD 4HE6ULATIONS
94

Title 40-Proteetion of Environment

CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
[FRL 1017-7]

PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES

Wood Residue-Fired Steam
Generators

APPLICABILITY DETERMINATION

AGENCY: Environmental Protection
Agency.

ACTION: Notice of Determination.
SUMMARY: "This notice presents the
results of a performance review of par-
ticulate -matter control systems on
wood residue-fired steam generators.
On November 22, 1976 (41 FR 51397),
EPA amended the standards of per-
formance of new fossil-fuel-fired
steam generators to allow the heat
content of wood residue to be included
with the heat content Of fossil-fuel
when determining compliance with
the standards. EPA stated in the pre-
amble that there were some questions
about the feasibility of unite burning a
targe -portion of wood residue to
achieve the participate matter stand-
ard and announced that this would be
reviewed. This review has been com-
pleted, and 'EPA concludes that the
particulate matter standard can be
achieved, therefore, no revision is nec-
essary.

ADDRESSES: The document which
presents the basis for this notice may
be obtained from the Public Informa-
tion Center (PM-215), U.S. Environ-
mental Protection Agency, Washing-
ton. D,C. 20460 (specify "Wood Resi-
due-Fired Steam Generator Particu-
late .Matter .Control Assessment,"
EPA-450/2-78^044.)
The document may be inspected and
copied at .the Public Information Ref-
erence Unit (EPA Library), Room
2922, 401 M Street. S.W., Washington,
D.C.

FOR FURTHER INFORMATION
CONTACT:

Don R. Goodwin, Director, Emission
Standards and Engineering Division,
Environmental Protection Agency,
Research Triangle Park, North
Carolina 27711, telephone number
(919).541^5271.

SUPPLEMENTARY INFORMATION:
On November 22, 1976, standards
under 40 CFR Part 60, Bubpart D for
new fossil-fiiel-fired steam generators
were amended (41 FR 51397) to clarify
that the standards -apply to each
fossil-fuel and wood residue-fired
steam generating unit capable of
firing fossil-fuel at a heat input of
more than 73 megawatts (250 million
Btu per hour). The primary objective
of this amendment is to allow the heat
input provided by wood residue to be
used as a dilution agent in the calcula-
tions necessary to determine sulfur
dioxide emissions. EPA recognized in
the preamble of the amendment that
questions remained concerning the.
ability of affected facilities which
burn substantially more wood residue
than fossil-fuel to comply with the
standard for particulate matter. The
preamble also stated that EPA was
continuing to gather information on
'this question. The discussion that fol-
lows summarizes the results of EPA's
examination of available information.
Wood residue is a waste by-product
of the pulp and paper industry which
consists of bark, sawdust, slabs, chips,
shavings, And .mill trims. Disposal of
this waste prior to the 1960's consisted
mostly of incineration in Dutch ovens
or open .air tepees. Since then the
advent of the spreader etroker boiler
and the Increasing costs of fossil-fuels
has made wood residue an -economical
fuel -to .burn-in large boilers for the
generation of process steam.
There are several hundred steam
generating boilers In the pulp .and
paper and allied forest product indus-
try that use fuel which is partly .or to-
tally derived from wood rasidue. These
boilers range in size from 6 megawatts
C20 million .Btu per hour) to 146
megawatts (500 million Btu per hour)
and the total emissions ,*.-om all boil-
ers is estimated to be 225 tons of par-
ticulate matter per day after applica-
tion of existing air pollution control
devices.
Most existing wood residue-fired
boilers subject to State emission stand-
ards are equipped with multitube-cy-
clone mechanical collectors. Manufac-
turers of the multitube collector have
recognized that this type of control
will not meet present new source
standards and have been developing
processes and devices to meet the new
regulations. However, the use of these
various systems on -wood residue-fired
boilers has not found widespread use
to date, resulting in -an information
gap on expected performance of col-
lector types other than conventional
mechanical collectors.
'In order to provide needed informa-
tion in this area and to answer ques-
tions raised in the November 22, 1976
(41 FR 51397), amendment, a study
was conducted on the most effective
control systems in operation on wood
residue-fired boilers. Also the amount
and characteristics of the particulate
emissions from wood residue-fired boil-
ers was studied. The review that fol-
lows presents the results of that study.

PERFORMANCE REVIEW

The combustion of wood residue re-
sults in particulate emissions in the
form 'of bark char or fly ash. En-
trained with the char are varying
amounts of sapd and salt, the quantity
depending on the method by -which
the original wood was logged and de-
livered. The fly ash particulates have
a lower density and are larger in size
than fly ash from coal-fired boilers. In
general, the bark boiler exhaust gas
will have a lower fly ash content than
emissions from similar boilers burning
physically cleaned coals or low-sulfur
Western coals.
The bark fly ash, unlike most fly
ash, is primarily unburned carbon.
With collection -and reinjection to the
FEDERAL REGISTER, VOL 44, WO. M—WEDNESDAY, JANUARY 17, 1*79
IV-280
-------
QUILES AM®
boiler, greater carbon burnout can in-
crease boiler -efficiency from one to
four percent. The reinjection of col-
lected ash also significantly increases
the dust loading since the sand is also
recirculated with the fly ash. This in-
creased dust loading can be accommo-
dated by the use of sand separators or
decantation type dust collectors. Col-
lectors of this type In combination
with more efficient units of air pollu-
tion control equipment constitute the
systems currently in operation on ex-
isting plants that were found to oper-
ate with emissions less than the 43
nanograms per joule (0.10 pounds per
million Btu) standard for particulate
matter.
A survey of currently operated facili-
ties that fire wood residue alone or in
combination with fossil-fuel shows
that most operate with mechanical
collectors; some operate with low
energy wet scrubbers, and a few facili-
ties currently use higher energy ven-
turi scrubbers (HEVS) or electrostatic
precipitators (ESP). One facility re-
viewed is using a high temperature
baghouse control system.
Currently, the use of multitube-cy-
clone mechanical collectors on hogged-
fuel boilers provides the sole source of
particulate removal for a majority of
existing plants. The most commonly
used system employs two multiclones
in series allowing for the first collector
to remove the bulk of the dust and a
second collector with special high effi-
ciency vanes for the removal of the
finer particles. Collection efficiency
for this arrangement ranges from 65
to 95 percent. This efficiency range is
not sufficient to provide compliance
with the particulate matter standard,
but' does provide a widely used first
stage collection to which other control
systems are added.
Of special note is one facility using a
Swedish designed mechanical collector
to series with conventional multiclone
collectors. The Swedish collector is a
small diameter multitube cyclone with
& movable vane ring that imparts a
spinning motion to the gases while at
the same time maintaining a low pres-
sure differential. This system is reduc-
ing emissions from the largest boiler
found in the review to 107 nanograms
psr joule.
Electrostatic precipitators have been
demonstrated to allow compliance
with the particulate matter standard
when coal is used as an auxiliary fuel.
Available Information Indicates that
fcMs type of control provides high col-
Section efficiencies on combinatibn
wood residue coal-fired boilers. One
ESP collects particulate matter from a
go percent bark, 50 percent coal combi-
nation fired boiler. An emission level
of 13 nanograms per joule (.03 pounds
EKSF million Btu) was obtained using
test methods recommended by the
American Society of Mechanical Engi-
neers.
The fabric filter (baghouse) particu-
late control system provides the high-
est collection efficency available, 99.9
percent. On one facility currently
using a baghouse on a wood residue-
fired boiler, the sodium chloride con-
tent of the ash being filtered is high
enough (70 percent) that the possibil-
ity of fire is practically eliminated.
Source test data collected with EPA
Method 5 showed this system reduces
the particulate emissions to 5 nano-
grams per joule (0.01 pounds per mil-
lion Btu).
The application of fabric filters to
control emissions from hogged fuel
boilers has recently gained acceptance
from several facilities of the paper and
pulp industry, mainly due to the devel-
opment of improved designs and oper-
ation procedures that reduce fire haz-
ards. Several large sized boilers, firing
salt and non-salt laden wood residue,
are being equipped with fabric filter
control systems this year and the per-
formance of these installations will
verify the effectiveness of fabric filtra-
tion.
Practically all of the facilities cur-
rently meeting the new source particu-
late matter standard are using wet
scrubbers of the venturi or wet-im-
pinger type. These units are usually
connected in series with a mechanical
collector. Three facilities reviewed
which are using the wet-impingement
type wet scrubber on large boilers
burning 100 percent bark are produc-
ing particulate emissions well below
the 43 nanograms per joule standard
at operating pressure drops of 1.5 to 2
kPa (6 to 8 inches, H2O). Five facilities
using venturi type wet' scrubbers on
large boilers, two burning half oil and
half bark and the other three burning
100 percent bark, are producing partic-
ulate emissions consistently below the
standard at pressure drops of 2.5 to 5
kPa (10 to 20 inches, H,O).
One facility has a large boiler burn-
ing 100 percent bark emitting a maxi-
mum of 5023 nanograms per joule of
particulate matter into a multi-cyclone
dust collector rated at an efficiency of
87 percent. The outlet loading from
this mechanical collector Is directed
through two wet impingement-type
scrubbers in parallel. With this ar-
rangement of scrubbers, a collection
efficiency of 97.7 percent is obtained
at pressure drops of 2 kPa (8 inches,
H,O). Source test data collected with
EPA Method 5 showed particulate
matter emissions to be 15 nanograms
per joule, well below the 43 nanograms
per joule standard.
Another facility with a boiler of sim-
ilar size and fuel was emitting a maxi-
mum of 4650 nanograms per joule into
& multi-cyclone dust collector operat-
ing at & collection efficiency of 66 per-
cent. The outlet loading from this col-
lector is drawn into two wet-impinge-
ment scrubbers arranged in parallel.
The operating pressure drop on these
scrubbers was varied within the range
of 1.6 to 2.0 kPa (6 to 8 inches. H,O).
resulting in a proportional decrease in
discharged loadings of 25.8 to 18.5
nanograms per Joule. Source test data
collected on this source was obtained
with the Montana Sampling Train.
Facilities using a venturi type wet
scrubber were found to be able to meet
the 43 nanogram per joule standard at
higher pressure drops than the im-
pingement type scrubber. One facility
with a large boiler burning 100 percent
bark had a multi-cyclone dust collec-
tor in series with a venturi wet scrub-
ber operating at a pressure drop of 5
kPa (20 inches, HiO). Source test data
using EPA Method 5 showed this
system consistently reduces emissions
to an average outlet loading of 17.2
nanograms per joule of particulate
matter. Another facility with a boiler
burning 40 percent bark and 60 per-
cent oil has a multi-cyclone and ven-
turi scrubber system obtaining 25.8
nanograms per Joule at a pressure
drop of 2.5 kPa (10 inches, H2O). The
Florida Wet Train was used to obtain
emission data on this source. A facility
of similar design but burning 100 per-
cent bark is obtaining the same emis-
sion control, 25.8 nanograms per joule,
at a pressure drop of 3 kPa (12 inches,
HjO). Source test data collected on
this source were obtained with the
EPA Method 5.
This review has shown that the use
of a wet scrubber, ESP, or a baghouse
to control emissions from wood bark
boilers will permit attainment of the
particulate matter standard under 40
CFR Part 60. The control method cur-
rently used, which has the widest ap-
plication is the multitube cyclone col-
lector in series with a venturi or wet-
impingement type scrubber. Source
test data have shown that facilities
which burn substantially more wood
residue than fossil-fuel have no diffi-
culty in complying with the 43 nano-
gram per joule standard for particu-
late matter. Also the investigated
facilities have been in operation suc-
cessfully for a number of years with-
out adverse economical problems.
Therefore EPA has concluded from
evaluation of the available informa-
tion that no revision is required of the
particulate. matter standard for wood
residue-fired boilers.

Dated: January 3,1979.

DOUGLAS M. COSTLE,
Administrator.
[FR Doc. 79-1421 Piled 1-16-79; 8:45 am]
DBOOSTGQ. W98, 40, MO. 12—WEDMES0AY, JANUAOV 17,
IV-281
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RULES AND REGULATIONS
95

PAIT 60—STANDARDS Of tfiRfOKM-
ANCE FOR NEW STATIONARY
SOURCES

DELEGATION OF AUTHORITY TO
STATE OF TEXAS

AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This action amends Sec-
tion 60.4. Address, to reflect the dele-
gation of authority for the Standards
of Performance for Mew Stationary
Sources (MSFS) to the State of Texas.
IS'J-'lSCTlVlfi DATE February 7.1979.
FOR FURTHER INFORMATION
CONTACT:
James Veach, Enforcement Division,
Region 0, Environmental Protection
Agency, First' International Build-
Ing. 1201 Elm Street, Dallas. Texas
75270, telephone (214) 767-2760.
SUPPLEMENTARY INFORMATION:
A notice announcing the delegation of
authority Is published elsewhere In
the Notice Section in this issue of the
FEDERAL REGISTER. These amendments
provide that all reports and communi-
cations previously submitted to the
Administrator, will now be sent to the
Texas Air Control Board, 8520 Shoal
Creek Boulevard, Austin, Texas 78758,
instead of EPA's Region 6.
As this action is not one of substan-
tive content, but is only an administra-
tive change, public, participation was
judged unnecessary.
(Section* 111 and SOU*) of the Clean Air
Act; Section 4]>.
Dated: November IS, 1978.
AmxHX HARKISO*,
Regional Administrator.
Regie* 6.

Part« of Chapter 1, Title 40. Code
of Federal Regulations, is amended as
follows:
1. In («0.4, paragraph (b) <8S> is
amended as follows:

|M.4 Addreu.
96

PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES

Petroleum Refineries—Clarifying
Amendment

AGENCY: Environmental Protection
Agency.
ACTION: Final Rule.
SUMMARY: These amendments clari-
fy the definitions of "fuel gas" and
"fuel gas combustion device" included
In the existing standards of perform-
ance for petroleum refineries. These
amendments will neither increase nor
decrease the degree of emission con-
trol required by the existing stand-
ards. The objective of these amend-
ments is to reduce confusion concern-
ing the applicability of the sulfur
dioxide standard to incinerator-waste
heat boilers installed on fluid or Ther-
mofor catalytic cracking unit catalyst
regenerators and fluid coking unit
coke burners.
EFFECTIVE DATE: March 12,1979.

FOR
FUKTHJuR
CONTACT:
INFORMATION
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), U£. Environmental Pro-
tection Agency, Research Triangle
Park. North Carolina 27711, tele-
phone (919) 541-5271.
SUPPLEMENTARY INFORMATION:
On March 8, 1974 (39 FR 9315), stand-
ards of performance were promulgated
limiting sulfur dioxide emissions from
fuel gas combustion devices in petro-
leum refineries under 40 CFR Part 60,
Subpart J. Fuel gas combustion de-
vices are defined as any equipment,
such as process heaters, boilers, or
flares, used to combust fuel gas. Fuel
gas is defined as any gas generated by
a petroleum refinery process unit
which 'is combusted. Fluid catalytic
cracking unit and fluid coking unit in-
cinerator-waste heat boilers, and facul-
ties in which gases are combusted to
produce sulfur or sulfuric acid are

FEDEtAL REGISTER, VOL 44, NO. 49—MONDAY, MARCH IX 1979
(SS) State of Texas, Texas Air Con-
trol Board, 8520 Shoal Creek Boule-
vard, Austin, Texas 78758.
CFR Doe. Tfr4t23 Filed 1-6-79; 8:4S ami

KDttAL RIOtntR, VOL 44, NO. XT-WEDNESDAY, fCMUAlY T, W9
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RULES AND REGULATIONS
exempted from consideration as fuel
gas combustion devices.
Recently, the following two ques-
tions have been raised concerning the
Intent of exempting fluid catalytic
cracking unit and fluid coking unit in-
cinerator-waste heat boilers.
(1) Is it intended that Thermofor
catalytic cracking unit incinerator
waste-heat boilers be considered the
same as fluid catalytic cracking unit
Incinerator-waste heat boilers?
(2) Is the exemption intended to
apply to the incinerator-waste heat
boiler as a whole including auxiliary
fuel gas also combusted in this boiler?
The answer to the first question is
yes. The answer to the second ques-
tion is no.
The objective of the standards of
performance is to reduce sulfur diox-
ide emissions from fuel gas combus-
tion in petroleum refineries. The
standards are based on amine treating
of refinery fuel gas to remove hydro-
gen sulfide contained in these gases
before they are combusted. The stand-
ards are not intended to apply to those
gas streams generated by catalyst re-
generation in fluid or Thermofor cata-
lytic cracking units, or by coke burn-
ing in fluid coking units. These gas
streams consist primarily of nitrogen,
carbon monoxide, carbon dioxide, and
water vapor, although small amounts
of hydrogen sulfide may be present.
Incinerator-waste heat boilers can be
used to combust these gas streams as a
means of reducing carbon monoxide
emissions and/or generating steam.
Any hydrogen sulfide present is con-
verted to sulfur dioxide. It is not possi-
ble, however, to control sulfur dioxide
emissions by removing whatever hy-
drogen sulfide may be present in these
gas streams before they are combust-
ed. The presence of carbon dioxide ef-
fectively precludes the use of amine
treating, and since this technology is
the basis for these standards, exemp-
tions are included for fluid catalytic
cracking units and fluid coking units.
Exemptions are not included for
Thermofor catalytic cracking units be-
cause this technology is considered ob-
solete compared to fluid catalytic
cracking. Thus, no new, modified, or
reconstructed Thermofor^ catalytic
cracking units are considered likely.
The possibility that an incinerator-
waste heat boiler might be added to an
existing Thermofor catalytic cracking
unit, however, was overlooked. To take
this possibility into account, the defi-
nitions of "fuel gas" and "fuel gas
combustion device" have been rewrit-
ten to exempt Thermofor catalytic
cracking units from compliance in the
same manner as fluid catalytic crack-
ing units and fluid coking units.
As outlined above, the intent is to
ensure that gas streams generated by
catalyst regeneration or coke burning
in catalytic cracking or fluid coking
units are exempt from compliance
with the standard limiting sulfur diox-
ide emissions from fuel gas combus-
tion. This is accomplished under the
standard as promulgated March 8,
1974, by exempting incinerator-waste
heat boilers installed on these unite
from consideration as fuel gas combus-
tion devices.
Incinerator-waste heat boilers in-
stalled to combust these gas streams
require the firing of auxiliary refinery
fuel gas. This is necessary to insure
complete combustion and prevent
"flame-out" which could lead to an ex-
plosion. By exempting the incinerator-
waste heat boiler, however, this auxil-
iary refinery fuel gas stream is also
exempted, which is not the intent of
these exemptions. This auxiliary refin-
ery fuel gas stream is normally drawn
from the same refinery fuel gas
system that supplies refinery fuel gas
to other process heaters or boilers
within the refinery. Amine treating
can be used, and in most major refin-
eries normally is used, to remove hy-
drogen sulfide from this auxiliary fuel
gas stream as well as from all other re-
finery fuel gas streams.
To ensure that this auxiliary fuel
gas stream fired in waste-heat boilers
is not exempt, the definition of fuel
gas combustion device is revised to
eliminate the exemption for inciner-
ator-waste heat boilers. In addition,
the definition of fuel gas is revised to
exempt those gas streams generated
by catalyst regeneration in catalytic
cracking units, and by coke burning in
fluid coking units from consideration
as refinery fuel gas. This will accom-
plish the original intent of exempting
only those gas streams generated by
catalyst regeneration or coke burning
from compliance with the standard
limiting sulfur dioxide emissions from
fuel gas combustion.
MISCELLANEOUS: The Administra-
tor finds that good cause exists for
omitting prior notice and public com-
ment on these amendments and for
making them immediately effective
because they simply clarify the exist-
ing regulations and impose no addi-
tional substantive requirements.
Dated: February 28, 1979.
DOUGLAS M. COSTLE,
Administrator.

Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amend-
ed as follows:
1. Section 60.101 is amended by re-
vising paragraphs (d) and (g) as fol-
lows:

§ 60.101 Definitions.
(d) "Fuel gas" means natural gas or
any gas generated by a petroleum re-
finery process unit which is combusted
separately or in any combination. Fuel
gas does not include gases generated
by catalytic cracking unit catalyst re-
generators and fluid coking unit coke
burners.
(g) "Fuel gas combustion device"
means any equipment, such as process
heaters, boilers, and flares used to
combust fuel gas, except facilities in
which gases are combusted to produce
sulfur or sulfuric acid.
(Sec. 111. 301(a>, Clean Air Act as amended
(42 U.S.C. 7411, 7601(a»)
[PR Doc. 79-7428 Filed 3-9-79; 8:45 am]
FEDERAL REGISTER, VOL 44, NO. 49—MONDAY, MARCH 12, 1979
IV-283
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Federal Register / Vol. 44, No. 77 / Thursday, April 19. 1979 / Rules and Regulations
97

40 CFR Part 60

Standards of Performance for New
Stationary Sources; Delegation of
Authority to Washington Local Agency

AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final Rulemaking.

SUMMARY: This rulemaking announces
EPA's concurrence with the State of
Washington Department of Ecology's
(DOE) sub-delegation of the
enforcement of the New Source
Performance Standards (NSPS) program
for asphalt batch plants to the Olympic
Air Pollution Control Authority
(OAPCA) and revises 40 CFR Part 60
accordingly. Concurrence was requested
by the State on February 27,1979.
EFFECTIVE DATE: April 19. 1979.
ADDRESS:
Environmental Protection Agency,
Region X M/S 629,1200 Sixth Avenue.
Seattle, WA 98101.
State of Washington, Department of
Ecology, Olympia, WA 98504.
Olympic Air Pollution Control Authority..
120 East State Avenue, Olympia, WA
98501.
Environmental Protection Agency,
Public Information Reference Unit,
Room 2922, 401 M Street SW.,
Washington, D.C. 20640.
FOR FURTHER INFORMATION CONTACT:
Clark L. Gaulding, Chief, Air Programs
Branch M/S 629, Environmental
Protection Agency, 1200 Sixth Avenue,
Seattle, WA 98101, Telephone No. (206)
442-1230 FTS 399-1230.
SUPPLEMENTARY INFORMATION: Pursuant
to Section lll(c) of the Clean Air Act (42
USC 7411(c)). on February 27,1979, the
Washington State Department of
Ecology requested that EPA concur with
the State's sub-delegation of the NSPS
program for asphalt batch plants to the
Olympic Air Pollution Control Authority.
After reviewing the State's request, the
Regional Administrator has determined
that the sub-delegation meets all
requirements outlined in EPA's original
February 28,1975 delegation of
authority, which was announced in the
Federal Register on April 1,1975 (40 FR
14632).
Therefore, on March 20,1979, the
Regional Administrator concurred in the
sub-delegation of authority to the
Olympic Air Pollution Control Authority
with the understanding that all
conditions placed on the original
delegation to the State shall apply to the
sub-delegation. By this rulemaking EPA
is amending 40 CFR 60.4 (WW) to reflect
the sub-delegation described above.
The amended § 60.4 provides that all
reports, requests, applications and
communications relating to asphalt
batch plants within the jurisdiction of
Olympic Air Pollution Control Authority
(Clallam, Grays Harbor, Jefferson,
Mason, Pacific and Thurston Counties)
will now be sent to that Agency rather
than the Department of Ecology. The
amended section is set forth below.
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective
immediately in that it is an
administrative change and not one of
substantive content. No additional
substantive burdens are imposed on the
parties affected.
This rulemaking is effective
immediately, and is issued under the
authority of Section lll(c) of the Clean
Air Act, as amended. (42 U.S.C. 7411(c)).
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In | 60.4, paragraph (b) is amended
by revising subparagraph (WW) as
follows:
*
§ 60.4 Address.
« * * * *

(b) * ' * -
(WW) * * *
(vi) Olympic Air Pollution Control
Authority, 120 East State Avenue,
Olympia. WA 98501.
Dated: April 13,1979.
DougU) M. Coitle.
Administrator.
[FRL 1202-6|
[FR Doc. 7&-12211 Filed 4-1B-7& 8:45 am]
BILLING CODE 6MO-01-M
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Federal Register / Vol. 44, No. 113 / Monday. June 11, 1979 / Rules and Regulations
98

40 CFR Part 60

[FRL1240-7]

New Stationary Sources Performance
Standards; Electric Utility Steam
Generating Units

AGENCY: Environmental Protection
Agency (EPA).

ACTION: Final rule.

SUMMARY: These standards of
performance limit emissions of sulfur
dioxide (SO,), participate matter, and
nitrogen oxides (NO,) from new,
modified, and reconstructed electric
utility steam generating units capable of
combusting more than 73 megawatts
(MW) heat input (250 million Btu/hour)
of fossil fuel. A new reference method
for determining continuous compliance
with SO, and NO, standards is also
established. The Clean Air Act
Amendments of 1977 require EPA to
revise the current standards of
performance for fossil-fuel-fired
stationary sources. The intended effect
of this regulation is to require new,
modified, and reconstructed electric
utility steam generating units to use the
best demonstrated technological system
of continuous emission reduction and to
satisfy the requirements of the Clean Air
Act Amendments of 1977.
DATES: The effective date of this
regulation is June 11,1979.
ADDRESSES: A Background Information
Document (BID; EPA 450/3-79-021) has
been prepared for the final standard.
Copies of the BID may be obtained from
the U.S. EPA Library (MD-35), Research
Triangle Park, N.C. 27711, telephone
919-541-2777. In addition, a copy is
available for inspection in the Office of
Public Affairs in each Regional Office,
and in EPA's Central Docket Section in
Washington, D.C. The BID contains (1) a
summary of ah the public comments
made on the proposed regulation; (2) a
summary of the data EPA has obtained
since proposal on SO* paniculate
matter, and NO, emissions; and (3) the
final Environmental Impact Statement
which summarizes the impacts of the
regulation.
Docket No. OAQPS-78-1 containing
all supporting information used by EPA
in developing the standards is available
for public inspection and copying
between 8 a.m. and 4 p.m., ge
alljnO.OOSMonday through Friday, at
EPA's Central Docket Section, room
2903B, Waterside Mall, 401 M Street,
SW., Washington, D.C. 20460.
The docket is an organized and
complete file of all the information
submitted to or otherwise considered by
the Administrator in the development of
this rulemaking. The docketing system is
intended to allow members of the public
and industries involved to readily
identify and locate documents so that
they can intelligently and effectively
participate in the rulemaking process.
Along with the statement of basis and
purpose of the promulgated rule and
EPA responses to significant comments,
the contents of the docket will serve as
the record in case of judicial review
[section 107(d)(a)]. —
FOR FURTHER INFORMATION CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13). Environmental Protection
Agency, Research Triangle Park, N.C.
27711, telephone 919-541-5271.
SUPPLEMENTARY INFORMATION: This
preamble contains a detailed discussion
of this rulemaking under the following
headings: SUMMARY OF STANDARDS.
RATIONALE, BACKGROUND.
APPLICABILITY, COMMENTS ON
PROPOSAL, REGULATORY
ANALYSIS, PERFORMANCE TESTING,
MISCELLANEOUS.

Summary of Standards
Applicability

The standards apply to electric utility
steam generating units capable of firing
more than 73 MW (250 million Btu/hour)
heat input of fossil fuel, for which
construction is commenced after
September 18,1978. Industrial
cogeneration facilities that sell less than
25 MW of electricity, or less than one-
third of their potential electrical output
capacity, are not covered. For electric
utility combined cycle gas turbines,
applicability of the standards is
determined on the basis of the fossil-fuel
fired to the steam generator exclusive of
the heat input and electrical power
contribution of the gas turbine.
SO» Standards

The SO, standards are as follows:
(1) Solid and solid-derived fuels
(except solid solvent refined coal): SO»
emissions to the atmosphere are limited
to 520 ng/J (1.20 Ib/million Btu) heat
input, and a 90 percent reduction in
potential SO, emissions is required at all
times except when emissions to the
atmosphere are less than 260 ng/J (0.60
Ib/million Btu) heat input. When SOt
emissions are less than 260 mg/J (0.60
Ib/million Btu) heat input, a 70 percent
reduction in potential emissions is
required. Compliance with the emission
limit and percent reduction requirements
is determined on a continuous basis by
using continuous monitors to obtain a
30-day rolling average. The percent
reduction is computed on the basis of
overall SO, removed by all types of SO*
and sulfur removal technology, including
flue gas desulfurization (FGD) systems
and fuel pretreatment systems (such as
coal cleaning, coal gasification, and coal
liquefaction). Sulfur removed by a coal
pulverizer or in bottom ash and fly ash
may be included in the computation.
(2) Gaseous and liquid fuels not
derived from solid fuels: SO* emissions
into the atmosphere are limited to 340
ng/J (0.80 Ib/million Btu) heat input, and
a 90 percent reduction in potential SO,
emissions is required. The percent
reduction requirement does not apply if
SO, emissions into the atmosphere are
less than 86 ng/J (0.20 Ib/million Btu)
heat input. Compliance with the SO,
emission limitation and percent
reduction is determined on a continuous
basis by using continuous monitors to
obtain a 30-day rolling average.
(3) Anthracite coal: Electric utility
steam generating units firing anthracite
coal alone are exempt from the
percentage reduction requirement of the
SO, standard but are subject to the 520
ng/J (1.20 Ib/million Btu) heat input
emission limit on a 30-day rolling
average, and all other provisions of the
regulations including the particulate
matter and NO, standards.
(4)-Noncontinental areas: Electric
utility steam generating units located in
noncontinental areas (State of Hawaii,
the Virgin Islands, Guam, American
Samoa, the Commonwealth of Puerto
Rico, and the Northern Mariana Islands)
are exempt from the percentage
reduction requirement of the SOi
standard but are subject to the
applicable SO, emission limitation and
all other provisions of the regulations
including the particulate matter and NO,
standards.
(5) Resource recovery facilities:
Resource recovery facilities that fire less
than 25 percent fossil-fuel on a quarterly
(90-day) heat input basis are not subject
to the percentage reduction
requirements but are subject to the 520
ng/J (1.20 Ib/million Btu) heat input
emission limit. Compliance with the
emission limit is determined on a
continuous basis using continuous
monitoring to obtain a 30-day rolling
average. In addition, such facilities must
monitor and report their heat input by
fuel type.
(6) Solid solvent refined coal: Electric
utility steam generating units firing solid
solvent refined coal (SRC I] are subject
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Federal Register / Vol. 44. No. 113 / Monday. June 11. 1979 / Rules and Regulations
to the 520 ng/J (1.20 Ib/million Btu) heat
input emission limit (30-day rolling
average) and all requirements under the
NO, and particulate matter standards.
Compliance with the emission limit is
determined on a continuous basis using
• continuous monitor to obtain a 30-day
rolling average. The percentage
reduction requirement for SRC I, which
ii to be obtained at the refining facility
itself, is 65 percent reduction in potential
SOt emissions on.a 24-hour (daily)
averaging basis. Compliance is to be
determined by Method 19. Initial full
scale demonstration facilities may be
granted a commercial demonstration
permit establishing a requirement of 80
percent reduction in potential emissions
on a 24-hour (daily) basis.
Paniculate Matter Standards
The particulate matter standard limits
emissions to 13 ng/J (0.03 Ib/million Btu)
heat input. The opacity standard limits
the opacity of emission to 20 percent (6-
minute average). The standards are
based on the performance of a well-
designed and operated baghouse or
electostatic precipitator (ESP).

NO* Standards
The NO, standards are based on
combustion modification and vary
according to the fuel type. The
standards are:
(1) 86 ng/J (0.20 Ib/million Btu) heat
input from the combustion of any
gaseous fuel, except gaseous fuel
derived from coal;
(2) 130 ng/I (0.30 Ib/million Btu] heat
input from the combustion of any liquid
fuel, except shale oil and liquid fuel
derived from coal;
(3) 210 ng/I (0.50 Ib/million Btu) heat
input from the combustion of
subbituminous coal, shale oil, or any
solid, liquid, or gaseous fuel derived
from coal;
(4) 340 ng/I (0.80 Ib/million Btu) heat
input from the combustion in a slag tap
furnace of any fuel containing more than
25 percent, by weight, lignite which has
been mined in North Dakota, South
Dakota, or Montana;
(5) Combustion of a fuel containing
more than 25 percent, by weight, coal
refuse is exempt from the NO, standards
and monitoring requirements; and
(6) 260 ng/I (0.60 Ib/million Btu) heat
input from the combustion of any solid
fuel not specified under (3), (4), or (5).
Continuous compliance with the NO,
standards is required, based on a 30-day
rolling average. Also, percent reductions
in uncontrolled NO, emission levels are
required. The percent reductions are not
controlling, however, and compliance
With the NO, emission limits will assure
compliance with the percent reduction
requirements.

Emerging Technologies

The standards include provisions
which allow the Administrator to grant
commercial demonstration permits to
allow less stringent requirements for the
initial full-scale demonstration plants of
certain technologies. The standards
include the following provisions:
(1) Facilities using SRC I would be
subject to an emission limitation of 520
ng/j (1.20 Ib/million Btu) heat input
based on a 30-day rolling average, and
an emission reduction requirement of 85
percent, based on a 24-hour average.
However, the percentage reduction
allowed under a commercial
demonstration permit for the initial full-
scale demonstration plants, using SRC I
would be 80 percent [based on a 24-hour
average). The plant producing the SRC I
would monitor to insure that the
required percentage reduction (24-hour
average) is achieved and the power
plant using the SRC I would monitor to
insure that the 520 ng/I heat input limit
(30-day rolling average) is achieved.
(2) Facilities using fluidized bed
combustion (FBC) or coal liquefaction
would be subject to the emission
limitation and percentage reduction
requirement of the SO9 standard and to
the particulate matter and NO,
standards. However, the reduction in
potential SOi emissions allowed under a
commercial demonstration permit for
the initial full-scale demonstration
plants using FBC would be 85 percent
(based on a 30-day rolling average). The
NO, emission limitation allowed under a
commercial demonstration permit for
the initial full-scale demonstration
plants using coal liquefaction would be
300 ng/I (0.70 Ib/million Btu) heat input,
based on a 30-day rolling average.
(3) No more than 15,000 MW
equivalent electrical capacity would be
allotted for the purpose of commercial
demonstration permits. The capacity
will be allocated as follows:
Equivalent
Technology 'Pollutant electrical capacity
MW
Solid solvent-refined coal
Fluidized bed combustion
(atmospheric)
Fluidized bed oombutflon
(pressurized)
Coal liquefaction .
SO. .

SO,

SO.
NO.
6.000-10.000

400-3.000

200-1.200
750-10.000
Compliance Provisions

Continuous compliance with the SO,
and NO, standards is required and is to
be determined with continuous emission
monitors. Reference methods or other
approved procedures must be used to
supplement the emission data when the
continuous emission monitors
malfunction, to provide emissions data
for at least 18 hours of each day for at
least 22 days out of any 30 successive
days of boiler operation.
A malfunctioning FGD system may be
Bypassed under emergency conditions.
Compliance with the particulate
standard is determined through
performance tests.-Continuous monitors
are required to measure and record the
opacity of emissions. This data is to be
used to identify excess emissions to
insure that the particulate matter control
system is being properly operated and
maintained.

Rationale '•
SO, Standards

Under section lll(a) of the Act, a
standard of performance for a fossil-
fuel-fired stationary source must reflect
the degree of emission limitation and
percentage reduction achievable through
the application of the best technological
system of continuous emission reduction
taking into consideration cost and any
nonair quality health and environmental
impacts and energy requirements. In
addition, credit may be given for any
cleaning of the fuel, or reduction in
pollutant characteristics of the fuel, after
mining and prior to combustion.
fai the 1977 amendments to the Clean
Air Act, Congress was severely critical
of the current standard of performance
for power plants, and especially of the
fact that it could be met by the use of
untreated low-sulfur coal. The House, in
particular, felt that the current standard
failed to meet six of the purposes of
section 111. The six purposes are (H.
Rept. at 184-186):
1. The standards must not give a
competitive advantage to one State over
another in attracting industry.
2. The standards must maximize the
potential for long-term economic growth
by reducing emissions as much as
practicable. This would increase the
amount of industrial growth possible
within the limits set by the air quality
standards.
3. The standards must to the extent
practical force the installation of all the
control technology that will ever be
necessary on new plants at the time of
construction when it is cheaper to
. install, thereby minimizing the need for
retrofit in the future when air quality
standards begin to set limits to growth.
4 and 5. The standards to the extent
practical must force new sources to burn
high-sulfur fuel thus freeing low-sulfur
fuel for use in existing sources where it
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it harder to control emissions and where
low-sulfur fuel is needed for compliance.
This will (1) allow old sources to
operate longer and (2) expand
environmentally acceptable energy
supplies.
6. The standards should be stringent
in order to force the development of
improved technology.
To deal with these perceived
deficiences, the House initiated
revisions to section 111 as follows:
1. New source performance standards
must be based on the "best
technological" control system that has
been "adequately demonstrated," taking
cost and other factors such as energy
into account. The insertion of the word
"technological" precludes a new source
performance standard based solely on
the use of low-sulfur fuels.
2. New source performance standards
for fossil-fuel-fired sources (e.g., power
plants) must require a "percentage
reduction" in emissions, compared to
the emissions that would result from
burning untreated fuels.
The Conference Committee generally
followed the House bill. As a result, the
1977 amendments substantially changed
the criteria for regulating new power
plants by requiring the application of
technological methods of control to
minimize SOa emissions and to
maximize the use of locally available
coals. Under the statute, these goals are
to be achieved through revision of the
standards of performance for new fossil-
fuel-fired stationary sources to specify
(1) an emission limitation and (2) a
percentage reduction requirement.
According to legislative history
accompanying the amendments, the
percentage reduction requirement
should be applied uniformly on a
nationwide basis, unless the
Administrator finds that varying
requirements applied to fuels of differing
characteristics will not undermine the
objectives of the house bill and other
Act provisions.
The principal issue throughout this
rulemaking has been whether a plant
burning low-sulfur coal should be
required to achieve the same percentage
reduction in potential SO« emissions as
those burning higher sulfur coal. The
public comments on the proposed rules
and subsequent analyses performed by
the Office of Air, Noise and Radiation of
EPA served to bring into focus several
other issues as well.
These issues included performance
capabilities of SO, control technology,
the averaging period for determining
compliance, and the potential adverse
impact of the emission ceiling on high-
sulfur coal reserves.
Prior to framing the final SO.
standards, the EPA staff carried out
extensive analyses of a range of
alternative SO, standards using an
econometric model of the utility sector.
As part of this effort, a joint working
group comprised of representatives from
EPA, the Department of Energy, the
Council of Economic Advisors, the
Council on Wage and Price Stability,
and others reviewed the underlying
assumptions used in the model. The
results of these analyses served to
identify environmental, economic, and
energy impacts associated with each of
the alternatives considered at the
national and regional levels. In addition,
supplemental analyses were performed
to assess impacts of alternative
emissiorrceilings on specific coal
reserves, to verify performance
characteristics of alternative SO,
scrubbing technologies, and to assess
the sulfur reduction potential of coal
preparation techniques.
Based on the public record and
additional analyses performed, the
Administrator concluded that a 90
percent reduction in potential SO,
emissions (30-day rolling average) has
been adequately demonstrated for high-
sulfur coals. This level can be achieved
at the individual plant level even under
the most demanding conditions through
the application of flue gas
desulfurization (FGD) systems together
with sulfur reductions achieved by
currently practiced coal preparation
techniques. Reductions achieved in the
fly ash and bottom ash are also
applicable. In reaching this finding, the
Administrator considered the
performance of currently operating FGD
systems (scrubbers) and found that
performance could be upgraded to
achieve the recommended level with
better design, maintenance, and
operating practices. A more stringent
requirement based on the levels of
scrubber performance specified for
lower sulfur coals in a number of
prevention of significant deterioration
permits was not adopted since
experience with scrubbers operating
with such performance levels on high-
sulfur coals is limited. In selecting a 30-
day rolling average as the basis for
determining compliance, the
Administrator took into consideration
effects of coal sulfur variability on
scrubber performance as well as
potential adverse impacts that a shorter
averaging period may have on the
ability of small plants to comply.
With respect to lower sulfur coals, the
EPA staff examined whether a uniform
or variable application of the percent
reduction requirement would best
satisfy the statutory requirements of
section 111 of the Act and the supporting
legislative history. The Conference
Report for the Clean Air Act
Amendments of 1977 says in the
pertinent part:
In establishing a national percent reduction
(or new fossil fuel-fired sources, the
conferees agreed that the Administrator may,
in his discretion, set a range of pollutant
reduction that reflects varying fuel
characteristics. Any departure from the
uniform national percentage reduction
requirement, however, must be accompanied
by a finding that such a departure does not
undermine the basic purposes of the House
provision and other provisions of the act,
such as maximizing the use of locally
available fuels.

In the face of such language, it is clear
that Congress established a presumption
in favor of a uniform application of the
percentage reduction requirement and
that any-departure would require careful
analysis of objectives set forth in the
House bill and the Conference Report.
This question was made more
complex by the emergence of dry SO,
control systems.. As a result of public
comments on the discussion of dry SO,
control technology in the proposal, the
EPA staff examined the potential of this
technology in greater detail. It was
found that the development of dry SO.
controls has progressed rapidly during
the past 12 months. Three full scale
systems are being installed on utility
boilers with scheduled start up in the
1981-1982 period. These already
contracted systems have design
efficiencies ranging from 50 to 85
percent SO» removal, long term average.
In addition, it was determined that bids
are currently being sought for five more
dry control systems (70 to 90 percent
reduction range) for utility applications.
Activity in the dry SO» control field is
being stimulated by several factors.
First, dry control systems are less
complex than wet technology. These
simplified designsjoffer the prospect of
greater reliability at substantially lower
costs than their wet counterparts.
Second, dry systems use less water than
wet scrubbers, which is an important
consideration in the Western part of the
United States. Third, the amount of
energy required to operate dry systems
is less than that required for wet
systems. Finally, the resulting waste
product is more easily disposed of than
wet sludge.
The applicability of dry control
technology, however, appears limited to
low-sulfur coals. At coal sulfur contents
greater than about 1290 ng/J (3 pounds
SOi/million Btu), or about 1.5 percent
sulfur coal, available data indicate that
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it probably will be more economical to
employ a wet scrubber than a dry
control system.
Faced with these findings, the
Administrator had to determine what
effect the structure of the final
regulation would have on the continuing
development and application of this
technology. A thorough engineering
review of the available data indicated
that a requirement of 90 percent
reduction in potential SOS emissions
would be likely to constrain the full
development of this technology by
limiting its potential applicability to high
alkaline content, low-sulfur coals. For
non-alkaline, low-sulfur coals, the
certainty of economically achieving a 90
percent reduction level is markedly
reduced. In the face of this finding, it
would be unlikely that the technology
would be vigorously pursued for these
low alkaline fuels which comprise
approximately one half of the Nation's
low-sulfur coal reserves. In view of this,
the Administrator sought a percentage
reduction requirement that would
provide an opportunity for dry SOf
technology to be developed for all low-
sulfur coal reserves and yet would be
sufficiently stringent to assure that the
technology was developed to its fullest
potential. The Administrator concluded
that a variable control approach with a
minimum requirement of 70 percent
reduction potential in SO» emissions (30-
day rolling average) for low-sulfur coals
would fulfill this objective. This will be
discussed in more detail later in the
preamble. Less stringent, sliding scale
requirements such as those offered by
the utility industry and the Department
of Energy were rejected since they
would have higher associated emissions,
would not be significantly less costly,
and would not serve to encourage
development of this technology.
In addition to promoting the
development of dry SO> systems, a
variable approach offers several other
advantages often cited by the utility
industry. For example, if a source chose
to employ wet technology, a 70 percent
reduction requirement serves to
substantially reduce the energy impact
of operating wet scrubbers in low-sulfur
coals. At this level of wet scrubber
control, a portion of the untested flue
gas could be used for plume reheat so as
to increase plume buoyancy, thus
reducing if not eliminating the need to
expend energy for flue gas reheat.
Further, by establishing a range of
percent reductions, a variable approach
would allow a source some flexibility
particularly when selecting intermediate
sulfur content coals. Finally, under a
variable approach, a source could move
to a lower sulfur content coal to achieve
compliance if its control equipment
failed to meet design expectations.
While these points alone would not be
sufficient to warrant adoption of a
variable standard, they do serve to
supplement the benefits associated with
permitting the use of dry technology.
Regarding the maximum emission
limitation, the Administrator had to
determine a level that was appropriate
when a 90 percent reduction in potential
emissions was applied to high-sulfur
coals. Toward this end, detailed
assessments of the potential impacts of
a wide range of emission limitations on
high-sulfur coal reserves were
performed. The results revealed that a
significant portion (up to 30 percent) of
the high-sulfur coal reserves in the East,
Midwest and portions of the Northern
Appalachia coal regions would require
more than a 90 percent reduction if the
emission limitation were established
below 520 ng/J (1.2 Ib/million Btu) heat
input on a 30-day rolling average basis.
Although higher levels of control are
technically feasible, conservatism in
utility perceptions of scrubber
performance could create a significant
disincentive against the use of these
coals and disrupt the coal markets in
these regions. Accordingly, the
Administrator concluded the emission
limitation should be maintained at 520
ng/J (1.2 Ib/million Btu) heat input on a
30-day rolling average basis. A more
stringent emission limit would be
counter to one of the purposes of the
1977 Amendments, that is, encouraging
the use of higher sulfur coals.
Having determined an appropriate
emission limitation and that a variable
percent reduction requirement should be
established, the Administrator directed
his attention to specifying the final form
of the standard. In doing so, he sought to
achieve the best balance in control
requirements. This was accomplished by
specifying a 520 ng/J (1.2 Ib/million Btu]
heat input emission limitation with a 90
percent reduction in potential SO,
emissions except when emissions to the
atmosphere were reduced below 260 ng/
I (0.6 Ib/million Btu) heat input (30-day
rolling average), when only a 70 percent
reduction in potential SO, emissions
would apply. Compliance with each of
the requirements would be determined
on the basis of a 30-day rolling average.
Under this approach, plants firing high-
sulfur coals would be required to
achieve a 90 percent reduction in
potential emissions in order to comply
with the emission limitation. Those
using intermediate- or low-sulfur content
coals would be permitted to achieve
between 70 and 90 percent reduction,
provided their emissions were less than
260 ng/J (0.6 Ib/million Btu). The 260 ng/
] (0.6 Ib/million Btu) level was selected
to provide for a smooth transition of the
percentage reduction requirement from
high- to low-sulfur coals. Other
transition points were examined but not
adopted since they tended to place
certain types of coal at a disadvantage.
By fashioning the SO, standard in this
manner, the Administrator believes he
has satisfied both the statutory language
of section 111 and the pertinent part of
the Conference Report. The standard
reflects a balance in environmental,
economic, and energy considerations by
being sufficiently stringent to bring
about substantial reductions in SO,
emissions (3 million tons in 1995) yet
does so at reasonable costs without
significant energy penalties. When
compared to a uniform 90 percent
reduction, the standard achieves the
same emission reductions at the
national level. More importantly, by
providing an opportunity for full
development of dry SO, technology the
standard offers potential for further
emission reductions (100 to 200
thousand tons per year], cost savings
(over $1 billion per year), and a
reduction in oil consumption (200
thousand barrels per day) when
compared to a uniform standard. The
standard through its balance and
recognition of varying coal
characteristics, serves to expand
environmentally acceptable energy
supplies without conveying a
competitive advantage to any one coal
producing region. The maintenance of
the emission limitation at 520 ng/J (1.2 Ib
SOi/million Btu) will serve to encourage
the use of locally available high-sulfur
coals. By providing for a range of
percent reductions, the standard offers
flexibility in regard to burning of
intermediate sulfur content coals. By
placing a minimum requirement of 70
percent on low-sulfur coals, the final
rule encourages the full development
and application of dry SO, control
systems on a range of coals. At the same
time, the minimum requirement is
sufficiently stringent to reduce the
amount of low-sulfur coal that moves
eastward when compared to the current
standard. Admittedly, a uniform 90
percent requirement would reduce such
movements further, but in the
Administrator's opinion, such gains
would be of marginal value when
compared to expected increases in high-
sulfur coal production. By achieving a
balanced coal demand within the utility
sector and by promoting the
development of less expensive SO,
control technology, the final standard
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will expamd eta^itvanmemtaiUy acceptable
energy supplies to existing power plants
and industrial oouroso.
emicoiono, 4&e standard will enhance the
potential fo? long term economic growth
at both the national and regional levels.
While more rssteicti'ife requirements
may have resulted m marginal air
quality improvements locally, their
higher costs may well feave served to
retard rather them promote ah* quality
improvement nationally by delaying the
retirement of older, pooriy controlled
plants.
The standard must also b$ viewed
within the broad context of 4he Qean
Air Act Amendments of 51977. It serves
as a minimum irequirement for both
prevention of significant deterioration
and non-attainment considerations.
When warranted by local conditions.
ample authority exists to impose more
restrictive requirements through the
case-by-case new oonrc® review
process. When exercised in conjunction!
with the stemdard, these authorities will
assure that our pristine areas and
national parks are adequately protected.
Similarly, in those areas where the
attainment and maintenance of the
- ambient air quality standard is
threatened, more restrictive
requirements will be imposed.
The standard limits SOn emissions
from facilities firing gaseous or liquid
fuels to 340 ng/J (0.80 Ib/million Btu)
heat input and requires SO percent
reduction in potential emissions on a 30-
day rolling average basis. The percent
reduction does not apply when
emissions are less than 68 ng/J (0.20 lb/
million Btu) heat input on a 30-day
rolling average basis. This reflects a
change to the proposed standards in
that the time for compliance is changed
from the proposed 24-hour basis to a 30-
day rolling average. This change is
necessary to make the compliance times
consistent for all fuels. Enforcement of
the standards would be complicated by
different averaging times, particularly
when more than one fuel is used.

Particulate Matter Standard

The standard for particulate matter
limits the emissions to 13 ng/J {0.03 lb/
million Btu) heat input and requires a 99
percent reduction in uncontrolled
emissions for solid fuels and a 70
percent reduction for liquid ruels. No
particulate matter control is necessary
for units firing gaseous fuels alone, and
a percent reduction is not required. The
percent reduction requirements for solid
and liquid fuels are not controlling, and
compliance with fee particulate matter
emission limit will assure compliance
with the percent reduction requirements.
A 20 percent (6-minute average)
opacity limit ie included in this
standard. The opacity limit is included
to insure proper operation and
maintenance of the emission control
system. If an affected facility were to
comply with all applicable standards
except opacity, the owner or operator ,
may request that the Administrator,
under 40 CFR 6Q.ll(
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Federal Register / Vol. 44, No. 113 / Monday, June 11, 1979 / Rules and Regulations
baghouses have an advantage for low-
sulfur coal applications and ESP's have
an advantage for high-sulfur coal
applications. Available data indicate
that for low-sulfur coals, ESP's (hot-side
or cold-side) require a large collection
area and thus ESP control system costs
will be higher than baghouse control
system costs. For high-sulfur coals, large
collection areas are not required for
ESP's, and ESP control systems offer
cost savings over baghouse control
systems.
Baghouses have not traditionally been
used at utility power plants. At the time
these regulations were proposed, the
largest baghouse-controlled coal-fired
steam generator for which EPA had
particulate matter emission test data
had an electrical output of 44 MW.
Several larger baghouse installations
were under construction and two larger
units were initiating operation. Since the
date of proposal of these standards, EPA
has tested one of the new units. It has
an electrical output capacity of 350 MW
and is fired with pulverized,
subbituminous coal containing 0.3
percent sulfur. The baghouse control
system for this facility is designed to
achieve a 43 Ng/J (0.01 Ib/million Btu)
heat input emission limit. This unit has
achieved emission levels below 13 Ng/J
(0.03 Ib/million Btu) heat input. The
baghouse control system was designed
with an air-to-cloth ratio of 1.0 actual
cubic meter per minute per square meter
(3.32 ACFM/ft2) and a pressure drop of
1.25 kilopascals (5 in. H2O). Although
some operating problems have been
encountered, the unit is being operated
within its design emission limit and the
level of the standard. During the testing
the power plant operated in excess of
300 MW electrical output. Work is
continuing on the control system to
improve its performance. Regardless of
type, large emission control systems
generally require a period of time for the
establishment of cleaning, maintenance,
and operational procedures that are best
suited for the particular application.
Baghouses are designed and
constructed in modules rather than as
one large unit. The baghouse control
system for the new 350 MW power plant
has 28 baghouse modules, each of which
services 12.5 MW of generating
capacity. As of May 1979, at least 26
baghouse-equipped coal-fired utility
steam generators were operating, and an
additional 28 utility units are planned to
start operation by the end of 1982. About
two-thirds of the 30 planned baghouse-
controlled power generation systems
will have an electrical output capacity
greater than 150 MW, and more than .
one-third of these power plants will be
fired with coal containing more than 3
percent sulfur. The Administrator has
concluded that baghouse control
systems have been adequately
demonstrated for full-sized utility
application. .
Scrubbers
EPA collected emission test data from
seven coal-fired steam generators
controlled by wet particulate matter
scrubbers. Emissions from five of the
seven scrubber-equipped power plants
were less than 21 Ng/J (0.05 Ib/million
Btu) heat input. Only one of the seven
units had emission test results less than
13 Ng/J (0.03 Ib/million Btu) heat input.
Scrubber pressure drop can be
increased to improve scrubber
particulate matter removal efficiencies;
however, because of cost and energy
considerafionsTthe Administrator
believes that wet particulate matter
scrubbers will only be used in special
situations and generally will not be
selected to comply with the standards.
Performance Testing
When the standards were proposed,
the Administrator recognized that there
is a potential for both FCD sulfate
carryover and sulfuric acid mist to affect
particulate matter performance testing
downstream of an FGD system. Data
available at the time of proposal
indicated that overall particulate matter
emissions, including sulfate carryover,
are not increased by a properly
designed, constructed, maintained, arid
operated FGD system. No additional
information has been received to alter
this finding.
The data available at proposal
indicated that sulfuric acid mist (H3SO4)
interaction with Methods 5 or 17 would
not be a problem when firing low-sulfur
coal, but may be a problem when firing
high-sulfur coals. Limited data obtained
since proposal indicate that when high-
sulfur coal is being fired, there is a
potential for sulfuric acid mist to form
after an FGD system and to introduce
errors in the performance testing results
when Methods 5 or 17 are used. EPA has
obtained particulate matter emission
test data from two power plants that
were fired with coals having more than
3 percent sulfur and that were equipped
with both an ESP and FGD system. The
particulate matter test data collected
after the FGD system were not
conclusive in assessing the acid mist
problem. The first facility tested
appeared to experience a problem with
acid mist interaction. The second facility
did not appear to experience a problem
with acid mist, and emissions after the
ESP/FGD system were less than 13 ng/J
(0.03 Ib/million Btu) heat input. The tests
at both facilities were conducted using
Method 5, but different methods were
used for measuring the filter
temperature. EPA has initiated a review
of Methods 5 and 17 to determine what
* modifications may be necessary to
avoid acid mist interaction problems.
Until these studies are completed the
Administrator is approving as an
optional test procedure the use of
Method 5 (or 17) for performance testing
before FGD systems. Performance
testing is discussed in more detail in the
PERFORMANCE TESTING section of
this preamble.
The particulate matter emission limit
and opacity limit apply at all times,
except during periods of startup,
shutdown, or malfunction. Compliance
with the particulate matter emission
limit is determined through performance
tests using Methods 5 or 17. Compliance
with the opacity limit is determined by
the use of Method 9. A continuous
monitoring system to measure opacity is
required to assure proper operation and
maintenance of the emission control
system but is not used for continuous
compliance determinations. Data from
the continuous monitoring system
indicating opacity levels higher than the
standard are reported to EPA quarterly
as excess emissions and not as
violations of the opacity standard.
The environmental impacts of the
revised particulate matter standards
were estimated by using an economic
model of the coal and electric utility
industries (see discussion under
REGULATORY ANALYSIS). This
projection took into consideration the
combined effect of complying with the
revised SO,, particulate matter, and NO,
standards on the construction and
operation of both new and existing
capacity. Particulate matter emissions
from power plants were 3.0 million tons
in 1975. Under continuation of the
current standards, these emissions are
predicted to decrease to 1.4 million tons
by 1995. The primary reason for this
decrease in emissions is the assumption
that existing power plants will come
into compliance with current state
emission regulations. Under these
standards, 1995 emissions are predicted
to decrease another 400 thousand tons
(30 percent).

NO* Standards

The NO, emission standards are
based on emission levels achievable
with a properly designed and operated
boiler that incorporates combustion
modification techniques to reduce NO,
formation. The levels to which NO.
emissions can be reduced with
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Federal Register / VoL 44. No. 113 / Monday. June 11, 1979 / Rules and Regulations
combustion modification depend not
only upon boiler operating practice, but
also upon the type ol fuel burned.
Consequently, the Administrator has
developed fuel-specific NO. standards.
The standards are presented in this
preamble under Summary of Standards.
Continuous compliance with the NO.
standards is required, based on a 30-day
rolling average. Also, percent reductions
in uncontrolled NO, emission levels are
required. The percent reductions are not
controlling, however, and compliance
with the NO. emission limits will assure
compliance with the percent reduction
requirements.
One change has been made to the*
proposed NO, standards. The proposed
standards would have required
compliance to be based on a 24-hour
averaging period, whereas the final
standards require compliance to be
based on a 30-day rolling average. This
change was made because several of the
comments received, one of which
included emission data, indicated that
more flexibility in boiler operation on a
day-to-day basis is needed to
accommodate slagging and other boiler
problems that may influence NO,
emissions when coal is burned. The
averaging period for determining
compliance with the NO. limitations for
gaseous and liquid fuels has been
changed from the proposed 24-hour to a
30-day rolling average. This change is
necessary to make the compliance times'
consistent for all fuels. Enforcement of
the standards would be complicated by
different averaging times, particularly
where more than one fuel is used. More
details on the selection of the averaging
period for coal appear in this preamble
under Comments on Proposal.
The proposed standards for coal
combustion were based principally on
the results of EPA testing performed at
six electric utility boilers, all of which
are considered to represent modern
boiler designs. One of the boilers was
manufactured by the Babcock and
Wilcox Company (B&W) and was
retrofitted with low-emission burners.
Four of the boilers were Combustion
Engineering, Inc. (CE) designs originally
equipped with overfire air, and one
boiler was a CE design retrofitted with
overfire air, The six boilers burned a
variety of bituminous and
subbituminous coals. Conclusions
drawn from the EPA studies of the
boilers were that the most effective
combustion modification techniques for
reducing NO, emitted from utility
boilers are staged combustion, low
excess air, and reduced heat release
rate. Low-emission burners were also
effective in reducing NO, levels during
the EPA studies.
In developing the proposed standards
for coal, the Administrator also
considered the following: (1) data
obtained from the boiler manufacturers
on 11 CE, three B&W, and three Foster
Wheeler Energy Corporation (FW)
utility boilers; (2) the results of tests
performed twice daily over 30-day
periods at three well-controlled utility
boilers manufactured by CE; (3) a total
of six months of continuously monitored
NO, emission data from two CE boilers
located at the Colstrip plant of the
Montana Power Company, (4) plans
underway at B&W, FW, and the Riley
Stoker Corporation (RS) to develop low-
emission burners and furnace designs;
(5) correspondence from CE indicating
that it would guarantee its new boilers
to achieve, without adverse side-effects,
emission limits essentially the same as
those proposed; and (8) guarantees
made by B&W and FW that their new
boilers would achieve the State of New
Mexico's NO, emission limit of 190 ng/J
(0.45 Ib/million Btu) heat input.
Since proposal of the standards, the
following new information has become
available and has been considered by
the Administrator (1) additional data
from the boiler manufacturers on four
B&W and four RS utility boilers; (2) a
total of 18 months of continuously
monitored NO, data from the two CE
utility boilers at the Colstrip plant; (3)
approximately 10 months of
continuously monitored NO, data from
five other CE boilers; (4) recent
performance test results for a CE and a
RS utility boiler; and (5) recent
guarantees offered by CE and FW to
achieve an NO, emission limit of 190 ng/
J (0.45 Ib/million Btu] heat input in the
State of California. This and other new
information is discussed in "Electric
Utility Steam Generating Units,
Background Information for
Promulgated Emission Standards" (EPA
450/3-79-021).
The data available before and after
proposal indicate that NO, emission
levels below 210 ng/} (0.50 Ib/million
Btu) heat input are achievable with a
variety of coals burned in boilers made
by all four of the major boiler
manufacturers. Lower emission levels
are theoretically achievable with
catalytic ammonia injection, as noted by
several commenters. However, these
systems have not been adequately
demonstrated at this time on full-size
electric utility boilers that burn coal.
Continuously monitored NO, emission
data from coal-fired CE boilers indicate
that emission variability during day-to-
day operation is such that low NO,
levels can be maintained if emissions
are averaged over 30-day periods.
Although the Administrator has not
been able to obtain continuously
monitored data from boilers made by
the other boiler manufacturers, the
Administrator believes that the emission
variability exhibited by CE boilers over
long periods of time is also
characteristic of B&W, FW, and RS
boilers. This is because the
Administrator expects B&W, FW, and
RS boilers to experience operational
conditions which are similar to CE
boilers (e.g., slagging, variations in fuel
quality, and load reductions] when
burning similar fuel. Thus, the
Administrator believes the 30-day
averaging time is appropriate for coal-
fired boilers made by all four
manufacturers.'
Prior to proposal of the standards
several electric utilities and boiler
manufacturers expressed concern over
the potential for accelerated boiler tube
wastage (i.e., corrosion) during low-NO,
operation of a coal-fired boiler. The
severity of tube wastage is believed to
vary with several factors, but especially
with the sulfur content of the coal
burned. For example, the combustion of
high-sulfur bituminous coal appears to
aggravate tube wastage, particularly if it
is burned in a reducing atmosphere. A
reducing atmosphere is sometimes
associated with low-NO, operation.
The EPA studies of one B&W and five
CE utility boilers concluded that tube
wastage rates did not significantly
increase during low-NO, operation. The
significance of these results is limited,
however, in that the tube wastage tests
were conducted over relatively short
periods of time (30 days or 300 hours).
Also, only CE and B&W boilers were
studied, and the B&W boiler was not a
recent design, but was an old-style unit
retrofitted with experimental low-
emission burners. Thus, some concern
still exists over potentially greater tube
wastage during low-NO, operation
when high-sulfur coals are burned. Since
bituminous coals often have high sulfur
contents, the Administrator has
established a special emission limit for
bituminous coals to reduce the potential
for increased tube wastage during low-
NO, operation.
Based on discussions with the boiler
manufacturers and on an evaluation of
all available tube wastage information.
the Administrator has established an
NO, emission limit of 260 ng/J (0.60 lb/
million Btu) heat imput for the
combustion of bituminous coal. The
Administrator believes this is a safe
level at which tube wastage will not be
accelerated 6y low-NO, operation. In
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support of foio befofc CE has stated that
it would guarantee its sew boilers, whan
equipped with overfire air, to achieve
the 280 ng/J (O.ao Ib/million Btu) heat
input limit without increased tabs
wastage rates whai Eastern bituminous
coals are bunted. 5a addition, B&W has
noted in csw^al receat technical papers
that its low-etaiaaion burners allow the
ftiFE3ce to tte maintained in on oxidizing
atmosphere, thereby reducing the
potential for tube wastage when high-
oulfur bituminous coals are burned. The
other boiler iRarvafacturers have also
developed techniques that reduce the
potential for tubs wastage during k>w-
NOtt operatiea. Although the amount of
tube waetage data available to the
Adatinistrator oo B&W. FW, and RS
boilers is very limited, it is the
Administrator's judgement that all three
of these manufacturers are capable of
designing boilers which would not
experience increased tube wastage rates
as Q resell of compliance with the NCXj
standards.
Since the potential for increased tube
wastage during low-NO,, operation
appears to be small when low-sulfur
subbituminotis coals are burned, the
Administrator has established a lower
NO* emission limit of 210 ng/J (0.50 lb/
million Btu) heat input for boilers
burning subbi luminous coal. This limit is
consistent with emission data from
boilers representing all four
manufacturers. Furthermore, CE has
stated that it would guarantee its
modern boilers to achieve an NOn limit
of 210 ng/J (0.50 Ib/million Btu) heat
input, without increased tube wastage
rates, when subbituminous coals are
burned.
The emission limits for electric utility
power plants that burn liquid and
gaseous fuels are at the same levels as
the emission limits originally
promulgated in 1971 under 40 CFR Part
60, Subpart D for large steam generators.
It was decided that a new study of
combustion modification or NOa flue-gas
treatment for oil- or gas-fired electric
utility steam generators would not be
appropriate because few, if any, of these
kinds of power plants are expected to be
built in the future.
Several studies indicate that NO,,
emissions from the combustion of fuels
derived from coal, such as liquid
solvent-refined coal (SRC II) and low-
Btu synthetic gas, may be higher than
those from petroleum oil or natural gas.
This is because coal-derived fuels have
fuel-bound nitrogen contents that
approach the levels found in coal rather
than those found in petroleum oil and
natural .gas. Based on limited emission
data from pilot-scale facilities and on
the hnor/n emission characteristics of
coal, the Administrator believes that an
achievable emission limit for solid,
liquid, and gaseous fuels derived from
coal is 210 ng/J (0.50 lb/million Btu) beat
input Tube vt/astage and otther boiler
problems are not expected to occur from
boiler operation at levels as low as 210
ng/J when firing these fuels because of
their low sulfur and ash contents.
NOn emission limits-for lignite
combustion were promulgated in 1978
(48 FR 9276) as amendments to the
original standards under 49 CFK Part 80,
Subpart D. Since no new information on
NO,, emission Fates from lignite
combustion has become available, the
emission limits have not been changed
for tfcese standards. Also, these
emission limits a?e the oame as the
proposed.
Little is known about the emission
characteristics of shale oil. However,
since shale oil typically has a higher
fuel-bound nitrogen content than
petroleum oil, it may be impossible for a
well-controlled unit burning shale oil to
achieve the NO,, emission limit for liquid
fuels. Shale oil does have a similar
nitrogen content to coal and it is
reasonable to expect that the emission
control techniques used for coal could
also be used to limit NOtt emissions from
shale oil combustion. Consequently, the
Administrator has limited NOZ
• emissions from units burning shale oil to
210 ng/J (0.50 Ib/million Btu) heat input,
the same limit applicable to.
subbituminous coal, which is the same
as proposed. There is no evidence that
tube wastage or other boiler problems
would result from operation of a boiler
at 210 ag/J when shale oil is burned.
The combustion of coal refuse was
exempted from the original steam
generator standards under 40 CFR Part
60, Subpart D because the only furnace
design believed capable of burning
certain kinds of coal refuse, the slag tap
furnace, inherently produces NO*
emissions in excess of the NOa
standard. Unlike lignite, virtually no
NO, emission data are available for the
combustion of coal refuse in slag tap
furnaces. The Administrator has
decided to continue the coal refuse
exemption under the standards
promulgated here because no new
information on coal refuse combustion
has become available since the
exemption under Subpart D was
established.
The environmental impacts of the
revised NOn standards were estimated
by using an economic model of the coal
and electric utility industries (see
discussion under REGULATORY
ANALYSIS). Thio projectioa took into
conoideration the combined effect of
complying with the revised SOa
particulate matter, and NO* standards
on the construction and operation of
both new and existing capacity.
National NO,, emissions from power
plants were Q& million tons in 1975 and
are predicted to increase to 9.3 million
tons by 1995 under the current
standards. These standards are
projected to reduce 1835 emissions by
600 thousand tons (6 percent).
In December 1971, under section 111
of the Clean Air Act the Administrator
issued standards of performance to limit
emissions of SOa, particulate matter,
and NOg from new, modified, and
reconstructed fossil-fuel-fired steam
generators (40 CFR 5KJ.40 et eeq.). Since
that time, the technology for controlling
emissions from this source category has
improved, but emissions of SO&,
particulate matter, and NOK continue to
be a national problem. In 1976, steam
electric generating units contributed 24
percent of the particulate matter, 65
percent of the SOa, and 29 percent of the
NO, emissions on a national basis.
The utility industry is expected to
have continued and significant growth.
The capacity is expected to increase by
about 50 percent with approximate 300
new fossO-fuel-fired power plant boilers
to begin operation within the next 10
years. Associated with utility growth is
the continued long-term increase in
utility coal consumption from some 400
million tons/year in 1975 to about 1250
million tons/year in 19S5. Under the
current performance standards for
power plants, national SOo emissions
are projected to increase approximately
17 percent between 1975 and 1995.
Impacts will be more dramatic on a
regional basis. For example, in the"
absence of more stringent controls,
utility SOa emissions are expected to
increase 1300 percent by 1995 in the
West South Central region of the
country (Texas, Oklahoma, Arkansas,
and Louisiana).
EPA waa petitioned on August 6,1976,
by the Sierra Club and the Oljato and
Red Mesa Chapters of the Navaho Tribe
to revise the SO8 standard so as to
require a 90 percent reduction in SO0
emissions from all new coal-fired power
plants. The petition claimed that
advances in technology oince 1S71
justified a revision of the standard. As a
result of the petition, EPA agreed to
investigate the matter thoroughly. On
January 27.1977 (42 FR 5121), EPA
announced that it had initiated a study
to review the technological, economic,
and other factors nseedsd to deJesmiae to
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what extent the~SO» standard for fossil-
fuel-fired steam generators should be
revised.
On August 7,1977, President Carter
signed into law the'Clean Air Act
Amendments of 1977. The provisions
under section lll(b)(6) of the Act, as
amended, required EPA to revise the
standards of performance for fossil-fuel-
fired electric utility steam generators
within 1 year after enactment.
After the Sierra Club petition of
August 1976, EPA initiated studies to
review the advancement made on
pollution control systems at power
plants. These studies were continued
following the amendment of the Clean
Air Act. In order to meet the schedule
established by the Act, a preliminary
assessment of the ongoing studies was
made in late 1977. A National Air
Pollution Control Techniques Advisory
Committee meeting was held on
December 13 and 14,1977, to present
EPA preliminary data. The meeting was
open to the public and comments were
solicited.
The Clean Air Act Amendments of
1977 required the standards to be
revised by August 7,1978. When it
appeared that the Administrator would
not meet this schedule, the Sierra Club
filed a complaint on July 14,1978, with
the U.S. District Court for the District of
Columbia requesting injunctive relief to
require, among other things, that the
Administrator propose the revised
standards by August 7,1978 (Sierra Club
v. Costle, No. 78-1297). The Court,
approved a stipulation requiring the
Administrator to (1) deliver proposed
regulations to the Office of the Federal
Register by September 12,1978, and (2)
promulgate the final regulations within 6
months after proposal (i.e., by March 19,
1979).
The Administrator delivered the
proposal package to the Office of the
Federal Register by September 12,1978,
and the proposed regulations were
published September 19,1978 (43 FR
42154). Public comments on the proposal
were requested by December 15, and a
public hearing was held December 12
and 13, the record of which was held
open until January 15,1979. More than
625 comment letters were received on
the proposal. The comments were
carefully considered, however, the'
issues could not be sufficiently
evaluated in time to promulgate the
standards by March 19.1979. On that
date the Administrator and the other
parties in Sierra Club v. Costle filed
with the Court a stipulation whereby the
Administrator would sign and deliver
the final standards to the Federal
Register on or before June 1,1979.
The Administrator's conclusions and
responses to the major issues are
presented in this preamble. These
regulations represent the
Administrator's response to the petition
of the Navaho Tribe and Sierra Club and
fulfill the rulemaking requirements
under section lll(b)(6) of the Act.

Applicability

General

These standards apply to electric
utility steam generating units capable of
firing more than 73 MW (250 million
Btu/hour) heat input of fossil fuel, for
which construction is commenced after
September 18,1978. This is principally
the same as the proposal. Some minor
changes and clarification in the
applicability requirements for
cogeneration facilities and resource
recovery facilities have been made.
On December 23,1971, the
Administrator promulgated, under
Subpart D of 40 CFR Part 60. standards
of performance for fossil-fuel-fired
steam generators used in electric utility
and large industrial applications. The
standards adopted herein do not apply
to electric utility steam generating units
originally subject to those standards
(Subpart D) unless the affected facilities
. are modified or reconstructed as defined
under 40 CFR 60 Subpart A and this
subpart. Similarly, units constructed
prior to December 23,1971, are not
subject to either performance standard
(Subpart D or Da) unless they are
modified or reconstructed.

Electric Utility Steam Generating Units

An electric utility steam generating
unit is defined as any steam electric
generating unit that is physically
connected to a utility power distribution
system and is constructed for the
purpose of selling more than 25 MW
electrical output and more than one
third of its potential electrical output
capacity. Any steam that is sold and
ultimately used to produce electrical
power for sale through the utility power
distribution system is also included
under the standard. The term "potential
electrical generating capacity" has been
added since proposal and is defined as
33 percent of the heat input rate at the
facility. The applicability requirement of
selling more than 25 MW electrical
output capacity has also been added
since proposal.
These standards cover industrial'
steam electric generating units or
cogeneration units (producing steam for
•both electrical generation and process
heat) that are capable of firing more
than 73 MW (250 million Btu/hr) heat
input of fossil fuel and are constructed
for the purpose of selling through a
utility power distribution system more
than 25 MW electrical output and more
than one-third of their potential
electrical output capacity (or steam
generating capacity ultimately used to
produce electricity for sale). Facilities
with a heat input rate in excess of 73
MW (250 million Btu/hour} that produce
only industrial steam or that generate
electricity but sell less than 25 MW
electrical output through the.utility
power distribution system or sell less
than one-third of their potential electric
output capacity through the utility
power distribution system are not ^
covered by these standards, but will
continue to be covered under Subpart D,
if applicable.
Resource recovery units incorporating
steam electric generating units that
would meet the applicability
requirements but that combust less than
25 percent fossil fuel on a quarterly (90-
day) heat-input basis are not covered by
the SO2 percent reduction requirements
under this standard. These facilities are
subject to the SO« emission limitation
and all other provisions of the
regulation. They are also required to
monitor their heat input by fuel type and
to monitor SO» emissions. If more than
25 percent fossil fuel is fired on a
quarterly heat input basis, the facility
will be subject to the SO» percent
reduction requirements. This represents
a change from the proposal which did
not include such provisions.
These standards cover steam
generator emissions from electric utility
combined-cycle gas turbines that are
capable of being fired with more than 73
MW (250 million Btu/hr) heat input of
fossil fuel and meet the other
applicability requirements. Electric
utility combined-cycle gas turbines that
use only turbine exhaust gas to provide
heat to a steam generator (waste heat
boiler) or that incorporate steam
generators that are not capable of being
fired with more than 73 MW (250 million
Btu/hr) of fossil fuel are not covered by
the standards.

Modification/Reconstruction
Existing facilities are only covered by
these standards if they are modified or
reconstructed as defined under Subpart
. A of 40 CFR Part 60 and this standard
(Subpart Da).
Few. if any, existing facilities that
change fuels, replace burners, etc. will
be covered by these standards as a
result of the modification/reconstruction
provisions. In particular, the standards
do not apply to existing facilities that
are modified to fire nonfossil fuels or to
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existing facilities that were designed to
fire gas or oil fuels and that are modified
to fire shale oil, coal/oil mixtures, coal/
oil/water mixtures, solvent refined coal,
liquified coal, gasified coal, or any other
coal-derived fuel. These provisions were
included in the proposal but have been
clarified in the final standard.

Comment* oa Proposal

Electric Utility Steam Generating Units

The applicability requirements are
basically the same as those in the
proposal; electric utility steam
generating units capable of firing greater
than 73 MW (250 million Btu/hour) heat
input of fossil fuel for which
construction is commenced after
September IB, 1978, are covered. Since
proposal, changes have been made to
specific applicability requirements for
industrial cogeneration facilities,
resource recovery facilities, and
anthracite coal-fired facilities. These
revisions are discussed later in this
preamble.
Only a limited number of comments
were received on the general
applicability provisions. Some
commenters expressed the opinion that
the standards should apply to both
industrial boilers and electric utility
steam generating units. Industrial.
boilers are not covered by these
standards because there are significant
differences between the economic
structure of utilities and the industrial
sector. EPA is currently developing
standards for industrial boilers nnd
plans to propose them in 1980.

Cogeneration Facilities

Cogeneration facilities are covered
under these standards if they have the
capability of firing more than 73 MW
(250 million Btu/hour) heat input of
fossil fuel and are constructed for the
purpose of selling more than 25 MW of
electricity and more than one-third of
their potential electrical output capacity.
This reflects a change from the proposed
standards under which facilities selling
less than 25 MW of electricity through
the utility power-distribution system
may have been covered.
A number of commenters suggested
that industrial cogeneration facilities are
expected to he highly efficient and that
their construction could be discouraged
if the proposed standards were adopted.
The commenters pointed out that
industrial cogeneration facilities are
unusual in' that a small capacity (10 MW
. electric output capacity, for example)
steam-electric generating set may be •
matched with a much larger industrial
steam generator (larger than 250 million
Bfti/hr for example). The Administrator
intended mat the proposed standards
cover only electric generation sets that
would sell more than 25 MW electrical
output on the utility power distribution
system. The final standards allow the
sale of up to 25 MW electrical output
capacity before a facility is covered.
Since most industrial cogeneration units
are expected to be less than 25 MW
electrical output capacity, few, if any,
new industrial cogeneration units will
be covered by these standards. The
standards do cover large electric utility
cogeaeration facilities because such
units are fundamentally electric utility
steam generating units.
Comments suggested clarifying what
was meant in the proposal by the sale of
more than one-third of its "maximum
electrical generating capacity". Under
the final standard the term "potential
electric output capacity" is used in place
of "maximum electrical generating
capacity" and is defined as 33 percent of
the steam generator heat input capacity.
Thus, a steam generator with a 500 MW
(1,700 million Btu/hr) heat input
capacity would have a 165 MW
potential electrical output capacity and
could sell up to one-third of this
potential output capacity on the grid (55
MW electrical output) before being
covered under the standard. Under the
proposal it was unclear if the,standard
allowed the sale of up to one-third of the
actual electric generating capacity of a
facility or one-third of the potential
generating capacity before being
covered under the standards. The
Administrator has clarified his
intentions in these standards. Without
this clarification the standards may
have discouraged some industrial
cogeneration facilities that have low in-
house electrical demand.
A number of commenters suggested
that emission credits should be allowed
for improvements in cycle efficiency at
new electric utility power plants. The
commenters suggested that the use of
electrical cogeneration technology and
other technologies with high cycle
efficiencies could result in less overall
fuel consumption, which in turn could
reduce overall environmental impacts
through lower air emissions and less
solid waste generation. The final
standards do not give credit for
increases in cycle efficiency because the
different technologies covered by the
standards and available for commercial
application at this time are based on the
use of conventional steam generating
units which have very similar cycle
efficiencies, and credits for improved
cycle efficiency would not provide
measurable benefits. Although the final
standards do not address cycle
efficiency, this approach will not
discourage the application of more
efficient technologies.
If a facility that is planned for
construction will incorporate an
innovative control technology (including
electrical generation technologies with
inherently low emissions or high
electrical generation efficiencies) the
owner or operator may apply to the
Administrator under section lll(j) of the
Act for an innovative technology waiver
which will allow for (1) np to four years
of operation or (2) up to seven.years
after issuance of a waiver prior to
performance testing. The technology
would have to have a substantial
likelihood of achieving greater
continuous emission reduction or
«chieve equivalent reductions at low
cost ki terms of energy, economics, or
nonair quality impacts before a waiver
would be issued.

Resource Recovery Facilities
Electric utility steam generating units
incorporated into resource recovery
facilities are exempt from the SO,
percent reduction requirements when
less than 25 percent of the heat input is
from fossil fuel on a quarterly heat input
basis. Such facilities are subject to all
other requirements of this standard. This
represents a change from the proposed
regulation, underwhich any steam
electric generating unit that combusts
non-fossil fuels such as wood residue,
sewage sludge, waste material, or
municipal refuse would have been
covered if the facility were capable of.
firing more than 75 MW (250 million
Btu/hr) of fossil fuel
A number of comments indicated that
the proposed standard could discourage
the construction of resource recovery
facilities that generate electricity
because of the SO, percentage reduction
requirement One commenter suggested
that most new resource recovery
facilities will process municipal refuse
and other wastes into a dry fuel with a
low-sulfur content that can be stored
and subsequently fired. The commenter
suggested that when firing processed
refuse fuel, little if any fossil fuel will be
necessary for combustion stabilization
over the long term; however, fossil fuel
will be necessary for startup. When a
cold unit is started, 100 percent fossil
fuel (oil or gas) may be fired for a few
hours prior to firing 100 percent
processed refuse.
Other commenters suggested that
resource recovery facilities would in
many cases be owned and operated by a
municipality and the electricity and
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ateam generated would be sold by
contract to offset operating costs. Under
such an arrangement, commenters
suggested that there may be a need to
fire fossil fuel on a short-term basis
when refuse is not readily available in
order to generate a reliable supply of
ateam for the contract customer.
The Administrator accepts these
suggestions and does not wish to
discourage the construction of resource
recovery facilities that generate
electricity and/or industrial steam. For
resource recovery facilities, the
Administrator believes that less than 25
percent heat input from fossil fuels will
be required on a long-term basis; even
though 100 percent fossil fuel firing
[greater than 73 MW (250 million Btu/
hour)] may be necessary for startup or
intermittent periods when refuse is not
available. During startup such units are '
allowed to fire 100 percent fossil fuel
because periods of startup are exempt
from the standards under 40 CFR 60.8(c).
If a reliable source of refuse is not
available and 100 percent fossil fuel is to
be fired more than 25 percent of the
time, the Administrator believes it is
reasonable to require such units to meet
the SO] percent reduction requirements.
This will allow resource recovery
facilities to operate with fossil fuel up to
25 percent of the time without having to
install and operate an FGD system.
Anthracite

These standards exempt facilities that
burn anthracite alone from the
percentage reduction requirements of
the SOS standard but cover them under
the 520 ng/J (1.2 lb/million Btu) heat
input emission limitation and all
requirements of the paniculate matter
and NO, standards. The proposed
regulations would have covered
anthracite in the same maner as all
other coals. Since the Administrator
recognized that there were arguments in
favor of less stringent requirements for
'anthracite, this issue was discussed in
the preamble to the proposed
regulations.
Over 30 individuals or organizations
commented on the anthracite issue.
Almost all of the commenters favored
exempting anthracite from the Sd
percentage reduction requirement. Some
of the reasons cited to justify exemption
were: (1) the sulfur content of anthracite
is low; (2) anthracite is more expensive
to mine and burn than bituminous and
will not be used unless it is cost
competitive; and (3) reopening the
anthracite mines will result in
improvement of acid-mine-water
conditions, elimination of old mining
scars on the topography, eradication of
dangerous fires in deep mines and culm
banks, and creation of new Jobs. One '
commenter pointed out that the average
sulfur content of anthracite is 1.09
percent. Other commenters indicated
that anthracite will be cleaned, which
will reduce the sulfur content. One
commenter opposed exempting
anthracite, because it would result in
more SO. emissions. Another
commenter said all coal-fired power
plants including anthracite-fired units
should have scrubbers.
After evaluating all of the comments,
the Administrator has decided to
exempt facilities that bum anthracite
alone from the percentage reduction
requirements of the SO. standard. These
facilities will be subject to all other
requirements of this regulation,
including the particulate matter and NO.
standards, and the 520 ng/J (1.2 lb/
million Btu) heat imput emission
limitation under the SO. standard.
In 10 Northeastern Pennsylvania
counties, where about 95 percent of the
nation's anthracite coal reserves are
located, approximately 40,000 acres of
land have been despoiled from previous
anthracite mining. The recently enacted
Federal Surface Mining Control and
Reclamation Act was passed to provide
for the reclamation of areas like this.
Under this Act, each ton of coal mined is
taxed at 35 cents for strip mining and 15
cents for deep mining operations. One-
half of the amount taxed is
automatically returned to the State
where the coal mined and one-half is to
be distributed by the Department of
Interior. This tax is expected to lead
eventually to the reclamation of the
anthracite region, but restoration will
require many years. The reclamation
will occur sooner if culm piles are used
for fuel, the abandoned mines are
reopened, and the expense of
reclamation is born directly by the mine
operator.
The Federal Surface Mining Control
and Reclamation Act and a similar
Pennsylvania law also provide for the
establishment of programs to regulate
anthracite mining. The State of
Pennsylvania has assured EPA that total
reclamation will occur if anthracite
mining activity increases. They are
actively pursuing with private industry
the development of one area involving
12,000 to 19,000 acres of despoiled land.
In Summary, the Administrator
concludes that the higher SO> emissions
resulting-from the use of anthracite
without a flue gas desulfurization
system is acceptable because of the
other environmental improvements that
will result. The impact of facilities using
anthracite on ambient air quality will be
minimized, because they will have to be
reviewed to assure compliance with the
prevention of significant deterioration
provisions under the Act.
Alaskan Coal
The final standards are the same as
the proposed; facilities fired with
Alaskan coal are covered in the same
manner as facilities fired with other
coals.
Commenters suggested that problems
unique to Alaska justify special
provisions for facilities located in
Alaska and firing Alaskan coal. Reasons
cited as justification for less stringent
standards by commenters on the
proposal were freezing conditions,
problems with sludge disposal, adverse
impact of FGD on the reliability of plant
operation, low-sulfur content of the coal,
and cost impact on the consumer. The
Administrator has examined these
factors and has concluded that
technically and economically feasible
means are available to overcome these
problems; therefore special regulatory
provisions are not justified.
In reaching this conclusion the
Administrator considered whether these
factors demonstrated that the standards
posed a substantially greater burden
unique to Alaska. In other northern
States where" severe freezing conditions
are common, plants are enclosed in
buildings and insulated vessels and
piping provide protection from freezing,
both for scrubber operation and for
liquid sludge dewatering. For an
equivalent electrical generating
capacity, the disposal sites for Alaskan
plants could be smaller than those for
most plants in the contiguous 48 States
because of the lower sulfur content of
Alaskan coal. Burying pipes carrying
sludge to waste ponds below the frost
line is feasible, except possibly in
permafrost areas. The Administrator
expects that future steam generators
cannot be sited in permafrost areas
because fly ash as well as scrubber
sludge could not be properly disposed of
in accordance with requirements of the
Resource Recovery and Reclamation
Act. In permafrost areas, turbines or
other non-waste-producing processes
are used or electricity is transmitted
from other locations.
One commenter pointed out that
failures of the FGD system would have
an adverse impact on the ability to
supply customers with reliable electric
service, since there are no extensive
interconnections with other utility
companies. The Administrator has
provided relief from the standards under
emergency conditions that would
require a choice between meeting a
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power demand or complying with the
standards. These emergency provisions
are discussed in a subsequent section of
this preamble.
Concern was expressed by the
commenters that the cost impact of the
standard would be excessive and that
the benefits do not justify the cost,
especially since Alaskan coal is among
the lowest sulfur-content coal in the
country. The Administrator agrees that
for comparable sulfur-content coals,
scrubber operating costs are slightly
higher in Alaska because of the
transportation costs of required
materials such as lime. However, the
operating costs are lower than the
typical costs of FGD units controlling
emissions from higher sulfur coals in the
contiguous 48 States.
The Administrator considered
applying a less stringent SO> standard to
Alaskan coal-fired units, but concluded
that there is insufficient distinction
between conditions in Alaska and
conditions in the northern part of the
contiguous 48 States to justify such
action. The Administrator has
concluded that Alaskan coal-fired units
should be controlled in the same manner
as other facilities firing low-sulfur coal.
Noncontinental Areas
Facilities in noncontinental areas
(State of Hawaii, the Virgin Islands,
Guam, American Samoa, the
Commonwealth of Puerto Rico, and the
Northern Mariana Islands) are exempt
from the SO2 percentage reduction
requirements. Such facilities are
required, however, to meet the SO*
emission limitations of 520 ng/J (1.2 lb/
million Btu) heat input (30-day rolling
average) for coal and 340 ng/J (0.8 lb/
million Btu) heat input (30-day rolling
average) for oil, in addition to all
requirements under the NO, and
particulate matter standards. This is the
same as the proposed standards.
Although this provision was identified
as an issue in the preamble to the
proposed standards, very few comments
were received on it. In general, the
comments supported the proposal. The
main question raised is whether Puerto
Rico has adequate land available for
sludge disposal.
After evaluating the comments and
available information, the Administrator
has concluded that noncontinental
areas, including Puerto Rico, are unique
and should be exempt from the SO*
percentage reduction requirements.
The impact of new power plants in
noncontinental areas on ambient air
quality will be minimized because each
will have to undergo a review to assure
compliance with the prevention of
significant deterioration provisions
under the Clean Air Act. The
Administrator does not intend to rule
out the possibility that an individual
BACT or LAER determination for a
power plant in a noncontinental area
may require scrubbing.

Emerging Technology
The final regulations for emerging
technologies are summarized earlier in
this preamble under SUMMARY OF
STANDARDS and are very similar to
the proposed regulations.
In general, the comments received on
the proposed regulations were
supportive, although a few commenters
suggested some changes. A few
commenters indicated that section lll(j)
of the Act provides EPA with authority
to handle innovative technologies. Some
commenters pointed out that the
proposed standards did not address
certain technologies such as dry
scrubbers for SO* control. One
commenter suggested that SRC I should
be included under the solvent refined
coal rather than coal liquefaction
category for purposes of allocating the
15,000 MW equivalent electrical
capacity.
On the basis of the comments and
public record, the Administrator
believes the need still exists to provide
a regulatory mechanism to allow a less
stringent standard to the initial full-scale
demonstration facilities of certain
emerging technologies. At the time the
standards were proposed, the
Administrator recognized that the
innovative technology waiver provisions
under section lll(j) of the Act are not
adequate to encourage certain capital-
intensive, front-end control
technologies. Under the innovative
technology provisions, the
Administrator may grant waivers for a
period of up to 7 years from the date of
issuance of a waiver or up to 4 years
from the start of operation of a facility,
whichever is less. Although this amount
of time may be sufficient to amortize the
cost of tail-gas control devices that do
not achieve their design control level, it
does not appear to be sufficient for
amortization of high-capital-cost, front-
end control technologies. The proposed
provisions were designed to mitigate the
potential impact on emerging front-end
technologies and insure that the
standards dojiot preclude the
development of such technologies.
Changes have been made to the
proposed regulations for emerging
technologies relative to averaging time
in order to make them consistent with
the final NO, and SO* standards;
however, a 24-hour averaging period has
been retained for SRC-I because it has
relatively uniform emission rates, which
makes a 24-hour averaging period more
appropriate than a 30-day rolling
average.
.. Commercial demonstration permits
establish less stringent requirements for
the SOj or NO, standards, but do not
exempt facilities with these permits
from any other requirements of these
standards.
Under the final regulations, the
Administrator (in consultation with the
Department of Energy) will issue
commercial demonstration permits for
the initial full-scale demonstration
facilities of each specified technology.
These technologies have been shown to
have the potential to achieve the
standards established for commercial
facilities. If, in implementing these
provisions, the Administrator finds that
a given emerging technology cannot
achieve the standards for commercial
facilities, but it offers superior overall
environmental performance (taking into
consideration all areas of environmental
impact, including air, water, solid waste,
toxics, and land use) alternative
standards can be established.
It should be noted that these permits
will only apply to the application of this
standard and will not supersede the new
source review procedures and
prevention of significant deterioration
requirements under other provisions of
the Act.

Modification/Reconstruction
The impact of the modification/
reconstruction provisions is the same for
the final standard as it was for the
proposed standard; existing facilities are
only covered by the final standards if
the facilities are modified or
reconstructed as defined under 40 CFR
60.14, 60.15, or 60.40a. Many types of fuel
switches are expressly exempt from
modification/reconstruction provisions
under section 111 of the Act.
Few, if any, existing steam generators
that change fuels, replace burners, etc.,
are expected to qualify under the
modification/reconstruction provisions;
thus, few, if any, existing electric utility
steam generating units will become
subject to these standards.
The preamble to the proposed
regulations did not provide a detailed
discussion of the modification/
reconstruction provisions, and the
comments received indicated that these
provisions were not well understood by
the commenters. The general
modification/reconstruction provisions
under 40 CFR 60.14 and 60.15 apply to all
source categories covered under Part 60.
Any source-specific modification/
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reconstruction provisions are defined in
more detail under the applicable oubpart
(60.408 for this standard).
A number of commenters expressly
requested that fuel switching provisions
be more clearly addressed by the
standard. In response, the Administrator
has clarified the fuel switching
provisions by including them in the final
otandards. Under these provisions
existing facilities that are converted to
nonfossil fuels are not considered to
have undergone modification. Similarly,
existing facilities designed to fire gas or
oil and that are converted to shale oil,
coal/oil mixtures, coal/oil/water
mixtures, solvent refined coal, liquified
coal, gasified coal, or any other coal-
derived fuel are not considered to have
undergone modification. This was the
Administrator's intention under the
proposal and was mentioned in the
Foderal Register preamble for the
proposal.

SO0 Standards
SO8 Control Technology—The final
SOo standards are based on the
performance of a properly designed,
installed, operated and maintained FGD
system. Although the standards are
based on lime and limestone FGD
oystems, other commercially available
FGD systems (e.g., Wellman-Lord,
double alkali and magnesium oxide) are
also capable of achieving the final
standard. In addition, when specifying
the form of the final standards, the
Administrator considered the potential
of dry SO0 control systems as discussed
later in this section.
Since the standards were proposed,
EPA has continued to collect SOa data
with continuous monitors at two sites
and initiated data gathering at two
additional sites. At the Conesville No. 5
plant of Columbus and Southern Ohio
Electric company, EPA gathered
continuous SOa data from July to
December 1978. The Conesville No. 5
FGD unit is a turbulent contact absorber
(TCA) scrubber using thiosorbic lime as
the scrubbing medium. Two parallel
modules handle the gas flow from a 411-
MW boiler firing run-of-mine 4.5 percent
sulfur Ohio coal. During the test period,
data for only thirty-four 24-hour
averaging periods were gathered
because of frequent boiler and scrubber
outages. The Conesville system
averaged 86.8 percent SOa removal, and
outlet SOa emissions averaged 0.80 lb/
million Btu. Monitoring of the Wellman-
Lord FGD unit at Northern Indiana
Public Service Company's Mitchell
station during 1978 included one 41-day
continuous period of operation. Data
previous data and analyzed. Results
indicated 0.61 lb SOa/million Btu and
89.2 percent SOa removal for fifty-six 24-
hour periods.
From December 1978 to February 1979,
"EPA gathered SOa data with continuous
monitors at the 10-MW prototype unit
(using a TCA absorber with lime) at
Tennessee Valley Authority's (TVA)
Shawnee station and the Lawrence No.
4 FGD unit (using limestone) of Kansas
Power and Light Company. During the
Shawnee test, data were obtained for
forty-two 24-hour periods in which 3.0
percent sulfur coal was fired. Sulfur
dioxide removal averaged 88.8 percent
Lawrence No. 4 consists of a 125-MW
boiler controlled by a spray tower
limestone FGD unit, in January and
February 1979, during twenty-two 24-
hour periods of operation with 0.5
percent sulfur coal, the average SOa
removal was 63.6 percent. The Shawnee
and Lawrence tests also demonstrated
that SOa monitors can function with
reliabilities above 80 percent. A
summary of the recent EPA-acquired
SOa monitored data follows:
CcdculJuT.
pet
Ko. 0)24-
towpsrtot)
AvcrcgaSO,
removal, pet
ConsoviJIafV
S)O3ft33 .....
Icescncoti
>O ff

Uma/TCA , _
. Umsstofo/cpmy to&sr .

4.5
3.5
3.0
O.S
34
sa
12
22
69.2
69.2
G8.6
es.e
Since proposing the standards, EPA
has prepared a report that updates
information in the earlier PEDCo report
on FGD systems. The report includes
listings of several new closed-loop
A variety of comments were received
concerning SOa control technology.
Several comments were concerned with
the use of data from FGD systems
operating in Japan. These comments
suggested that the Japanese experience
shows that technology exists to obtain
greater than €0 percent SOa removal.
The commenters pointed out that
attitudes of the plant opera tors,'the skill
of the FGD system operators, the close
surveillance of power plant emissions by
the Japanese Government, and technical
differences in the mode of scrubber
operation were primary factors in the
'higher FGD reliabilities and efficiencies
for Japanese systems. These commenters
stated that the Japanese experience is
directly applicable to U.S. facilities.
Other comments stated that the
Japanese systems cannot be used to
support standards for power plants in
the U.S. because of the possible
differences in factors such as the degree
of closed-loop versus open-loop
operation, the impact of trace
constituents such as chlorides, the
differences in inlet SOj concentrations,
SO* uptake per volume of slurry,
Japanese production of gypsum instead
of sludge, coal blending and the amount
of maintenance. /
The comments on closed-loop
operation of Japanese systems inferred
that larger quantities of water are
purged from these systems than from
their U.S. counterparts. A closed-loop
system is one where the only water
leaving the system is by: (1) evaporative
water losses in the scrubber, and (2) the
water associated with the sludge. The
administrator found by investigating the
systems referred to in the comments that
six of ten Japanese systems listed by
one commenter and two of four coal-
fired Japanese systems are operated
within the above definition of closed-
loop. The closed-loop operation of
Japanese scrubbers was also attested to
in an Interagencey Task Force Report,
"Sulfur Oxides Control Technology in
Japan" (June 30,1978) prepared for
Honorable Henry M. Jackson, Chairman,
Senate Committee on Energy and
Natural Resources. It is also important
to note that several of these successful
Japanese systems were designed by U.S.
vendors.
After evaluating all the comments, the
Administrator has concluded that the
experience with systems in Japan is
applicable to U.S. power plants and can
be used as support to show that the final
standards are achievable.
A few commenters stated that closed-
loop operation of an FGD system could
not be accomplished, especially at
utilities burning high-sulfur coal and
located in areas where rainfall into the
sludge disposal pond exceeds
evaporation from the pond. It is
important to note that neither the
proposed nor final standards require
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closed-loop operation of the FGD. The
commenters are primarily concerned
that future water pollution regulations
will require closed-loop operation.
Several of these commenters ignored the
large amount of water that is evaporated
by the hot exhaust gases in the scrubber
and the water that is combined with and
goes to disposal with the sludge in a
typical ponding system. If necessary, the
sludge can be dewatered by use of a
mechanical clarifier, filter, or centrifuge
and then sludge disposed of in a landfill
designed to minimize rainwater
collection. The sludge could also be
physically or chemically stabilized.
Most U.S. systems operate open-loop
(i.e., have some water discharge from
their sludge pond) because they are not
required to do otherwise. In a recent
report "Electric Utility Steam Generating
Units—Flue Gas Desulfurization
Capabilities as of October 1978" (EPA-
450/3-79-001), PEDCo reported that
several utilities burning both low- and
high-sulfur coal have reported that they
are operating closed-loop FGD systems.
As discussed earlier, systems in Japan
are operating closed-loop if pond
disposal is included in'the system. Also,
experiments at the Shawnee test facility
have shown that highly reliable
operation can be achieved with high
sulfur coal (containing moderate to high
levels of chloride) during closed-loop
operation. The Administrator continues
to believe that although not required,
closed-loop operation is technically and
economically feasible if the FGD and x
disposal system are properly designed.
If a water purge is necessary to control
chloride buildup, this stream can be
treated prior to disposal using
commercially available water treatment
methods, as discussed in the report
"Controlling SO2 Emissions from Coal-
Fired Steam-Electric Generators: Water
Pollution Impact" (EPA-600/7-78-045b).
Two comments endorsed coal
cleaning as an SO2 emission control
technique. One commenter encouraged
EPA to study the potential of coal
cleaning, and another endorsed coal
cleaning in preference to FGD. The
Administrator investigated coal cleaning
and the relative economics of FGD and
coal cleaning and the results are
presented in the report "Physical Coal
Cleaning for Utility Boiler SOi Emission
Control" (EPA-600/7-78-034). The
Administrator does not consider coal
cleaning alone as representing the best
demonstrated system for SO, emission
reduction. Coal cleaning does offer the
following benefits when used in
conjuction with an FGD system: (1) the
SOi concentrations entering the FGD
system are lower and less variable than
would occur without coal cleaning, (2)
percent removal credit is allowed ,
toward complying with the SO* standard
percent removal requirement, and (3) the
SO* emission limit can be achieved
when using a coal having a sulfur
content above that which would be
needed when coal cleaning is not
practiced. The amount of sulfur that can •
be removed from coal by physical coal
cleaning was investigated by the U.S.
Department of the Interior ("Sulfur
Reduction Potential of the Coals of the
United States," Bureau of Mines Report
of Investigations/1976, RI-8118). Coal
cleaning principally removes pyritic
sulfur from coal by crushing it to a
maximum top size and then separating
the pyrites and other rock impurities
from the coal. In order to prevent coal
cleaning processes from developing into
undesirable sources of energy waste, the
amount of crushing and the separation
bath's specific gravity must be limited to
reasonable levels. The Administrator
has concluded that crushing to 1.5
inches topsize and separation at 1.6
specific gravity represents common
practice. At this level, the sulfur
reduction potential of coal cleaning for
the Eastern Midwest (Illinois, Indiana,
and Western Kentucky) and the
Northern Appalachian Coal
(Pennsylvania, Ohio, and West Virginia)
regions averages approximately 30
percent. The washability of specific coal
seams will be less than or more than the
average.
Some comments state that FGD
systems do not work on specific coals,
such as high-sulfur Illinois-Indiana coal,
high-chloride Illinois coal, and Southern
Appalachian coals. After review of the
comments and data, the Administrator
concluded that FGD application is not
limited by coal properties. Two reports,
"Controlling SO8 Emissions from Coal-
Fired Steam-Electric Generators: Water
Pollution Impact" (EPS-600/7-78-045b)
and "Flue Gas Desulfurization Systems:
Design and Operating Considerations"
(EPA-600/7-78-030b) acknowledge that
coals with high sulfur or -chloride
content may present problems.
Chlorides in flue gas replace active
calcium, magnesium, or sodium alkalis
in the FGD system solution and cause
stress corrosion in susceptible materials.
Prescrubbing of flue gas to absorb
chlorides upstream of the FGD or the
use of alloy materials and protective
coatings are solutions to high-chloride
coal applications. Two reports, "Flue
Gas Desulfurization System Capabilities
for Coal-Fired Steam Generators" (EPA-
600/7-78-032b) and "Flue Gas
Desulfurization Systems: Design and
Operating Considerations" (EPA -600/
7-7-78-030b) also acknowledge that 90
percent SO» removal (or any given level)
is more difficult when burning high-
sulfur coal than when burning low-sulfur
coal because the mass of SO» that must
be removed is greater when high-sulfur
coal is burned. The increased load
results in larger and more complex FGD
systems (requiring higher liquid-to-gas
ratios, larger pumps, etc). Operation of
current FGD installations such as
LaCygne with over 5 percent sulfur coal.
Cane Run No. 4 on high-sulfur
midwestern coal, and Kentucky Utilities
Green River on 4 percent sulfur coal
provides evidence that complex systems
can be operated successfully on high-
sulfur coal. Recent experience at TVA,
Widows Creek No. 8 shows that FGD
systems can operate successfully at high
SOa removal efficiencies when Southern
Appalachian coals are burned.
Coal blending was the subject of two
comments: (1) that blending could
reduce, but not eliminate, sulfur
variability; and (2) that coal blending
was a relatively inexpensive way to
meet more relaxed standards. The
Administrator believes that coal
blending, by itself, does not reduce the
average sulfur content of coal but
reduces the variability of the sulfur
content. Coal blending is not considered
representative of the best demonstrated
system for SO» emission reduction. Coal
blending, like coal cleaning, can be
beneficial to the operation of an FGD
system by reducing the variability of
sulfur loading in the inlet flue gas. Coal
blending may also be useful in reducing
short-term peak SOj concentrations
where ambient SOa levels are a
problem.
Several comments were concerned
with the dependability of FGD systems
and problems encountered in operating
them. The commenters suggested that
FGD equipment is a high-risk
investment, and there has been limited
"successful" operating experience. They
expressed the belief that utilities will
experience increased maintenance
requirements and that the possibility of
forced outages due to scaling and
corrosion would be greater as a result of
the standards.
One commenter took issue with a
statement that exhaust stack liner
problems can be solved by using more
expensive materials. The commenter
also argued that EPA has no data
supporting the assumption that
scrubbers have been demonstrated at or
near 90 percent reliability with one
spare module. The Administrator has
considered these comments and has
concluded that properly designed and
operated FGD systems can perform
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reliably. An FGD system is a chemical
process which must be designed (1) to
include materials that will withstand
corrosive/erosive conditions, (2) with
instruments to monitor process
chemistry and (3) with spare capacity to
allow for planned downtime for routine
maintenance. As with any chemical
process, a startup or shakedown period
is required before steady, reliable
operation can be achieved.
The Administrator has continued to
follow the progress of the FGD systems
cited in the supporting documents
published in conjunction with the
proposed regulations in September 1978.
Availability of the FGD system at
Kansas City Power and Light Company's
LaCygne Unit No. 1 has steadily
improved. No FGD-related forced
outages were reported from September
1977 to September 1978. Availability
from January to September 1978
averaged 93 percent. Outages reported
were a result of boiler and turbine
problems but not FGD system problems.
LaCygne Unit No. 1 burns high-sulfur (5
percent) coal, uses one of the earlier
FGD's installed in the U.S., and reduces
SOt emissions by 80 percent with a
limestone system at greater than 90
percent availability. Northern States
Power Company's Sherburne Units
Numbers 1 and 2 on the other hand
operate on low-sulfur coal (0.8 percent).
Sherburne No. 1, which began operating
early in 1976, had 93 percent availability
in both 1977 and 1978. Sherburne No. 2,
which began operation in late 1976 had
availabilities of 93 percent in 1977 and
94 percent in 1978. Both of these systems
include spare modules to maintain these
high availabilities.
Several comments were received
expressing concern over the increased .
water use necessary to operate FGD
systems at utilities located in arid
regions. The Administrator believes that
water availability is a factor that limits
power plant siting but since an FGD
system uses less than 10 percent of the
water consumed at a power plant, FGD
will not be the controlling factor in the
siting of new utility plants.
A few commenters criticized EPA for
not considering amendments to the
Federal Water Pollution Control Act •
(now the Clean Water Act), the
Resource Conservation and Recovery
Act, or the Toxic Substances Control
Act when analyzing the water pollution
and solid waste impacts of FGD
systems. To the extent possible, the
Administrator believes that the impacts
of these Acts have been taken into
consideration in this rule-making. The
economic impacts were estimated on the
basis of requirements anticipated for
power plants under these Acts.
Various comments were received
regarding the SOt removal efficiency
achievable with FGD technology. One
comment from a major utility system
stated that they agreed with the
standards, as proposed. Many
comments stated that technology for
better than 90 percent SOi removal
exists. One comment was received
stating that 95 percent SO* removal
should be required. The Administrator
concludes that higher SOi removals are
achievable for low-sulfur coal which
was the basis of this comment. While 95
percent SOt removal may be obtainable
on high-sulfur coals with dual alkali or
regenerable FGD systems, long-term
data to support this level are not
available and the Administrator has
concluded that the demand for dual
alkali/regenerable systems would far
exceed vendor capabilities. When the
uncertainties of extrapolating
performance from 90 to 95 percent for
high-sulfur coal, or from 95 percent on
low-sulfur coal to high-sulfur coal, were
considered, the Administrator
concluded that 95 percent SOi removal
for lime/limestone based systems on
high-sulfur coal could not be reasonably
expected at this time.
Another comment stated that all FGD
systems except lime and limestone were
not demonstrated or not universally
-applicable. The proposed SOt standards
were based upon the conclusion that
they were achievable with a well
designed, operated, and maintained
FGD system. At the time of proposal, the
Administrator believed that lime and
limestone FGD systems would be the
choice of most utilities in the near future
but, in some instances, utilities would
choose the more reactive dual alkali or
regenerable systems. The use of
additives such as magnesium oxides
was not considered ,to be necessary for
attainment of the standard, but could be
used at the option of the utility.
Available data show that greater than
90 percent SO* removal has been
achieved at full scale U.S. facilities for
short-term periods when high-sulfur coal
is being combusted, and for long-term
periods at facilities when low-sulfur
coal is burned. In addition, greater than
90 percent SO> removal has been
demonstrated over long-term operating
periods at FGD facilities when operating •
on low- and medium-sulfur coals in
Japan.
Other commenters questioned the
exclusion of dry scrubbing techniques
from consideration. Dry scrubbing was
considered in EPA's background
documents and was not excluded from
consideration. Five commercial dry SO»
control systems are currently on order;
three for utility boilers (400-MW, 455-
MW, and 550-MW) and two for
industrial applications. The utility units
are designed to achieve 50 to 85 percent
reduction on a long-term average basis
and are scheduled to commence
operation in 1981-1982. The design basis
for these units is to comply with
applicable State emission limitations. In
addition, dry SO, control systems for six
other utility boilers are out for bid.
However, no full scale dry scrubbers are
presently in operation at utility plants so
information available to EPA and
presented in the background document
dealt with prototype units. Pilot scale
data and estimated costs of full-scale
dry scrubbing systems offer promise of
moderately high (70-85 percent) SO»
removal at costs of three-fourths or less
of a comparable lime or limestone FGD
system. Dry control system and wet
control system costs are approximately
equal for a 2-percent-sulfur coal. With
lower-sulfur coals, dry controls are
particularly attractive, not only because
they would be less costly than wet
systems, but also because they are
expected to require less maintenance
and operating staff, have greater
turndown capabilities, require less
energy consumption for operation, and
produce a dry solid waste material that
can be more easily disposed of than wet
scrubber sludge.
Tests done at the Hoot Lake Station (a
53-MW boiler) in Minnesota
demonstrated the performance
capability of a spray dryer-baghouse dry
control system. The exhaust gas
concentrations before the control
systems were 800 ppm SOj and an
average of 2 gr/acf particulate matter.
With lime as the sorbent, the control
system removed over 86 percent SOi
and 99.96 percent particulate matter at a
stoichiometric ratio of 2.1 moles of lime
absorbent per inlet mole of SO». When
the spent lime dust was recirculated
from the bag filter to the lime slurry feed
tank, SO2 removal efficiencies up to 90
percent ware obtained at stoichiometric
ratios of 1.3-1.5. With the lime
recirculation process, SO2 removal
efficiencies of 70-80 percent were
demonstrated at a more economical
stoichiometric ratio (about 0.75). Similar
tests were performed at the Leland Olds
Station using commercial grade-lime.
Based upon the available information,
the Administrator has concluded that 70
percent SO*, removal using lime as the
reactantis technically feasible and
economically attractive in comparison
to wet scrubbing when coals containing
less than 1.5 percent sulfur are being
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combusted. The coal reserves which
contain 1.5 percent sulfur or less
represent approximately 90 percent of
the total Western U.S. reserves.
The standards specify a percentage
reduction and an emission limit but do
not specify technologies which must be
used. The Administrator specifically
took into consideration the potential of
dry SO* scrubbing techniques when
specifying the final form of the standard
in order to provide an opportunity for
their development on low-sulfur coals.

Averaging Time

Compiance with the final SO»
standards is based on a 30-day rolling
average. Compliance with the proposed
standards was based on a 24-hour
average.
Several comments state that the
proposed SO» percent reduction
requirement is attainable using currently
available control equipment. One utility
company commented upon their
experience with operating pilot and
prototype scrubbers and a, full-scale
limestone FGD system on a 550-MW
plant. They stated that the FGD state of
the art is sufficiently developed to
support the proposed standards. Based
on their analysis of scrubber operating
variability and coal quality variability,
they indicated that to achieve an 85
percent reduction in SOt emissions 90
percent of the time on a daily basis, the
30-day average scrubber efficiency
would have to be at least 88 to 90
percent.
Other comments stated that EPA
contractors did not consider SO»
removal in context with averaging time,
that vendor guarantees were not based
on specific averaging times, and that
quoted SO» removal efficiencies were
based on testing modules. EPA found
through a survey of vendors that many
would offer 90-95 percent SOS removal
guarantees based upon their usual
acceptance test criteria. However, the
averaging time was not specified. The
Industrial Gas Cleaning Institute (IGCI),
which represents control equipment
vendors, commented that the control
equipment industry has the present
capability to design, manufacture, and
install FGD control systems that have
the capability of attaining the proposed
SOj standards (a continuous 24-hour
average basis). Concern was expressed,
however, about the proposed 24-hour
averaging requirement, and this
commenter recommended the adoption
of 30-day averaging. Since minute-to-
minute variations in factors affecting
FGD efficiency cannot be compensated
for instantaneously, 24-hour averaging is
an impracticably short period for
implementing effective correction or for
creating offsetting favorable higher
efficiency periods.
Numerous other comments were
received recommending that the
proposed 24-hour averaging period be
changed to 30 days. A utility company
stated that their experience with
operating full scale FGD systems at 500-
and 400-MW stations indicates that
variations in FGD operation make it
extremely difficult, if not impossible, to
maintain SO* removal efficiencies in
compliance with the proposed percent
reduction on a continual daily basis. A
commenter representing the industry
stated that it is clear from EPA's data
that the averaging time could be no
shorter than 24 hours,but that neither
they nor EPA have data at this time to
permit a reasonable determination of
what the appropriate averaging time
should be.
The Administrator has thoroughly
reviewed the available data on FGD
performance and all of the comments
received. Based on this review, he has
concluded that to alleviate this concern
over coal sulfur variability, particularly
its effect on small plant operations, and
to allow greater flexibility in operating
FGD units, the final SO, standard should
be based on a 30-day rolling average
rather than a 24-hour average as
proposed. A rolling average has been
adopted because it allows the
Administrator to enforce the standard
on a daily basis. A 30-day average is
used because it better describes the
typical performance of an FGD system,
allows adequate time for owners or
operators to respond to operating
problems affecting FGD efficiency,
permits greater flexibility in procedures
necessary to operate FGD systems in
compliance with the standard, and can
reduce the effects of coal sulfur
variability on maintaining compliance
with the final SO, standards without the
application of coal blending systems.
Coal blending systems may be required
in some cases, however, to provide for
the attainment and maintenance of the
National Ambient Air Quality Standards
for SO2.

Emission Limitation

In the September proposal, a 520 ng/J
(1.20 Ib/million Btu) heat input emission
limit, except for 3 days per month, was
specified for solid fuels. Compliance
was to be determined on a 24-hour
averaging basis.
Following the September proposal, the
joint working group comprised of EPA,
The Department of Energy, the Council
of Economic Advisors, the Council on
Wage and Price Stability, and others
investigated ceilings lower than the
proposal. In looking at these
alternatives, the intent was to take full
advantage of the cost effectiveness
benefits of a joint coal washing/
scrubbing strategy on high-sulfur coal.
The cost of washing is relatively
inexpensive; therefore, the group
anticipated that a low emission ceiling,
which would require coal washing and
90 percent scrubbing, could
substantially reduce emissions in the
East and Midwest at a relatively low
cost. Since coal washing is how a
widespread practice, it was thought that
Eastern coal production would not be
seriously impacted by the lower
emission limit. Analyses using an
econometric model of the utility sector
confirmed these conclusions and the
results were published in the Federal
Register on December 8,1978 (43 FR
57834).
Recognizing certain inherent
limitations in the model when assessing
impacts at disaggregated levels, the
Administrator undertook a more
detailed analysis of regional coal
production impacts in February using
Bureau of Mines reports which provided
seam-by-seam data on the sulfur content
of coal reserves and the coal washing
potential of those reserves. The analysis
identified the amount of reserves that
would require more than 90 percent
scrubbing of washed coal in order to
meet designated ceilings. To determine
the sulfur reduction from coal washing,
the Administrator assumed two levels of
coal preparation technology, which were
thought to represent state-of-the-art coal
preparation (crushing to 1.5-inch top size
with separation at 1.6 specific gravity,
and Vs-inch top size with separation at
1.6 specific gravity). The amount of
sulfur reduction was determined
according to chemical characteristics of
coals in the reserve base. This
assessment was made using a model
developed by EPA's Office of Research
and Development.
As a result of concerns expressed by
the National Coal Association, a
meeting was called for April 5,1979, in
order for EPA and the National Coal
Association to present their respective
findings as they pertained to potential
impacts of lower emission limits on
high-sulfur coal reserves in the Eastern
Midwest (Illinois, Indiana, and Western
Kentucky) and the Northern
. Appalachian (Ohio, West Virginia, and
Pennsylvania) coal regions. Recognizing
the importance of discussion, the
Administrator invited representatives
from the Sierra Club, the Natural
Resources Defense Council, the
Environmental Defense Fund, the Utility
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Air Regulator/Group, and the United
Mine Workers of America, as well as
other interested parties to attend.
At the April 5 meeting, EPA presented
its analysis of the Eastern Midwest and
Northern Appalachian coal regions. The
analysis showed that at a 240 ng/J (0.55
Ib/million Btu) annual emission limit
more than 90 percent scrubbing would
be required on between 5 and 10 percent
of Northern Appalachian reserves and
on 12 to 25 percent of the Eastern
Midwest reserves. At a 340 ng/J (0.80 lb/
million Btu) limit, less than 5 percent of
the reserves in each of these regions
would require greater than 90 percent
scrubbing. At that same meeting, the
National Coal Association presented
data on the sulfur content and
washability of reserves which are
currently held by member companies.
While the reported National Coal
Association reserves represent a very
small portion of the total reserve base,
they indicate reserves which are
planned to be developed in the near
future and provide a detailed property-
by-property data base with which to
compare EPA analytical results. Despite
the differences in data base sizes, the
National Coal Association's study
served to confirm the results of the EPA
analysis. Since the National Coal
Association results were within 5
percentage points of EPA's estimates,
the Administrator concluded that the
Office of Research and Development
model would provide a widely accepted
basis for studying coal reserve impacts.
In addition, as a result of discussions at
this meeting the Administrator revised
his assessment of state-of-the-art coal
cleaning technology. The National Coal
Association acknowledged that crushing
to 1.5-inch top size with separation at 1.6
specific gravity was common practice in
industry, but that crushing to smaller top
sizes would create unmanageable coal
handling problems and great expense.
In order to explore further the
potential for dislocations in regional
coal markets, the Administrator
concluded that actual buying practices
of utilities rather than the mere technical
usability of coals should be considered.
This additional analysis identified coals
that might not be used because of
conservative utility attitudes toward
scrubbing and the degree of risk that a
utility would be willing to take in buying
coal to meet the emission limit. This
analysis was performed in a similar
manner to the analysis described above
except that two additional assumptions
were made: (1) utilities would purchase
coal that would provide about a 10
percent margin below the emission limit
in order to minimize risk, and (2) utilities
would purchase coal that would meet
the emission limit (with margin) with a
90 percent reduction in potential SOa
emissions. This assumption reflects
utility preference for buying washed
coal for which only 85 percent scrubbing
is needed to meet both the percent
reduction and the emission limit as
compared to the previous assumption
that utilities would do 90 percent
scrubbing on washed coal (resulting in
more than 90 percent reduction in
potential SO> emissions). This analysis
was performed using EPA data at 430
ng/J (1.0 Ib/million Btu) and 520 ng/J
(1.20 Ib/million Btu) monthly emission
limits. The results revealed that a
. significant portion (up to 22 percent) of
the high-sulfur coal reserves in the
Eastern Midwest and portions of
Northern Appalachian coal regions
would require more than a 90 percent
reduction if tfie emission limitation was
established below 520 ng/J (1.20 lb/
million Btu) on a 30-day rolling average
basis. Although higher levels of control
are technically feasible, conservatism in
utility perceptions of scrubber
performance could create a significant
disincentive against the use of these
coals and disrupt the coal markets in
these regions. Accordingly, the
Administrator concluded the emission
limitation should be maintained at 520
ng/J (1.20 Ib/million Btu) on a 30-day
rolling average basis. A more stringent
emission limit would be counter to one
of the basic purposes of the 1977
Amendments, that is, encouraging the
use of higher sulfur coals.

Full Versus Partial Control

In September 1978, the Administrator
proposed a full or uniform control
alternative and set forth other partial or
variable control options as well for
public comment. At that time, the
Administrator made it clear that a
decision as to the form of the final
standard would not be made until the
public comments were evaluated and
additional analyses were completed.
The analytical results are'discussed
later under Regulatory Analysis.
This issue focuses on whether power
plants firing lower-sulfur coals should
be required to achieve the same
percentage reduction in potential SO>
emissions as those burning higher-sulfur
coals. When addressing this issue, the
public commenters relied heavily on the
statutory language and legislative
history of Section 111 of the Clean Air
Act Amendments of 1977 to bolster their
arguments. Particular attention was
directed to the Conference Report which
says in the pertinent part:
In establishing a national percent reduction
for new fossil fuel-fired sources, the
conferees agreed that the Administrator may,
in his discretion, set a range of pollutant
reduction that reflects varying fuel
characteristics. Any departure from the
uniform national percentage reduction
requirement, however, must be accompanied
by a finding that such a departure does not
undermine the basic purposes of the House
provision and other provisions of the act,
such as maximizing the use of locally
available fuels. •
Comments Favoring Full or Uniform
Control. Commenters in favor of full
control relied heavily on the statutory
presumption in favor of a uniform
application of the percentage reduction
requirement. They argued that the
Conference Report language, ". . . the
Administrator may, in his discretion, set
a range of pollutant reduction that
reflects varying fuel
characteristics. . . ." merely reflects the
contention of certain conferees that low-
sulfur coals may be more difficult to
treat than high-sulfur coals. This
contention, they assert, is not borne out
by EPA's technical documentation nor
by utility applications for prevention of
significant deterioration permits which
clearly show that high removal
efficiencies can be attained on low-
sulfur coals. In the face of this, they
maintain there is no basis for applying a
lower percent reduction for such coals.
These commenters further maintain
that a uniform application of the percent
reduction requirement is needed to
protect pristine areas and national
parks, particularly in the West. In doing
so, they note that emissions may be up
to seven times higher at the individual
plant level under a partial approach
than under uniform control. In the face
of this, they maintain that partial control
cannot be considered to reflect best
available control technology. They also
contend that the adoption of a partial
approach may serve to undermine the
more stringent State requirements
currently in place in the West.
Turning to national impacts,
commenters favoring a uniform
approach note that it will result in lower
emissions. They maintain that these
lower emissions are significant in terms
of public health and that such
reductions should be maximized,
particularly in light of the Nation's
commitment to greater coal use. They
also assert that a uniform standard is
clearly affordable. They point out that
the incremental increase in costs
associated with a uniform standard is
small when compared to total utility
expenditures and will have a minimal
impact at the consumer level. They
further maintain that EPA has inflated
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the costs of scrubber technology and has
failed to consider factors that should
result in lower costs in future years.
With respect to the oil impacts
associated with a uniform standard,
these same commenters are critical of
the oil prices used in the EPA analyses
and add that if a higher oil price had
been assumed the supposed oil impact
would not have materialized.
They also maintain that the adoption
of a partial approach would serve to
perpetuate the advantage that areas
producing low-sulfur coal enjoyed under
the current standard, which would be
counter to one of the basic purposes of
the House bill. On the other hand, they
argue, a uniform standard would not
only reduce the movement of low-sulfur
coals eastward but would serve "to ~
maximize the use of local high-sulfur
coals.
Finally, one of the commenters
specified a more stringent full control
option than had been analyzed by EPA.
It called for a 95 percent reduction in
potential SOa emissions with about a
280 ng/J {0.65 Ib/million Btu) emission
limit on a monthly basis. In addition,
this alternative reflected higher oil
prices and declining scrubber costs with
time. The results were presented at the
December 12 and 13 public hearing on
the proposed standards.
Comments Favoring Portia! or
Variable Control. Those commenters
advocating a partial or variable
approach focused their arguments on the
statutory language of Section 111. They
maintained that the standard must be
based on the "best technological system
of continuous emission reduction which
(taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated." They also
asserted that the Conference Report
language clearly gives the Administrator
authority to establish a variable
standard based on varying fuel
characteristics, i.e., coal sulfur content
Their principal argument is that a
variable approach would achieve
virtually the same emission reductions
at the national level as a uniform
approach but at substantially lower
costs and without incurring a significant
oil penalty. In view of this, they
maintain that a variable approach best
satisfies the statutory language of
Section 111.
In support of variable control they
also note that the revised NSPS will
serve as a minimum requirement for
prevention of significant deterioration
and non-attainment considerations, and
that ample authority exists to impose
more stringent requirements on a case-
by-case basis. They contend that these
authorities should be sufficient to
protect pristine areas and national parks
in the West and to assure the attainment
and maintenance of the health-related
ambient air quality standards. Finally,
they note that the NSPS is technology-
based and not directly related to
protection of the Nation's public health.
In addition, they argue that a variable
control option would provide a better
opportunity for the development of
innovative technologies. Several
commenters noted that in particular, a
uniform requirement would not provide
an opportunity for the development of
dry SOa control systems which they felt
held considerable promise for bringing
about SOa emission reductions at lower
costs and in a more reliable manner.
Commenters favoring variable control
also advanced the arguments that a
standard based on a range of percent
reductions would provide needed
flexibility, particularly when selecting
intermediate sulfur content coals.
Further, if a control system failed to
meet design expectations, a variable
approach would allow a source to move
to lower-sulfur coal to achieve
compliance. In addition, for low-sulfur
coal applications, a variable option
would substantially reduce the energy
penalty of operating wet scrubbers since
a portion of the flue gas could be used
for plume reheat.
To support their advocacy of a
variable approach, two commenters, the
Department of Energy and the Utility Air
Regulatory Group (UARG, representing
a number of utilities), presented detailid
results of analyses that had been
conducted for them. UARG analyzed a
standard that required a minimum
reduction of 20 percent with 520 ng/J
(1.20 Ib/million Btu) monthly emission
limit. The Department of Energy
specified a partial control option that
required a 33 percent minimum
requirement with a 430 ng/J (1.0 lb/
million Btu) monthly emission limit
Faced with these comments, the
Administrator determined the final
analyses that should be performed. He
concluded that analyses should be
conducted on a range of alternative
emission limits and percent reduction
requirements in order to determine the
approach which best satisfies the
statutory language and legislative
history of section 111. For these
analyses, the Administrator specified a
uniform or full control option, a partial
control option reflecting the Department
of Energy's recommendation for a 33
percent minimum control requirement,
and a variable control option which
specified a 520 ng/J (1.20 Ib/million Btu)
emission limitation with a 90 percent
reduction in potential SO* emissions
except when emissions to the
atmosphere were reduced below 260 ng/
J (0.60 Ib/million Btu), when only a 70
percent reduction in potential SO»
emissions would apply. Under the
variable approach, plants firing high-
sulfur coals would be required to
achieve a 90 percent reduction in
potential emissions in order to comply
with the emission limitation. Those using
intermediate and low-sulfur content
coals would be permitted to achieve
between 70 and 90 percent, provided
their emissions were less than 260 ng/J
(0.60 Ib/million BTU).
In rejecting the minimum requirement
of 20 percent advocated by .UARG, the
Administrator found that it not only
resulted in the highest emissions, but
that it was also the least cost effective
of the variable control options •
considered. The more stringent full
control option presented in the
comments was rejected because it
required a 95 percent reduction in
potential emissions which may not be
within the capabilities of demonstrated
technology for high-sulfur coals in all
cases.

Emergency Conditions

The final standards allow an owner or
operator to bypass uncontrolled flue
gases around a malfunctioning FGD
system provided (1) the FGD system has
been constructed with a spare FGD
module, (2) FGD modules are not
available in sufficent numbers to treat
the entire quantity of flue gas generated,
and (3) all available electric generating
capacity is being utilized in a power
pool or network consisting of the
generating capacity of the affected
utility company (except for the capacity
of the largest single generating unit in
the company), and the amount of power
that could be purchased from
neighboring interconnected utility
companies. The final standards are
essentially the same as those proposed.
The revisions involve wording changes
to clarify the Administrator's intent and
revisions to address potential load
management and operating problems.
None of the comments received by EPA
disputed the need for the emergency
condition provisions or objected to their
intent
The intent of the final standards is to
encourage power plant owners and
operators to install the best available
FGD systems and to implement effective
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operation and maintenance procedures
but not to create power supply
disruptions. FGD systems with spare
FGD modules and FGD modules with
spare equipment components have
greater capability of reliable operation
than systems without spares. Effective
control and operation of FGD systems
by engineering supervisory personnel
experienced in chemical process
operations and properly trained FGD
system operators and maintenance staff
are also important in attaining reliable
FGD system operation. While the
standards do not require these
equipment and staffing features, the
Administrator believes that their use
will make compliance with the
standards easier. Malfunctioning FGD
systems are not exempt from the SOt
standards except during infrequent
power supply emergency periods. Since
the exemption does not apply unless a
spare module has been installed (and
operated), a spare module is required for
the exemption to apply. Because of the
disproportionate cost of installing a
spare module on steam generators
having a generating capacity of 125 MW
or less, the standards do not require
them to have-spare modules before the
emergency conditions exemption
applies.
The proposed standards included the
requirement that the emergency
condition exemption apply only to those
facilities which have installed a spare
FGD system module or which have 125
MW or less of output capacity.
However, they did not contain
procedures for demonstrating spare
module capability. This capability can
be easily determined once the facility
commences operation. To specify how
this determination is to be performed,
provisions have been added to the
regulations. This determination is not
required unless the owner or operator of
the affected facility wishes to claim
spare module capability for the purpose
of availing himself of the emergency
condition exemption. Should the
Administrator require a demonstration
of spare module capability, the owner or
operator would schedule a test within 60
days for any period of operation lasting
from 24 hours to 30 days to demonstrate
that he can attain the appropriate SOt
emission control requirements when the
facility is operated at a maximum rate
without using one of its FGD system
modules. The test can start at any time
of day and modules may be rotated in
and out of service, but at all times in the
test period one module (but not
necessarily the same module) must not
be operated to demonstrate spare
module capability.
Although it is within the
Administrator's discretion to require the
spare module capability demonstration
test, the owner or operator of the facility
has the option to schedule the specific
date and duration t)f the test. A
minimum of only 24 hours of operation
are required during the test period
because this period of time is adequate
to demonstrate spare module capability
and it may be unreasonable in all .
circumstances to require a longer (e.g.,
30 days) period of operation at the
facility's maximum heat input rate.
Because the owner or operator has the
flexibility to schedule the test, 24 hours
of operation at maximum rate will not
impose a significant burden on the
facility
The Administrator believes that the
standards will not cause supply
disruption because (1) well designed
and operated FGD systems can attain
high operating availability, (2) a spare
FGD module can be used to rotate other
modules out of service for periodic
maintenance or to replace a
malfunctioning module, (3) load shifting
of electric generation to another
generating unit can normally, be used if a
"part or all of the FGD system were to
malfunction, and (4) during abnormal
power supply emergency periods, the
bypassing exemption ensures that the
regulations would not require a unit to
stand idle if its operation were needed
to protect the reliability of electric
service. The Administrator believes that
this exemption will not result in
extensive bypassing because the
probability of a major FGD malfunction
and power supply emergency occurring
simultaneously is small.
A commenter asked that the definition
of system capacity be revised to ensure
that the plant's capability rather than
plant rated capacity be used because
the full rated capacity is not always
operable. The Administrator agrees with
this comment because a component
failure (e.g., the failure of one coal
pulverizer) could prevent a boiler from '
being operated at its rated capacity, but
would not cause the unit to be entirely
shut down. The definition has been
revised to allow use of the plant's
capability when determining the net
system capacity.
One commenter asked that the
definition of system capacity be revised
to include firm contractual purchases
and to exclude firm contractual sales.
Because power obtained through
contractual purchases helps to satisfy
load demand and power sold under
contract affects the net electric
generating capacity available in the
system, the Administrator agrees with
this request and has included power
purchases in the definition of net system
capacity and has excluded sales by
adding them to the definition of system
load.
A commenter asked that the
ownership basis for proration of electric
capacity in several definitions be
modified when there are other
contractual arrangements. The
Administrator agrees with this comment
and has revised the definitions
accordingly.
One commenter asked that definitions
describing "all electric generating
equipment owned by the utility
company" specifically include
hydroelectric plants. The proposed
definitions did include these plants, but
the Administrator agrees with the
clarification requested, and the
definitions have been revised.
A commenter asked that the word
"steam" be removed from the definition
of system emergency reserves to clarify
that nuclear units are included. The
Administrator agrees with the comment
and has revised the definition.
Several commenters asked that some
type of modification be made to the
emergency condition provisions that
would consider projected system load
increases within the next calendar day.
One commenter asked that emergency
conditions apply based on a projection
of the next day's load. The
Administrator does not agree with the
suggestion of using a projected load,
which may or may not materialize, as a
criterion to allow bypassing of SO2
emissions, because the load on a
generating unit with a malfunctioning
FGD system should be reduced
whenever there is other available
system capacity.
A commenter recommended that a
unit removed from service be allowed to
return to service if such action were
necessary to maintain or reestablish
system emergency reserves. The
Administrator agrees that it would be
impractical to take a large steam
generating unit entirely out of service
whenever load demand is expected to
later increase to the level where there
would be no other unit available to meet
the demand or to maintain system
emergency reserves. To address the
problem of reducing load and later
returning the load to the unit, the
• Administrator has revised the proposed •
emergency condition provisions to give
an owner or operator of a unit with a
malfunctioning FGD system the option
of keeping (or bringing) the unit into
spinning reserve when the unit is
needed to maintain (or reestablish)
system emergency reserves. During this
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period, emissions must be controlled to
the extent that capability exists within
the FGD system, but bypassing
emissions would be allowed when the
capability of a partially or completely
failed FGD system is inadequate. This
procedure will allow the unit to operate
in spinnjng reserve rather than being
entirely shut down and will ensure that
a unit can be quickly restored to service.
The final emergency condition
provisions permit bypassing of
emissions from a unit kept in spinning
reserve, but only (1) when the unit is the
last one available for maintaining
system emergency reserves, (2) when it
is operated at the minimum load
consistent with keeping the unit in
spinning reserve, and (3) has inadequate
operational FGD capability at the
minimum load to completely control SO>
emissions. This revision will still
normally require load on a
malfunctioning unit to be reduced to a
minimum level, even if load demand is
anticipated to increase later; but it does
prevent having to take the unit entirely
out of operation and keep it available in
spinning reserve to assume load should
an emergency arise or as load increases
the following day. Because emergency
condition periods are a small percentage
of total operating hours, this revision to
allow bypassing of SO2 emissions from a
unit held in spinning reserve with
reduced output is expected to have
minor impact on the amount of SOa
emitted.
One commenter stated that the
proposed provisions would not reduce
the necessity for additional plant
capacity to compensate for lower net
reliability. The Administrator does not
agree with this comment because the
emergency condition provisions allow
operation of a unit with a failed FGD
system whenever no other generating
capacity is available for operation and
thereby protects the reliability of
electric service. When electric load is
shifted from a new steam-electric
generating unit to another electric
generating unit, there would be no net
change in reserves within the power
system. Thus, the emergency condition
provisions prevent a failed FGD system
from impacting upon the utility
company's ability to generate electric
power and prevents an impact upon
reserves needed by the power system to
maintain reliable electric service.
A commenter asked that the definition
of available system capacity be clarified
because (1) some utilities have certain
localized areas or zones that, because of
system operating parameters, cannot be
served by all of the electric generating
units which constitute the utility's
system capacity, and (2) an affected
facility may be the only source of supply
for a zone or area. Almost all electric
utility generating units in the United
States are electrically interconnected
through power transmission lines and
switching stations. A few isolated units
in the U.S. are not interconnected to at
least one other electric generating unit
and it is possible that a new unit could
also be constructed in an isolated area
where interconnections would not be
practical. For a single, isolated unit
where it is not practical to construct
interconnections, the emergency
condition provisions would apply
whenever an FGD malfunction occurred
because there would be no other
available system capacity to which load
could be shifted. It is also possible that
two or three units could be
interconnected, but not interconnected
with a larger power network (e.g.,
Alaska and Hawaii). To clarify this
situation, the definitions of net system
capacity, system load, and system
emergency reserves have been revised
to include only that electric power or
capacity interconnected by a network of
power transmission facilities. Few units
will not be interconnected into a
network encompassing the principal and
neighboring utility companies. Power
plants, including those without FGD
systems, are expected to experience
electric generating malfunctions and
power systems are planned with reserve
generating capacity and interconnecting
electric transmission lines to provide
means of obtaining electricity from
alternative generating facilities to meet
demand when these occasions arise.
Arrangements for an affected facility
would typically include an
interconnection to a power transmission
network even when it is geographically
located away from the bulk of the utility
company's power system to allow
purchase of power from a neighboring
utility for those localized service areas
when necessary to maintain service
reliability. Contract arrangements can
provide for trades of power in which a
localized zone served by the principal
company owning or operating the
affected facility is supplied by a
neighboring company. The power bought
by the principal company can, if desired
by the neighboring company, be
replaced by operation of other available
units in the principal company even if
these units are located at a distance
from the localized service zone. The
proposed definition of emergency
condition was contingent upon the
purchase of power from another
electrical generation facility. To further
clarify this relationship, the
Administrator has revised the proposed
definitions to define the relationship
between the principal company (the
utility company that owns the
generating unit with the malfunctioning
FGD system) and the neighboring power
companies for the purpose of
determining when emergency conditions
exist.
A commenter requested that the
proposed compliance provisions be
revised so that they could not be
interpreted to force a utility to operate a
partially functional FGD module when
extensive damage to the FGD module
would occur. For example, a severely
vibrating fan must be shut down to
prevent damage even though the FGD
system may be otherwise functional.
The Administrator agrees with this
comment and has revised the
compliance provisions not to require
FGD operation when significant damage
to equipment would result.
One commenter asked that the
definition of system emergency reserves
account for not only the capacity of the
single largest generating unit, but also
for reserves needed for system load-
frequency regulation. Regulation of
power frequency can be a problem when
the mix of capacitive and reactive loads
shift. For example, at night capacitive
load of industrial plants can adversely
affect power factors. The Administrator
disagrees that additional capacity
should be kept independent of the load
shifting requirements. Under the
definition for system emergency
reserves, capacity equivalent to the
largest single unit in the system was set
aside for load management. If frequency
regulation has been a particular
problem, extra reserve margins would
have been maintained by the utility
company even if an FGD system were
not installed. Reserve capacity need not
be maintained within a single generating
unit. The utility company can regulate
system load-frequency by distributing
their system reserves throughout the
electric power system as needed. In the
Administrator's judgment, these
regulations do not impact upon the
reserves maintained by the utility
company for the purpose of maintaining
power system integrity, because the
emergency condition provisions do not
restrict the utility company's freedom in
distributing their reserves and do not
require construction of additional
reserves.
A commenter asked that utility ,
operators be given the option to ignore
the loss of SOj removal efficiency due to
FGD malfunctions by reducing the level
of electric generation from an affected
unit. This would control the amount of
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Sd emitted on.a pounds per hour basis,
but would also allow and exemption
from the percentage of SOs removal
specified by the SOt standards. The
Administrator believes that allowing
this exemption is not necessary because
load can usually be shifted to other
electric generating units. This procedure
provides an incentive to the owner or
operator to properly maintain and
operate FGD systems. Under the
procedures suggested by the coTnmenter,
neglect of the FGD system would be
encouraged because an exemption
would allow routine operation at
reduced percentages of SO, removal.
Steam generating units are often
operated at less than rated capacity and
a fully operational FGD system would
not be required for compliance during
these periods if this exemption were
allowed. The procedure suggested by
the commenter is also not necessary
because FGD modules can be designed
and constructed with separate
equipment components so that they are
routinely capable of independent
operation whenever another module of
the steam-generating unit's FGD system
is not available. Thus, reducing the level
of electric generation and removing the
failed FGD module for servicing would
not affect the remainder of the FGD
system and would permit the utility to
maintain compliance with the standards
without having to take the generating
unit entirely out of operation. Each
module should have the capability of
attaining the same percentage reduction
of SO« from the flue gas it treats
regardless of the operability of the other
modules in the system to maintain
compliance with the standards.
Although the efficiency of more than one
FGD module may occasionally be
affected by certain equipment
malfunctions, a properly designed FGD
system has no routine need for an ~
exemption from the SOs percentage
reduction requirement when the unit is
operated at reduced load. The
Administrator has concluded that the
final regulations provide sufficient
flexibility for addressing FGD
malfunctions and that an exemption
from the percentage SO2 removal
requirement is not necessary to protect
electric service reliability or to maintain
compliance with these SOa standards.

Paniculate Matter Standard

The final standard limits particulate
matter emissions to 13 ng/J (0.03 lb/
million Btu) heat input and is based on
the application of ESP or baghouse
control technology. The final standard is
the same as the proposed. The
Administrator has concluded that ESP
and baghouse control systems are the
best demonstrated systems of
continuous emission reduction (taking
into consideration the cost of achieving
such emission reduction, and nonair
quality health and enviornmental
impacts, and energy requirements] and
that 13 ng/J (0.03 Ib/million Btu) heat
input represents the emission level
achievable through the application of
these control systems.
One group of commenters indicated
that they did not support the proposed
standard because in their opinion it
would be too expensive for the benefits
obtained; and they suggested that the
final standard limit emissions to 43 ng/J
(0.10 Ib/million Btu] heat input which is
the same as the current standard under
40 CFR Part 60 Subpart D. The
Administrator disagrees with the
commenters because the available data
clearly indicate that ESP and baghouse
control systems are capable of
performing at the 13 ng/J (0.03 Ib/million
Btu] heat input emission level, and the
economic impact evaluation indicates
that the costs and economic impacts of
installing these systems are reasonable.
The number of commenters expressed
the opinion that the proposed standard
was to strict, particularly for power
plants firing low-sulfur coal, because
baghouse control systems have not been
adequately demonstrated on full-size
power plants. The commenters
suggested that extrapolation of test data
from small scale baghhouse control
systems, such as those used to support
the proposed standard, to full-size utility
applications is not reasonable.
The Administrator believes that
baghouse control systems are
demonstrated for all sizes of power
plants. At the time the standards were
proposed, the Administrator concluded
that since baghouses are designed and
constructed in modules rather than as
one large unit, there should be no
technological barriers to designing and
constructing utility-sized facilities. The
largest baghouse-controlled, coal-fired
power plant for which EPA had
emission test data to support the
proposed standard was 44 MW. Since
the standards were proposed, additional
information has become available which
supports the Administrator's position
that baghouses are demonstrated for all
sizes of power plants. Two large
baghouse-controlled, coal-fired power
plants have recently initiated
operations. EPA has obtained emission
data for one of these units. This unit has
achieved particulate matter emission
levels below 13 ng/J (0.03 Ib/million Btu)
heat input. The baghouse system for this
facility has 28 modules rated at 12.5 MW
capacity per module. This supports the
Administrator's conclusion that
baghouses are designed and constructed
in modules rather than as one large unit,
and there should be no technological
barriers to designing and constructing
utility-sized facilities.
One commenter indicated that
baghouse control systems are not
demonstrated for large utility
application at this time and
recommended that EPA gather one year
of data from 1000 MW of baghouse
installations to demonstrate that
baghouses can operate reliably and
achieve 13 ng/J (0.03 Ib/million Btu) heat
input. The standard would remain at 21
to 34 ng/J (0.05 to 0.08 Ib/million Btu)
heat input until such demonstration. The
Administrator does not believe this
approach is necessary because
baghouse control systems have been
adequately demonstrated for large
utility applications.
One group of commenters supported
the proposed standard of 13 ng/J (0.03
Ib/million Btu) heat input. They
indicated that in their opinion the
proposed standard attained the proper
balance of cost, energy and
environmental factors and was
necessary in consideration of expected
growth in coal-fired power plant
capacity.
Another group of commenters which
included the trade association of
emission control system manufacturers
indicated that 13 ng/J (0.03 Ib/million
Btu) is technically achievable. The trade
association further indicated the
proposed standard is technically
achievable for either high- or low-sulfur
coals, through the use of baghouses,
ESPs, or wet scrubbers.
A number of commenters
recommended that the proposed
standard be lowered to 4 ng/J (0.01 lb/
million Btu) heat input. This group of
commenters presented additional
emission data for utility baghouse
control systems to support their
recommendation. The. data submitted by
the commenters were not available at
the time of proposal and were for utility
units of less than 100 MW electrical
output capacity. The commenters
suggested that a 4 ng/J (0.01 Ib/million
Btu] heat input standard is achievable
based on baghouse technology, and they
suggested that a standard based on
baghouse technology would be
consistent with the technology-forcing
nature of section 111 of the Act. The
Administrator believes that the
available data base for baghouse
performance supports a standard of 13
ng/J (0.03 Ib/million Btu) heat input but
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does not support a lower standard such
as 4 ng/J (0.01 Ib/million Btu) heat input.
One commenter suggested that the
standard should be set at 26 ng/J (0.06
Ib/million Btu) heat imput so that
paniculate matter control systems
would not be necessary for oil-fired
utility steam generators. Although it is
expected that few oil-fired utility boilers
will be constructed, the ESP
performance data which is contained in
the "Electric Utility Steam Generating
Units, Background Information for
Promulgated Emission Standards" (EPA
450/3-79-021), supports the conclusion
that ESPs are applicable to both oil
firing and coal firing. The Administrator
believes that emissions from 6il-fired
utility boilers should be controlled to the
same level as coal-fired boilers.
NO? Standard

The NO, standards limit emissions to
210 ng/J (0.50 Ib/million Btu) heat input
from the combustion of subbituminous
coal and 260 ng/I (0.60 Ib/million Btu)
heat imput from the combustion of
bituminous coal, based on a 30-day
rolling average. In addition, emission
limits have been established for other
solid, liquid, and gaseous fuels, as
discussed in the rational section of this
preamble. The final standards differ
from the proposed standards only in
that the final averaging time for
determining compliance with the
standards is based on a 30-day rolling
average, whereas a 24-hour average was
proposed. All comments received during
the public comment period were
considered in developing the final NO,
standards. The major issues raised
during the comment period are
discussed below.
One issue concerned the possibility
that the proposed 24-hour averaging
period for coal might seriously restrict
the flexibility boiler operators need
during day-to-day operation. For
example, several commenters noted that
on some boilers the control of boiler
tube slagging may periodically require
increased excess air levels, which, in
turn, would increase NO, emissions.
One commenter submitted data
indicating that two modern Combustion
Engineering (CE) boilers at the Colstrip,
Montana plant of the Montana Power
Company do not consistently achieve
the proposed NO, level of 210 ng/J (0.50
Ib/million Btu) heat input on a 24-hour
basis. The Colstrip boilers burn
subbituminous coal and are required to
comply with the^NO, standard under 40
CFR Part 60, Subpart D of 300 ng/J (0.70
Ib/million Btu) heat input. Several other
commenters recommended that the 24-
hour averaging period be extended to 30
days to allow for greater operational
flexibility.
As an aid in evaluating the
operational flexibility question, the
Administrator has reviewed a total of 24
months of continuously monitored NO,
data from the two Colstrip boilers. Six
months of these data were available to
the Administrator before proposal of
these standards, and two months were
submitted by a commenter. The
commenter also submitted a summary of
28 months of Colstrip data indicating the
number of 24-hour averages per month
above 210 ng/J (0.50 Ib/million Btu) heat
input. The remaining Colstrip data were
obtained by the Administrator from the
State of Montana after proposal. In
addition to the Colstrip data, the
Administrator has reviewed
approximately 10 months of
continuously monitored NO, data from
five modern CE utility boilers. Three of
the boilers burn subbituminous coal,
two burn bituminous coal, and all five
have monitors that have passed
certification tests. These data were
obtained from electric utility companies
after proposal. A summary of all of the
continuously monitored NO, data that
the Administrator has considered
appears in "Electric Utility Steam
Generating Units, Background
Information for Promulgated Emission
Standards" (EPA 450/3-79-021).
The usefulness of these continuously
monitored data in evaluating the ability
of modern utility boilers to continuously
achieve the NO, emission limits of 210
and 260 ng/J (0.50 and 0.60 Ib/million
Btu) heat input is somewhat limited.
This is because the boilers were
required to comply with a higher NO,
level of 300 ng/J (0.70 Ib/million Btu)
heat input. Nevertheless, some
conclusions can be drawn, as follows:
(1) Nearly all of the continuously
monitored NO, data are in compliance
with the boiler design limit of 300 ng/J
(0.70 Ib/million Btu) heat input on the
basis of a 24-hour average.
(2) Most of the continuously
monitored NO, data would be in
compliance with limits of 260 ng/J (0.60
Ib/million Btu) heat input for bituminous
coal ov 210 ng/J (0.50 Ib/million Btu)
heat input for subbituminous coal when
averaged over a 30-day period. Some of
the data would be out of compliance
based on a 24-hour average.
(3) The volume of continuously
monitored NO, emission data evaluated
by the Administrator (34 months from
seven large coal-fired boilers) is
sufficient to indicate the emission
variability expected during day-to-day
operation of a utility-size boiler. In the
Administrator's judgment, this emission
variability adequately represents
slagging conditions, coal variability,
load changes, and other factors that may
influence the level of NO, emissions.
(4) The variability of continuously
monitored NO, data is sufficient to
cause some concern over the ability of a
utility boiler that burns solid fuel to
consistently achieve a NO, boiler design
limit, whether 300, 260, or 210 ng/J (0.70.
0.60, or 0.50 Ib/million Btu) heat input,
based on 24-hour averages. In contrast,
it appears that there would be no
difficulty in achieving the boiler design
limit based on 30-day periods.
Based on these conclusions, the
Administrator has decided to require
compliance with the final standards for
solid fuels to be based on a 30-day
rolling average. The Administrator
believes that the 30-day rolling average
will allow boilers made by all four major
boiler manufacturers to achieve the
standards while giving boiler operators
the flexibility needed to handle
conditions encountered during normal
operation.
Although the Administrator has not
evaluated continuously monitored NO,
data from boilers manufactured by
companies other than CE, the data from
CE boilers are considered representative
of the other boiler manufacturers. This is
because the boilers of all four ;
manufacturers are capable of achieving
the same NO, design limit, and because
the conditions that occur during normal
operation of a boiler (e.g., slagging,
variations in fuel quality, and load
reductions) are similar for all four
manufacturer designs. These conditions.
the Administrator believes, lead to
similar emission variability and require
essentially the same degree of
operational flexibility.
Some commenters have question the
validity of the Colstrip data because the
Colstrip continuous NO, monitors have
not passed certification tests. In April
and June of 1978 EPA conducted a
detailed evaluation of these monitors.
The evaluation led the Administrator to
conclude that the monitors were
probably biased high, but by less than
21 ng/J (0.50 Ib/million Btu) heat input.
Since this error is so small (less than 10
percent), the Administrator considers
the data appropriate to use in
developing the standards.
A number of commenters expressed
concern over the ability of as many as
three of the four major boiler
manufacturer designs to achieve the
proposed standards. Although most of
the available NO, test data are from CE
boilers, the Administrator believes that
all four of the boiler manufacturers will
be able to supply boilers capable of
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achieving the standards. This conclusion
is supported with (1) emission test
results from 14 CE, seven Babcock and
Wilcox (B&W), three Foster Wheeler
(FW), and four Riley Stoker (RS) utility
boilers; (2) 34 months of continuously
monitored NO, emission data from
seven CE boilers; and (3) an evaluation
of plans under way at B&W, FW, and RS
to develop low-emission burners and
furnace designs. Full-scale tests of these
burners and furnace designs have
proven their effectiveness in reducing
NO, emissions without apparent long-
term adverse side effects.
Another issue raised by commenters
concerned the effect that variations in
the nitrogen content of coal may have on
achieving the NO, standards. The
Adminstrator recognizes that NO, levels
are sensitive to the nitrogen content of
the coal burned and that the combustion
of high-nitrogen-content coals might be
expected to result in higher NO,
emissions than those from coals with
low nitrogen contents. However, the
Administrator also recognizes that other
factors contribute to NO, levels,
including moisture in the coal, boiler
design, and boiler operating practice. In
the Administrator's judgment, the
emission limits for NO, are achievable
with properly designed and operated
boilers burning any coal, regardless of
its nitrogen content. As evidence of this,
three of the six boilers tested by EPA
burned coals with nitrogen contents
above average, and yet exhibited NO,
emission levels well below the
standards. The three boilers that burned
coals with lower nitrogen contents also
exhibited emission levels below the
standards. The Administrator believes
this is evidence that at NO, levels near
210 arid 260 ng/J (0.50 and 0.60 lb/
million Btu) heat input, factors other
than fuel-nitrogen-content predominate
in determining final emission levels.
A number of commenters expressed
concern over the potential for
accelerated tube wastage (i.e.,
corrosion) during operation of a boiler in
compliance with the proposed
standards. Almost all of the 300-hour
and 30-day coupon corrosion tests
conducted during the EPA-sponsored
low-NO, studies indicate that corrosion
rates decrease or remain stable during
operation of boilers at NO, levels as low
as those required by the standards. In
the few instances where corrosion rates
increased during low-NO, operation, the
increases were considered minor. Also,
CE has guaranteed that its new boilers
will achieve the NO, emission limits
without increased tube corrosion rates.
Another boiler manufacturer, B&W, has
developed new low-emission burners
that minimize corrosion by surrounding
the flame in an oxygen-rich atmosphere.
The other boiler manufacturers have
also developed techniques to reduce the
potential for corrosion during low-NO,
operation. The Administrator has
received no contrasting information to
the effect that boiler tube corrosion
rates would significantly increase as a
result of compliance with the standards.
• Several commenters stated that
according to a survey of utility boilers
subject to the 300 ng/J (0.70 Ib/million
Btu) heat input standard under 40 CFR
Part 60, Subpart D, none of the boilers
can achieve the standard promulgated
here of 280 ng/J (0.60 Ib/million Btu)
heat input on a range of bituminous
coals. Three of the six utility boilers
tested by EPA burned bituminous coal.
(Two of these boilers were
manufactured by CE and one by B&W.)
In addition, the Administrator has
reviewed continuously monitored NO,
data from two CE boilers that burn
bituminous coal. Finally, the
Administrator has examined NO,
emission data obtained by the boiler
manufacturers on seven CE, four B&W,
three FW, 'and three RS modern boilers,
all of which burn bituminous coal.
Nearly all of these data are below the
260 ng/I (0.60 Ib/million Btu) heat input
standard. The Administrator believes
that these data provide adequate ~
evidence that the final NO, standard for
bituminous coal is achievable by all four
boiler manufacturer designs.
An issue raised by several
commenters concerned the use of
catalytic ammonia injection and
advanced low-emission burners to
achieve NO, emission levels as low as
15 ng/J (0.034 Ib/million Btu) heat input.
Since these controls are not yet
available, the commenters
recommended that new utility boilers be
designed with sufficient space to allow
for the installation of ammonia injection
and advanced burners in the future. In
the meantime the commenters
recommended that NO, emissions be
limited to 190 ng/J (0.45 Ib/million Btu)
heat input. The Administrator believes
that the technology needed to achieve
NO, levels as low as 15 ng/J (0.034 lb/
million Btu) heat input has not been
adequately demonstrated at this time.
Although a pilot-scale catalytic-
ammonia-injection system has
successfully achieved 90 percent NO,
removal at a coal-fired utility power
plant in Japan, operation of a full-scale
ammonia-injection system has not yet
been demonstrated on a large coal-fired
boiler. Since the Clean Air Act requires
that emission control technology for new
source performance standards be
adequately demonstrated, the
Administrator cannot justify
establishing a low NO, standard based
on unproven technology. Similarly, the
Administrator cannot justify requiring
boiler designs to provide for possible
future installation of unproven
technology.
The recommendation that NO,
emissions be limited to 190 ng/J (0.45 lb/
million Btu) heat input is based on boiler
manufacturer guarantees in California.
(No such utility boilers have been built
as yet.) Although manufacturer
guarantees are appropriate to consider
when establishing emission limits, they
cannot always be used as a basis for a
standard. As several commenters have
noted, manufacturers do not always
achieve their performance guarantees.
The standard is not established at this
level, because emission test data are not
available which demonstrate that a
level of 190 ng/J (0.45 Ib/million Btu)
heat input can be continuously achieved
without adverse side effects when a
wide variety of coals are burned.

Regulatory Analysis

Executive Order 12044 (March 24,
1978), whose objective is to improve
Government regulations, requires
executive branch agencies to prepare
regulatory analyses for regulations that
may have major economic
consequences. EPA has extensively
analyzed the costs and other impacts of
these regulations. These analyses, whicn
meet the criteria for preparation of a
regulatory analysis, are contained
within the preamble to the proposed
regulations (43 FR 42154), the
background documentation made
available to the public at the time of
proposal (see STUDIES, 43 FR 42171),
this preamble, and the additional
background information document
accompanying this action ("Electric
Utility Steam Generating Units,
Background Information for
Promulgated Emission Standards," EPA-
450/3-79-021). Due to the volume of this
material and its continual development
over a period of 2-3 years, it is not
practical to consolidate all analyses into
a single document. The following
discussion gives a summary of the most
significant alternatives considered. The
rationale for the action taken for each
pollutant being regulated is given in a
previous section.
In order to determine the appropriate
form and level of control for the
standards, EPA has performed extensive
analysis of the potential national
impacts associated with the alternative
standards. EPA employed economic
models to forecast the structure and
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operating characteristics of the utility
industry in future years. These models
project the environmental, economic,
and energy impacts of alternative
standards for the electric utility
industry. The major analytical efforts
took place in three phases as described
below.
Phase 1. The initial effort comprised a
preliminary analysis completed in April
1978 and a revised assessment
completed in August 1978. These
analyses were presented in the
September 19,1978 Federal Register
proposal (43 FR 42154). Corrections to
the September proposal package and
additional information was published on
November 27,1978 (43 FR 55258).
Further details of the analyses can be
found in "Background Information for
Proposed SOt Emission Standards—
Supplement," EPA 450/2-78-007a-l.
Phase 2. Following the September 19
proposal, the EPA staff conducted
additional analysis of the economic,
environmental, and energy impacts
associated with various alternative
sulfur dioxide standards. As part of this
effort, the EPA staff met with
representatives of the Department of
Energy, Council of Economic Advisors,
Council on Wage and Price Stability,
and others for the purpose of
reexamining the assumptions used for
the August analysis and to develop
alternative forms of the standard for
analysis. As a result, certain
assumptions were changed and a
number of new regulatory alternatives
were defined. The EPA staff again
employed the economic model that was
used in August to project the national
and regional impacts associated with
each alternative considered.
The results of the phase 2 analysis
were presented and discussed at the
public hearings in December and were
published in the Federal Register on
December 8,1978 (43 FR 7834).
Phase 3. Following the public
hearings, the EPA staff continued to
analyze the impacts of alternative sulfur
dioxide standards. There were two
primary reasons for the continuing
analysis. First, the detailed analysis ;
(separate from the economic modeling)
of regional coal production impacts
pointed to a need to investigate a range
of higher emission limits.
Secondly, several comments were
received from the public regarding the
potential of dry sulfur dioxide scrubbing
systems. The phase 1 and phase 2
analyses had assumed that utilities
would use wet scrubbers only. Since dry
scrubbing costs substantially less then
wet scrubbing, adoption of the dry
technology would substantially change
the economic, energy, and
environmental impacts of alternative
sulfur dioxide standards. Hence, the
phase 3 analysis focused on the impacts
of alternative standards under a range
of emission ceilings assuming both wet
technology and the adoption of dry
scrubbing for applications in which it is
technically and economically feasible.

Impacts Analyzed
The environmental impacts of the
alternative standards were examined by
projecting pollutant emissions. The
emissions were estimated nationally
and by geographic region for each plant
type, fuel type, and age category. The
EPA staff also evaluated the waste
products that would be generated under
alternative standards.
The economic and financial effects of
the alternatives were examined. This
assessment included an estimation of
the utility capital expenditures for new
plant and pollution control equipment as
well as the fuel costs and operating and
maintenance expenses associated with
the plant and equipment. These costs
were examined in terms of annualized
costs and annual revenue requirements.
The impact on consumers was
determined by analyzing the effect of
the alternatives on average consumer
costs and residential electric bills. The
alternatives were also examined in .
terms of cost per ton of SO. removal.
'Finally, 1he present value costs of the
alternatives were calculated.
The effects of the alternative
proposals on energy production and
consumption were also analyzed.
National coal use was projected and
broken down in terms of production and
consumption by geographic region. The
amount of western coal shipped to the
Midwest and East was also estimated.
In addition, utility consumption of oil
and natural gas was analyzed.

Major Assumptions
Two types of assumptions have an
important effect on the results of the
analyses. The first group involves the
model structure and characteristics. The
second group includes the assumptions
used to specify future economic
conditions.
The utility model selected for this
analysis can be characterized as a cost
minimizing economic model. In meeting
demand, it determines the most
economic mix of plant capacity and
electric generation for the utility system,
based on a consideration of construction
and operating costs for new plants and
variable costs for existing plants. It also
determines the optimum operating level
for new and existing plants. This
economic-based decision criteria should
be kept in mind when analyzing the
model results. These criteria imply, for
example, that all utilities base decisions
on lowest costs and that neutral risk is
associated with alternative choices.
Such assumptions may not represent
the utility decision making process in all
cases. For example, the model assumes
that a utility bases supply decisions on
the cost of constructing and operating
new capacity versus the cost of
operating existing capacity.
Environmentally, this implies a tradeoff
between emissions from new and old
sources. The cost minimization
assumption implies that in meeting the
standard a new power plant will fully
scrub high-sulfur coal if this option is
cheaper than fully or partially scrubbing
low-sulfur coal. Often the model will
have to make such a decision, especially
in the Midwest where utilities can
choose between burning local high-
sulfur or imported western low-sulfur
coal. The assumption of risk neutrality
implies that a utility will always choose
the low-cost option. Utilities, however,
may perceive full scrubbing as involving
more risks and pay a premium to be able
to partially scrub the coal. On the other
hand, they may perceive risks
associated with long-range
transportation of coal, and thus opt for
full control even though partial control
is less costly.
The assumptions used in the analyses
. to represent economic conditions in a
given year have a significant impact on
the final results reached. The major
assumptions used in the analyses are
shown in Table 1 and the significance of
these parameters is summarized below.
The growth rate in demand for electric
power is very important since this rate
determines the amount of new capacity
which will be needed and thus directly
affects the emission estimates and the
projections of pollution control costs. A
high electric demand growth rate results
in a larger emission reduction
associated with the proposed standards
and also results in higher costs.
The nuclear capacity assumed to be
installed in a given year is also.
important to the analysis. Because
nuclear power is less expensive, the
model will predict construction of new
nuclear plants rather than new coal
plants. Hence, the nuclear capacity
assumption affects the amount of new
coal capacity which will be required to
meet a given electric demand level. In
practice, there are a number of
constraints which limit the amount of
nuclear capacity which can be
constructed, but for this study, nuclear
capacity-was specified approximately
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Federal Register / Vol. 44. No. 113 / Monday. June 11. 1979 / Rules and Regulations
equal to the mpderate growth
projections of the Department of Energy.
The oil price assumption has a major -
impact on the amount of predicted new
coal capacity, emissions, and oil
consumption. Since the model makes
generation decisions based on cost, a
low oil price relative to the cost of
building and operating a new coal plant
will result in more oil-fired generation
and less coal utilization. This results in
less new coal capacity which reduces
capital costs but increases oil
consumption and fuel costs because oil
is more expensive per Btu than coal.
This shift in capacity utilization also
affects emissions, since an existing oil
plant generally has a higher emission
rate than a new coal plant even when
only partial control is allowed on the
new plant.
Coal transportation and mine labor
rates both affect the delivered price of
coal. The assumed transportation rate is
generally more important to the
predicted consumption of low-sulfur
coal (relative to high-sulfur coal), since
that is the coal type which is most often
chipped long distances. The assumed
mining labor cost is more important to
eastern coal costs and production
estimates since this coal production is
generally much more labor intensive
than western coal.
Because of the uncertainty involved in
predicting future economic conditions,
the Administrator anticipated a large
number of comments from the public
regarding the modeling assumptions.
While the Administrator would have
liked to analyze each scenario under a
range of assumptions for each critical
parameter, the number of modeling
inputs made such an approach
impractical. To decide on the best
assumptions and to limit the number of
sensitivity runs, a joint working group
was formed. The group was comprised
of representatives from the Department
of Energy, Council of Economic
Advisors, Council on Wage and Price
Stability, and others. The group
reviewed model results to date,
identified the key inputs, specified the
assumptions, and identified the critical
parameters for which the degree of
uncertainty was such that sensitivity
analyses should be performed. Three
• months of study resulted in a number of
changes which are reflected in Table 1
and discussed below. These
assumptions were used in both the
phase 2 and phase 3 analyses.
After more evaluation, the joint
working group concluded that the oil
prices assumed in the phase 1 analysis
were too high. On the other hand, no
firm guidance was available as to what
oil prices should be used. In view of this,
the working group decided that the best
course of action was to use two sets of
oil prices which reflect the best
estimates of those governmental entities
concerned with projecting oil prices. The
oil price sensitivity analysis was part of
the phase 2 analysis which was
distributed at the public hearing. Further
details are available in the draft report,
"Still Further Analysis of Alternative
New Source Performance Standards for
New Coal-Fired Power Plants (docket
number IV-A-5)." The analysis showed
that while the variation in oil price
affected the magnitude of emissions,
costs, and energy impacts, price .
variation had little effect on the relative
impacts of the various NSPS alternatives
tested. Based on this conclusion, the
higher oil price was selected for
modeling purposes since it paralleled
more closely the middle range
projections by the Department of
Energy. .
Reassessment of the assumptions
made in the phase 1 analysis also
revealed that the impact of the coal
washing credit had not been considered
in the modeling analysis. Other credits
allowed by the September proposal,
such as sulfur removed by the
pulverizers or in bottom ash and flyash,
were determined not to be significant
when viewed at the national and
regional levels. The coal washing credit,
on the other hand, was found to have a
significant effect on predicted emissions
levels and, therefore, was factored into
the analysis.
As a result of this reassessment
refinements also were made in the fuel
gas desulfurization (FGD) costs
assumed. These refinements include
changes in sludge disposal costs, energy
penalties calculated for reheat, and
module sizing. In addition, an error was
corrected in the calculation of partial
scrubbing costs. These changes have
resulted in relatively higher partial
scrubbing costs when compared to full
scrubbing.
Changes were made in the FGD
availability assumption also. The phase
1 analysis assumed 100 percent
availability of FGD systems. This
assumption, however, was in conflict
with EPA's estimates on module
availability. In view of this, several
alternatives in the phase 2 analysis were
modeled at lower system availabilities.
The assumed availability was consistent
with a 90 percent availability for
individual modules when the system is
equipped with one spare. The analysis
also took into consideration the
emergency by-pass provisions of the
proposed regulation. The analysis
showed that lower reliabilities would
result in somewhat higher emissions and
costs for both the partial and full control
cases. Total coal capacity was slightly
lower under full control and slightly
higher under partial control. While it
was postulated that the lower reliability
assumption would produce greater
adverse impacts on full control than on
partial control options, the relative
differences in impacts Wi/e found to be
insignificant. Hence, the working group
discarded the reliability issue as a major
consideration in the analyzing of
national impacts of full and partial
control options. The Administrator still
believes that the newer approach better
reflects the performance of well
designed, operated, and maintained
FGD systems. However, in order to
expedite the analyses, all subsequent
alternatives were analyzed with an
assumed system reliability of 100
percent.
Another adjustment to the analysis
was the incorporation of dry SO,
scrubbing systems. Dry scrubbers were
assumed to be available for both new
and retrofit applications. The costs of
these systems were estimated by EPA's
Office of Research and Development
based on pilot plant studies and
contract prices for systems currently
under construction. Based on economic
analysis, the use of dry scrubbers was
assumed for low-sulfur coal (less than
1290 ng/J or 3 Ib SO,/million Btu)
applications in which the control
requirement was 70 percent or less. For
higher sulfur content coals, wet
scrubbers were assumed to be more
economical. Hence, the scenarios
characterized as using "dry" costs
contain a mix of wet and dry technology
whereas the "wet" scenarios assume
wet scrubbing technology only.
Additional refinements included a
change in the capital charge rate for
pollution control equipment to conform
to the Federal tax laws on depreciation,
and the addition of 100 billion tons of
coal reserves not previously accounted
for in the model.
Finally, a number of less significant
adjustments were made. These included
adjustments in nuclear capacity to
reflect a cancellation of a plant,
consideration of oil consumption in
transporting coal, and the adjustment of
costs to 1978 dollars rather than 1975
dollars. It should be understood that all
reported costs include the costs of
complying with the proposed particulate
matter standard and NO. standards, as
well as the sulfur dioxide alternatives,
The model does not incorporate the
Agency's PSD regulations nor
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forthcoming requirements to protect
visibility.

?ublic Comments
Following the September proposal, a
number of comments were received on
the impact analysis. A great number .
focused on the model inputs, which
were reviewed in detail by the joint
working group. Members of the joint
working group represented a spectrum
of expertise (energy, jobs, environment,
inflation, commerce). The following
paragraphs discuss only those
comments addressed to parts of the
analysis which were not discussed in
the preceding section.
One commenter suggested that the
costs of complying with State
Implementation Plan (SIP) regulations
and prevention of significant
deterioration requirements should not
be charged to the standards. These costs
are not charged to the standards in the
analyses. Control requirements under
PSD are based on site specific, case-by-
case decisions for which the standards
serves as a minimum level of control.
Since these judgments cannot be
forecasted accurately, no additional
control was assumed by the model
beyond the requirements of these
standards. In addition, the cost of
meeting the various SIP regulations was
included as a base cost in all the
scenarios modeled. Thus, any forecasted
cost differences among alternative
standards reflect differences in utility
expenditures attributable to changes in
the standards only.
Another commenter believed that the
time horizon for the analysis (1990/1995)
was too short since most plants on line
at that time will not be subject to the
revised standard. Beyond 1995, our data
show that many of the power plants on
line today will be approaching
retirement age. As utilization of older
capacity declines, demand will be
picked up by newer, better controlled
plants. As this replacement occurs,
national SO* emissions will begin to
decline. Based on this projection, the
Administrator believes that the 1990-
1995 time frame will represent the peak.
years for SO. emissions and is,
therefore, the relevant time frame for
this analysis.
Use of a higher general inflation rate
was suggested by one commenter. A
distinction must be made between
general inflation rates and real cost
escalation. Recognizing the uncertainty
of future inflation rates, the EPA staff
conducted the economic analysis in a
manner that minimized reliance on this"
assumption. All construction, operating,
and fuel costs were expressed as
constant year dollars and therefore the
analysis is not affected by the inflation
rate. Only real cost escalation was
included in the economic analysis. The
inflation rates will have an impact on
the present value discount rate chosen
since this factor equals the inflation rate
plus the real discount rate. However,
this impact is constant across all
scenarios and will have little impact on
the conclusions of the analysis.
Another commenter opposed the
presentation of economic impacts in
terms of monthly residential electric
bills, since this treatment neglects the
impact of higher energy costs to
industry. The Administrator agrees with
this comment and has included indirect
consumer impacts in the analysis. Based
on results of previous analysis of the
electric utility industry, about half of the
total costs due to pollution control are
felt as direct increases in residential
electric bills. The increased costs also
flow into the commercial and industrial
sectors where they appear as increased
costs of consumer goods. Since the
Administrator is unaware of any
evidence of a multiplier effect on these
costs, straight cost pass through was
assumed. Based on this analysis, the
indirect consumer impacts (Table 5)
were concluded to be equal to the
monthly residential bills ("Economic
and Financial Impacts of Federal Air
and Water Pollution Controls on the
Electric Utility Industry," EPA-230/3-
76/013, May 1978).
One utility company commented that
the model did not adequately simulate
utility operation since it did not carry
out hour-by-hour dispatch of generating
units. The model dispatches by means of
load duration curves which were
developed for each of 35 demand
regions across the United States.
Development of these curves took into
consideration representative daily load
curves, traditional utility reserve
margins, seasonal demand variations,
and historical generation data. The
Administrator believes that this
approach is adequate for forecasting
long-term impacts since it plans for
meeting short-term peak demand
requirements.

Summary of Results
The Final results of the analyses are
presented in Tables 2 through 5 and
discussed below. For the three
alternative standards presented,
emission limits and percent reduction
requirements are 30-day rolling
averages, and each standard was
analyzed with a paniculate standard of
13 ng/I (0.03 Ib/million Btu) and the
proposed NO, standards. The full
control option was specified as a 520
ng/| (1.2 Ib/million Btu) emission limit
with a 90 percent reduction in potential
SOi emissions. The other options are the
.same as full control except when the
emissions to the atmosphere are
reduced below 260 ng/J (0.6 Ib/million
Btu) in which case the minimum percent
reduction requirement is reduced. The
variable control oition requires a 70
percent minimum reduction and the
partial control option has a 33 percent
minimum reduction requirement. The
impacts of each option were forecast
first assuming the use of wet scrubbers
only and then assuming introduction of
dry scrubbing technology. In contrast to
the September proposal which focused
on 1990 impacts, the analytical results
presented today are for the year 1995.
The Administrator believes that 1995
better represents the differences among
alternatives since more new plants
subject to the standard will be on line
by 1995. Results of the 1990 analyses are
available in the public record.
Wet Scrubbing Results

The projected SO* emissions from
utility boilers are shown by plant type
and geographic region in Tables 2 and 3.
Table 2 details the 1995 national SOi
emissions resulting from different plant
types and age groups. These standards
will reduce 1995 SO> emissions by about
3 million tons per year (13 percent) as
compared to the current standards. The
emissions from new plants directly
affected by the standards are reduced
by up to 55 percent. The emission
reduction from new plants is due in part
to lower emission rates and in part to
reduced coal consumption predicted by
the model. The reduced coal
consumption in new plants results from
the increased cost of constructing and
operating new coal plants due to
pollution controls. With these increased
costs, the model predicts delays in
construction of new plants and changes
in the utilization of these plants after
start-up. Reduced coal consumption by
new plants is accompanied by higher
utilization of existing plants and
combustion turbines. This shift causes
increased emissions from existing coal-
and.oil-fired plants, which partially
offsets the emission reductions achieved
by new plants subject to the standard.
Projections of 1995 regional SOi
emissions are summarized in Table 3.
Emissions in the East are reduced by
about 10 to 13 percent as compared to
predictions under the current standards.
whereas Midwestern emissions are
reduced only slightly, The smaller
reductions in the Midwest are due to a
slow growth of new coal-fired capacity.
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In general, introductions of coal-fired
capacity tends to reduce emissions since
new coal plants replace old coal- and
oil-fired units which have higher
emission rates. The greatest emission
reduction occurs in the West and West
South Central regions where significant
growth is expected and today's
emissions are relatively low. For these
two regions combined, the full control
option reduces emissions by 40 percent
from emission levels under the current
otandards, while the partial and variable
options produce reductions of about 30
percent.
Table 4 illustrates the effect of the
proposed standards on 1995 coal
production, western coal shipped east,
and utility oil and gas consumption.
National coal production is predicted to
triple by 1995 under all the alternative
standards. This increased demand
raises production in all regions of the
country as compared to 1975 levels.
Considering these major increases in
national production, the small
production variations among the
alternatives are not large. Compared to
production under the current standards,
production is down somewhat in the
West, Northern Great Plains, and
Appalachia, while production is up in
the Midwest. These shifts occur because
of the reduced economic advantage of
low-sulfur coals under the revised
etandards. While three times higher than
1975 levels, western coal shipped east is
lower under all options than under the
current standards.
Oil consumption in 1975 was 1.4
million barrels per day. The 3.1 million
barrels per day figure for 1975
consumption in Table 4 includes utility
natural gas consumption (equivalent of
1.7 million barrels per day) which the
analysis assumed would be phased out
by 1990. Hence, in 1995, the 1.4 million
barrel per day projection under current
standards reflects retirement of existing
oil capacity and offsetting increases in
consumption due to gas-to-oil
conversions.
Oil consumption by utilities is
predicted to increase under all the
options. Compared to the current
standards, increased consumption is
200,000 barrels per day under the partial
and variable options and 400,000 barrels
per day under full control. Oil
consumption differences are due to the
higher costs of. new coal plants under
these standards, which causes a shift to
more generation from existing oil plants
and combustion turbines. This shift in
generation mix has important
implications for the decision-making
process, since the only assumed
constraint to utility oil use was the
price. For example, if national energy
policy imposes other constraints which
phase out or stabilize oil use for electric
power generation, then the differences
in both oil consumption and oil plant
emissions (Table 2} across the various
etandards will be mitigated.
Constraining oil consumption, however,
will spread cost differences among
standards.
The economic effects in 1995 are
shown in Table 5. Utility capital
expenditures increase under all options
as compared to the $770 billion
estimated to be required through 1995 in
the absence of a change in the standard.
The capital estimates in Table 5 are
increments over the expenditures under
the current standard and include both
plant capital (for new capacity] and
pollution control expenditures. As
shown in Table 2, the model estimates
total industry coal capacity to be about
17 GW (3 percent) greater under the
non-uniform control options. The cost of
this extra capacity makes the total
utility capital expenditures higher under
the partial and variable options, than
under the full control option, even
though pollution control capital is lower.
Annualized cost includes levelized
capital charges, fuel costs, and
operation and maintenance costs
associated with utility equipment. All of
the options cause an increase in
annualized cost over the current
standards'. This increase ranges from a
low of $3.2 billion for partial control to
$4.1 billion for full control, compared to
the total utility annualized costs of
about $175 billion.
The average monthly bill is
determined by estimating utility revenue
requirements which are a function of
capital expenditures, fuel costs, and
operation and maintenance costs. The
average bill is predicted to increase only
slightly under any of the options, up to a
maximum 3-percent increase shown for
full control. Over half of the large total
increase in the average monthly bill
over 1975 levels ($25.50 per month) is
due to a significant increase in the
amount of electricity used by each
customer. Pollution control
expenditures, including those to meet
the current standards, account for about
15 percent of the increase in the cost per
kilowatt-hour while the remainder of the
cost increase is due to capital intensive
capacity expansion and real escalations
in construction and fuel cost.
Indirect consumer impacts, range from
$1.10 to $1.60 per month depending on
the alternative selected. Indirect
consumer impacts reflect increases in
consumer prices due to the increased
energy costs in the commercial and
industrial sectors.
The incremental costs per ton of SO,
removal are also shown in Table 5. The
figures are determined by dividing the
change in annualized cost by the change
in annual emissions, as compared to the
current standards. These ratios are a
measure of the cost effectiveness of the
options, where lower ratios represent a
more efficient resource allocation. All
the options result in higher cost per ton
than the current standards with the full
control option being the most expensive.
Another measure of cost effectiveness
is the average dollar-per-ton cost at the
plant level. This figure compares total
pollution control cost with total SO»
emission reduction for a model plant.
This average removal cost varies
depending on the level of control and
the coal sulfur content. The range for full
control is from $325 per ton on high-
sulfur coal to $1,700 per ton on low-
sulfur coal. On low-sulfur coals, the
partial control cost is $2,000 per ton, and
the variable cost is $1,700 per ton.
The economic analyses also estimated
the net present value cost of each
option. Present value facilitates
comparison of the options by reducing
the streams of capital, fuel, and
operation and maintenance expenses to
one number. A present value estimate
allows expenditures occurring at
different times to be evaluated on a
similar basis by discounting the
expenditures back to a fixed year. The
costs chosen for the present value
analysis were the incremental utility
revenue requirements relative to the
current NSPS. These revenue
requirements most closely represent the
costs faced by consumers. Table 5
shows that the present value increment
for 1995 capacity is $41 billion for full
control, $37 billion for variable control,
and $32 billion for partial control.
Dry Scrubbing Results

Tables 2 through 5 also show the
impacts of the options under the
assumption that dry SOt scrubbing
systems penetrate the pollution control
market. These analyses assume that
utilities will install dry scrubbing
systems for all applications where they
are technologically feasible and less
costly than wet systems. (See earlier
discussion of assumptions.)
The projected SOi emissions from
utility boilers are shown by plan type
and geographic region in Tables 2 and 3.
National emission projections are
similar to the wet scrubbing results.
Under the dry control assumption,
however, the variable control option is
predicted to have the lowest national
IV-311
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EogSotag / Vol. 44. No. 113 / Monday. June 11. 1970 / Rules and Regulations
emissions primarily due to lower oil
plant emissions relative to the full
control option. Partial control produces
more emissions than, variable control
because of higher emissions from new
plants. Compared to the current
otandards, regional emission impacts
are also similar to the wet scrubbing
projections. Full control results in the
lowest emissions in the West, while
variable control results in the lowest
emissions in the East. Emissions in the
Midwest and West South Central are
relatively unaffected by the options.
Inspection of Tables 2 end 3 shows
that with the dry control assumption the
current standard, full control, and
partial control cases produce slightly
higher emissions than the corresponding
wet control cases. This is due to several
factors, the most important of which is a
shift in the generation mix. This shift
occurs because dry scrubbers have
lower capital costs and higher variable
costs than wet scrubbers and, therefor,
the two systems have different effects
on the plant utilization rates. The higher
variable costs are due primarily to
transportation charges on intermediate
-to low sulfur coal which must be used
with dry scrubbers. The increased
variable cost of dry controls alters the
dispatch order of existing plants so that
older, uncontrolled plants operate at
relatively higher capacity factors than
would occur under the wet scrubbing
assumption, hence increasing total
emissions. Another factor affecting
emissions is utility coal selection which
may be altered by differences in
pollution control costs.
Table 4 shows the effect to the
proposed standards on fuels in 1S95.
National coal production remains '
essentially the same whether dry or wet
controls are assumed. However, the use
of dry controls causes a slight
reallocation in regional coal production,
except under a full control option where
dry controls cannot be applied to new
plants. Under the variable and partial
options Appalachian production
increases somewhat due to greater
demand for intermediaTe sulfur coals
while Midwestern coal production •
declines slightly. The non-uniform
options also result in a small shifting in
the western regions with Northern Great
Plains production declining and
production in the rest of West
increasing. The amount of western coal
shipped east under the current standard
is reduced from 122 million to 89 million
tons (20% decrease) due to the increased
use of eastern intermediate sulfur coals
for dry scrubbing applications. Western
coal shipped east is reduced further by
the revised standards, to a low of §5
million tons under full control. Oil
impacts under the dry control
assumption are identical to the wet
control cases, with full control resulting
in increased consumption of 200
thousand barrels per day relative to the
partial and variable options.
The 1S95 economic effects of these
otandards are presented in Table 5. In
general, the dry control assumption
results in lower costs. However, when
comparing the dry control costs to the
wet control figures it must be kept in -
mind that the cost base for comparison,
the current standards, is different under
the dry control and wet control
assumptions. Thus, while the
uncremental costs of full control are
higher under the dry scrubber
assumption the total costs of meeting
the standard is lower than if wet
controls were used.
The economic impact figures show
that when dry controls are assumed the
cost savings associated with the
variable and partial options is
significantly increased over the wet
control cases. Relative to full control the
partial control option nets a savings of
§1.4 billion in annualized costs which
equals a $14 billion net present value
savings. Variable control results in &
§1.3 billion annualized cost savings
which is a savings of $12 billion in net
present value. These changes in utility
costs affect the average residential bill
only slightly, with partial control
resulting in a savings of $.50 per month
and variable control savings of $.40 per
month on the average bill, relative to full
control.
One finding that has been clearly
demonstrated by the two years of
analysis is that lower emission
•standards on new plants do not
necessarily result in lower national SOa
emissions when total emissions from the
entire utility system are considered.
There are two reasons for this finding.
First, the lowest emissions tend to result
from strategies that encourage the
construction of new coal capacity. This
capacity, almost regardless of the -
alternative analyzed, will be less
polluting than the existing coal- or oil-
fired capacity that it replaces. Second,
the higher cost of operating the new
capacity (due to higher pollution costs)
may cause the newer, cleaner plants to
be utilized less than they would be
under a less stringent alternative. These
situations are demonstrated by the
analyses presented here.
The variable control option produces
emissions that are equal to or lower
than the other options under both the
wet and dry scrubbing assumptions.
Compared to full control, variable
control is predicted to result in 12 GW to
17 GW more coal capacity. This
additional capacity replaces dirtier
existing plants and compensates for the
slight increase in emissions from new
plants subject to the standards, hence
causing emissions to be less than or '
equal to full control emissions
depending on scrubbing cost assumption
(i.e., wet or dry). Partial control and
variable control produce about the same
coal capacity, but the additional 300
thousand ton emission reduction from
• new plants causes lower total emissions
under fhe variable option. Regionally, all
the options produce about the same
emissions in the Midwest and West
South Central regions. Full control
produces 200 thousands tons less
emissions in the West than the variable
option and 300 thousand tons less than
partial control. But the variable and
partial options produce between 200 and
300 thousand tons less emissions in the
East.
The variable and partial control
options have a clear advantage over full
control with respect to costs under both
the wet and dry scrubbing assumptions.
Under the dry assumption, which the
Administrator believes represents the
best prediction of utility behavior,
variable control saves about $1.1 billion
per year relative to full control and
partial control saves an additional $0.3
' billion.
All the options have similar impacts
on coal production especially when
considering the large increase predicted
over 1975 production levels. With
respect to oil consumption, however, the
full control option causes a 200,000
barrel per day increase as compared to
both the partial and variable options.
Based on these analyses, the
Administrator has concluded that a non-
uniform control strategy is best
considering the environmental, energy,
and economic impacts at both national
and regional levels. Compared to other
options analyzed, the variable control
standard presented above achieves the
lowest emissions in an efficient manner
and will not disrupt local or regional
coal markets. Moreover, this option
avoids the 200 thousand barrel per day
oil penalty which has been predicted
under a number of control options. FOF
these reasons, the Administrator
believes that the variable control optics
provides the best balance of national
environmental, energy, and economic
objectives.
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TeMo 1.—Aty Modeling Assumptions
Assumption
Growth rttM..._.

Nudeercepecey.
CM prices (S 1975)-
Codln
Ktaboi
Cod mining tl»r coats—
Ccpttal charge rate.
Cost icooftiig bcitii.
FGDoocts —
1875-1965 4.8%/vr.
1965-1995: 4.0%.
1965: 97 QW.
1990: 165.
1995: 226.
1985: $12.90/bbL
1990: $16.40.
1995: $21.00.
1% per year red Incrceaa.
U.M.W. wtttoment end 1* red inert
Cod decning cnxtt..

Bottom ash end fly ash content.,
i thereafter.
12.5% for Rotation ooosrol opcndourm.
1978 (totem
No change from phase 2 enclyife except for the tddStkxi Of dry
' scrubbing systems for oertdn epptieatons.
5%-35% SO, reducton cammed for high euKur bKummoiB cads
only.
No croon •tssunwo.
Tebie I—National 1995 SO, Emissions Frvm Utility Boilers •

{man tons]
Level ol control'
1975 Current standards
actual

New Plants ',„„„, ,
O3 Plants

ToW National

TotdCod
Ccpedly (QW) 205
Budge generated (miSon
Ions dry) _._„_.._
165
7.1
1.0
23.7
652
23
ay
154
7.0
1.0
23.8
654
27
Fun control
Wet
16.0
J.1
1.4
20.6
521
96
Dry
162
S.1
1.4
10.7 .
520
S3
fcitfflJ contiol
33% minimum
Wtt Dry
15.9 162
94 3.4
14 12
104 t04
634 S37
43 39
Vcrtsbw ooflfirol
70% minimum
MM
16.0
84
14
20.6
533
SO
Dry
16.1
12
20.5
537
41
•Results of loint EPA/DOE analyses completed kt May 1979 based on o9 prices of J1Z90, $16.40, and K1JOM& In the
yeas 1965.1990. end 1995. respectively.
'Wtth 520 ng/J maximum emission tmtt.
< Plants subject to existing State regulations or the current NSPS of 121> SCVmMon BTU.
'Based on wet SO, scrubbing costs.
• Based on dry SO, scrubbing costs where tppticrbta.
'Plants subject to the revised standards.
TcMe 3.—fte&oncl 1995 SO, Emissions From Utility Boilers •

[Mutton torn)

Level o) control*
1975
ectud
Currant standard!
FuElconM
Ptfttfil control
33% minimum
Vtyicbw control
70% minimum
TotdNationd
23.7
Dry

tO.7
204
3»y Wet Dry

204 204 20.5
Regtond Emissions:
EM*'
Midweot'
West South Centre! •
Wed *
112
0.1
2.6
— 1.7
2.6
1.7
10.1
74
1.7
, 04
10.1
74
1.7
04
94
74
14
12
•4
OJ>
14
•4
74
14
1.1
•7
0.0
1.7
1.1
TotdCod
Capacity (GW)..
205
652
S54
621
620
S34
637
633
637
• Results of |oM EPA/DOE analyses completed in May 1979 based on o9 prices of $1i»0, $16.40. end *21.00/bbl In the
years 1985. t990. and 1995, respectively.
> With 520 ng/J maximum emission ImH.
' Based on wet SO, scrubbing costs.
' Based on dry SO, scrubbing costs where applicable.
• New England, Middle Atlantic, South Atlantic, and East South CtnM Ctnan Ra^oro.
'East North Central and West North Central Census Regions.
•West South Central Census Region.
• Mountain end Pedfc Census Regtam.
Performance Tenting

Particulate Matter
The final regulations require that
Method 5 or 17 under 40 CFR Part 60,
Appendix A, be used to determine
compliance with the participate matter
emission limit. Particulate matter may
be collected with Method 5 at an
outstack niter temperature up to 160 C
(320 F); Method 17 may be used when
stack temperatures are less than 160 C
(320 F). Compliance with the opacity
standard in the final regulation is
determined by means of Method 9,
under 40 CFR Part 60, Appendix A. A
transmissometer that meets
Performance Specification 1 under 40
CFR Part 60, Appendix B is required.
Several comments were received
which questioned the accuracy of
Methods 5 and 17 when used to measure
participate matter at the level of the
otandard. The accuracy of Methods 5
and 17 is dependent on the amount of
sample collected and not the
concentration in the gas stream. To
maintain an accuracy comparable to the
accuracy obtained when testing for
mass emission rates higher than the
standard, it is necessary to sample for
longer times. For this reason, the
regulation requires a minimum sampling
time of 120 minutes and a minimum
sampling volume of 1.7 dscm (60 dscf).
Three comments raised the issue of
potential interference of acid mist with
the measurement of particulate matter.
The Administrator recognized this issue
prior to proposal of the regulations. In
the preamble to the proposed
regulations, the Administrator indicated
that investigations would continue to
determine the extent of the problem. A
series of tests at an FGD-equipped
facility burning 3-percent-sulfur coal
indicate that the amount of sample
collected using Method 5 procedures io
temperature sensitive over the range of
filter temperatures used (250* F to 380*
F), with reduced weights at higher
temperatures. Presumably, the
decreased weight at higher filter
temperatures reflect vaporization of acid
mist. Recently received particulate
emission data using Method 5 at 32* F
for a second coal-fired power plant
equipped with an electrostatic
precipitator and an FGD system
apparently conflicts with the data
generated by EPA. For this plant,
particulate matter was measured at 0.02
Ibs/million Btu. It is not known what
portion of this particulate matter, if any
was attributable to sulfuric acid mist.
The intent of the particulate matter
standard is to insure the installation,
operation, and maintenance of a good
IV-313
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Tabto 4—Impacts on Fuels In 199?
Level of control •
1975 Current standards
•dual
fun control Partial control
33% fTunhnum
Variable control
70% minimum
Dry'
Dry
Wet
Oft
Wat
Dry
US. Coal Production (mMon
tons):
^ppglyhif
Midwest
Northern Great Plains....
Wtfft

Total
Western Coal Shipped East
(million tons)
Ol Consumpton by Power
Plants (million bbl/day):
Power Plants _ _
Coal Transportabon.._-__

396
151
54
46

647

489
404
ess
" 230

1.778

122

12
02

524
391
630
222

1.767

1.2
02

463
487
633
182

1,765

1.6
02

465
488
628
180

1.761

1.6
02

475
4S6
622
212

1,765

1.4
0.2

486
452
676
228

1,742

1.4
02

470
465
632
203

1.770

1.4
02

484
450
602
217

1,752

1.4
0.2
Total.—
.3.1
1.4
1.4
1.8
1.8
1.6
1.6
1.6
1.6
• Results ol EPA analyses completed in May 1979 based on ol prices of $12.90. $16.40, and $21.00/bbl In the years 1885,
1990. and 1995. respectively.
• With 520ng/J maximum emission Hrnrt
< Based on wet SO, scrubbing costs.
• Based on dry SOi scrubbing where applicable.
Tabte &.—1995 Economic Impacts •

(1978 dollars)

Level of control'"
Currant standards Ft* control
Average Monthly Residential Bills ($/
month) _...««...«»...««»..».»
Indirect Consumer Impacts ($/month) .. _
Incremental Utility Capital Expendi-
tures. Cumulative 1976-1995 ($ bil-
lons)
Incremental Anruabed Cost ($ bi-
llons)
Present Value ol Incremental Utility
Incremental Cost ol SO' Reduction ($/
*"")

WW Dry' Wei
$53.00 $52.85 $54.50
.,.„,. .,...,...„.„„„ 1.50
,„„ 4
41
41
1,3??

Dry
$54.45
1.60
5
4.4
45
1,428
Partial control
33% minimum
Wet
$54.15
1.15
6
32
32
1,094
Dry
$53.95
1.10
-3
3.0
31
1.012
Variable control
70% minimum
Wet
$54.30
1.30
10
3.6
37
1,163
Dry
$54.05
120
-1
3.3
33
1,036
• Results ol EPA analyses completed in May 1979 based on ol prices of $12.90, $1&40. and $21.00/bM In the yean 1985.
1990, and 1995, respectively.
With 520 ng/J maximum erru&ion lirrut.
' Based on wet SO, scrubbing costs.
• Based on dry SO, scrubbing costs where applicable.
emission control system. Since
technology is not available for the
control of sulfuric acid mist, which is
condensed in the FGD system, the
Administrator does not believe the
paniculate matter sample should
include condensed acid mist. The final
regulation, therefore, allows particulate
matter testing for compliance between
the outlet of the particulate matter
control device and the inlet of a wet
FGD system. EPA will continue to
investigate revised procedures to
minimize the measurement of acid mist
by Methods 5 or 17 when used to
measure particulate matter after the
FGD system. Since technology is
available to control particulate sulfate
carryover from an FGD system, and the
Administrator believes good mist
eliminators should be included with all
FGD systems, the regulations will be
amended to require particulate matter
measurement after the FGD system
when revised procedures for Methods 5
or 17 are available.

SO, and NO.

The final regulation requires that
compliance with the sulfur dioxide and
nitrogen oxides standards be
determined by using continuous
monitoring systems (CMS) meeting
Performance Specifications 2 and 3,
under 40 CFR Part 60, Appendix B. Data -
from the CMS are used to calculate a 30-
day rolling average emission rate and
percentage reduction (sulfur dioxide
only) for the initial performance test
required under 40 CFR 60.8. At the end
of each boiler operating day after the
initial performance test a new 30-day
rolling average emission rate for sulfur
dioxide and nitrogen oxides and an
average percent reduction for sulfur
dioxide are determined. The final
regulations specify the minimum amount
of data that must be obtained for each
30 successive boiler operating days but
requires the calculation of the average
emission rate and percentage reduction
based on all available data. The
minimum data requirements can be
satisfied by using the Reference
Methods or other approved alternative
methods when the CMS, or components
of the system, are inoperative.
The final regulation requires operation
of the continuous monitors at all times,
including periods of startup, shutdown,
malfunction (NO, only), and emergency
conditions (SO* only), except for those
periods when the CMS is inoperative
because of malfunctions, calibration or
span checks.
The proposed regulations would have
required that compliance be based on
the emission rate and percent reduction
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(sulfur dioxide only) for each 24-hour
period of operation. Continual
determination of compliance with the
proposed standard would have
necessitated that each source owner or
operator install redundant CMS or
conduct manual testing in the event of
CMS malfunction.
Comments on the proposed testing
requirements for sulfur dioxide and
nitrogen oxides indicated that CMS
could not operate without malfunctions;
therefore, every facility would require
redundant CMS. One commenter
calculated that seven CMS would be
needed to provide the required data.
Comments also questioned the
practicality and feasibility of obtaining
around-the-clock emissions data by
means of manual testing in the event of
CMS malfunction. The commenter
stated that the need for immediate
backup testing using manual methods
would require a stand-by test team at all
times and that extreme weather
conditions or other circumstances could
often make ifimpossible for the test
team to obtain the required data. The
Administrator agrees with these
comments and has redefined the data
requirements to reflect the performance
that can be achieved with one well-
maintained CMS. The final requirements
are designed to eliminate the need for
redundant CMS and minimize the
possibility that manual testing will be
necessary, while assuring acquisition of
sufficient data to document compliance.
Compliance with the emission
limitations for sulfur dioxide and
nitrogen oxides and the percentage
reduction for sulfur dioxide is
determined from all available hourly
averages, except for periods of startup,
shutdown, malfunction or emergency
conditions for each 30 successive boiler
operating days. Minimum data
requirements have been established for
hourly averages, for 24-hour periods, •
and for the 30 successive boiler
operating days. These minimum
requirements eliminate the need for
redundant CMS and minimize the need
for testing using manual sampling
techniques. The minimum requirements
apply separately to inlet and outlet
monitoring systems.
The regulation allows calculation of
hourly averages for the CMS using two
or more of the required four data points.
This provision was added to
accommodate those monitors for which
span and calibration checks and minor
repairs might require more than 15
minutes.
For any 24-hour period, emissions
data must be obtained for a minimum of
75 percent of the hours during which the
affected facility is operated (including
startup, shutdown, malfunctions or
emergency conditions). This provision
was added to allow additional time for
CMS calibrations and to correct minor
CMS problems, such as a lamp failure, a
plugged probe, or a soiled lens.
Statistical analyses of data obtained by
EPA show that there is no significant
difference (at the 95 percent confidence
interval) between 24-hour means based
on 75 percent of the data and those
based on the full data set.
To provide time to correct major CMS
malfunctions and minimize the
possibility that supplemental testing will
be needed, a provision has been added
which allows the source owner or
operator to demonstrate compliance if
the minimum data for each 24-hour
period has been obtained for 22 of the 30
successive boiler operating days. This
provision is based on EPA studies that
have shown that a single pair of CMS
pollutant and diluent monitors can be
made available in excess of 75 percent
of the time and several comments
showing CMS availability in excess of
90 percent of the time.
In the event a CMS malfunction would
prevent the source owner or operator
from meeting the minimum data
requirements, the regulation requires
that the reference methods or other
procedures approved by the
Administrator be used to supplement
the data. The Administrator believes,
however, that a single properly
designed, maintained, and operated
CMS with trained personnel and an
appropriate inventory of spare parts can
achieve the monitoring requirements
with currently available CMS
equipment. In the event that an owner or
operator fails to meet the minimum data
requirements, a procedure is provided
which may be used by the
Administrator to determine compliance
with the SO, and NO, standards. The
procedure is provided to reduce
potential problems that might arise if an
owner or operation is unable to meet the
minimum data requirements or attempts
to manipulate the acquisition of data so
as to avoid the demonstration of
noncompliance. The Administrator
believes that an owner or operator
should not be able to avoid a finding of
. noncompliance with the emission
standards solely by noncompliance with
the minimum data requirements.
Penalties related only to failure to meet
the minimum data requirements may be
less than those for failure to meet the
emission standards and may not provide
as great an incentive to maintain
compliance with the regulations.
The procedure involves the
calculation of standard deviations for
the available inlet SOS monitoring data
and the available outlet SO2 and NO,
monitoring data and assumes the data
are normally distributed. The standard
deviation of the inlet monitoring data for
SOa is used to calculate the upper
confidence limit of the inlet emission
rate at the 95 percent confidence
interval. The upper confidence limit of
the inlet emission rate is used to
determine the potential combustion
concentration and the allowable
emission rate. The standard deviation of
the outlet monitoring data for SO, and
NO, are used to calculate the lower
confidence limit of the outlet emission
rates at the 95 percent confidence
interval. The lower confidence limit of
the outlet emission rate is compared
with the allowable emission rate to
determine compliance. If the lower
confidence limit of the outlet emission
rate is greater than the allowable
emission rate for the reporting period,
the Administrator will conclude that
noncompliance has occurred.
The regulations require the source
owner or operator who fails to meet the
minimum data requirements to perform
the calculations required by the added
procedure, and to report the results of
the calculations in the quarterly report.
The Administrator may use this
information for determining the
compliance status of the affected
facility.
It is emphasized that while the
regulations permit a determination of
the compliance status of a facility in the
absence of data reflecting some periods
of operation, an owner and operator is
required by 40 CFR 60.11(d) to continue
to operate the facility at all times so as
to minimize emissions consistent with
good engineering practice. Also, the
added procedure which allows for a
determination of compliance when less
than the minimum monitoring data have
been obtained does not exempt the
source owner or operator from the
minimum data requirements. Exemption
from the minimum data requirements
could allow the source owner to
circumvent the standard, since the
added procedure assumes random
variations in emission rates.
One commenter suggested that
operating data be used in place of CMS
data to demonstrate compliance. The
Administrator does not believe,
however, that the demonstration of
compliance can be based on operating
data alone. Consideration was given to
the reporting of operating parameters
during those periods when emissions
data have not been obtained. This
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alternative was rejected because it
would mean that the source owner or
operator would need to record the
operating parameters at all times, and
would impose an administrative burden
on source owners or operators in
compliance with the emission
monitoring requirements. The regulation
requires the owner or operator to certify
that the emission control systems have
been kept in operation during periods
when emissions data have not been
obtained.
Several commenters indicated that
CMS were not sufficiently accurate to
allow for a determination of compliance.
One commenter provided calculations
showing that the CMS could report an
FGD efficiency ranging from 77.5 to 90
percent, with the scrubber operating at
an efficiency of 85 percent The analysis
submitted by the commenler is
theoretically possible for any single data '
point generated by the CMS. For the 30-
day averaging periods, however, random
variations in individual data points are
not significant. The criterion of
importance in showing compliance for
this longer averaging time is the
difference between the mean values
measured by the CMS and the reference
methods. EPA is developing quality
assurance procedures, which will
require a periodic demonstration that
the mean emission rates measured by
the CMS demonstrates a consistent and
reproducible relationship with the mean
emission rates measured by the
reference methods or acceptable
modifications of these methods.
A specific comment received on the
monitoring requirements questioned the
need to respan the CMS for sulfur
dioxide when the sulfur content of the
fuel changed by 0.5 percent The intent
of this requirement was to assure that a
change in fuel sulfur content would not
result in emissions exceeding the range
of the CMS. This requirement has been
deleted on the premise that the source
owner or operator will initiate his own
procedures to protect himself against
loss of data.
Several comments were also received
concerning detailed technical items
contained in Performance Specifications
2 and 3. One comment, for example,
suggested that a single "relative
accuracy" specification be used for the
entire CMS, as opposed to separate
values for the pollutant and diluent
monitors. Another comment questioned
the performance specification on
instrument response time, while still
other comments raised questions on
'calibration procedures. EPA is in the
process of revising Performance
Specifications 2 and 3 to respond to
these, and other questions. The current
performance specifications, however,
are adequate for the determination of
compliance.
Fuel Pretreatment
The final regulation allows credit for
fuel pretreatment to remove sulfur or
increase heat content. Fuel pretreatment
credits are determined in accordance
with Method 19. This means that coal or
oil may be treated before firing and the
sulfur removed may be credited toward
meeting the SO* percentage reduction
requirement The final fuel pretreatment
provisions are the same as those
proposed.
Most all oommenters on this issue
supported the fuel pretreatment
crediting procedure* proposed by EPA.
Several commenters requested that
credit also be given for sulfur removed
in the coal bottom ash and fly ash. This
is allowed under the final regulation and
was also allowed under the proposal in
the optional "as-fired" fuel sampling
procedures under the SO, emission
monitoring requirements. By monitoring
SOS emissions {ng/J, Ib/million Btuj with
an as-fired fuel sampling system located
upstream of coal pulverizers and with
an in-slack continuous SO> monitoring
system downstream of the FGD system,
sulfur removal credits are combined for
the coal pulverizer, bottom ash. fly ash
and FGD system into one removal
efficiency. Other alternative sampling
procedures may also be submitted to the
Administrator for approval.
Several commenters indicated that
they did not understand the proposed
fuel pretreatment crediting procedure for
refined fuel oil. The Administrator
intended to allow fuel pretreatment
credits for all fuel oil desulfurizaiion
processes used in preparation of utility
boiler fuels. Thus, the input and output
from oil desulfurization processes (e.g.,
hydrotreatment units) that are used to
pretreat utility boiler fuels used in
determining pretreatment credits. If
desulfurized oil is blended with
undesulfurized oil, fuel pretreatment
credits are prorated based on heat input
of oils blended. The Administrator
believes that the oil input to the
desulfurizer should be considered the
input for credit determination and not
the well head crude oil or input oil to the
refinery. Refining of crude oil results in
the separation of the base stock into
various density fractions which range
from lighter products such as naphtha
and distillate oils. Most of the sulfur
from the crude oil is bound to the
heavier residual oils which may have a
sulfur content of twice the input crude
oil. The residual oils can be upgraded to
a lower sulfur utility steam generator
fuel through the use of desulfurization
technology {such as
hydrodesulfurization). The
Administrator believes that it is
appropriate to give full fuel pretreatment
credit for hydrotreatment units and not
to penalize hydrodesulfurization units
which are used to process high-sulfur
residual oils. Thus, the input to the
hydrodesulfurization unit is need to
determine oil pretreatment credits and
not 1he kywer sulfur refinery input crude.
This procedure will allow full credit for
residual oil hydrodesulfurization units.
In relation to fuel pretreatment credits
for coal, commenters requested that
sampling be allowed prior to the initial
coal breaker. Under the final standards.
coal sampling may be conducted at any
location (either before or after the initial
coal breaker). It is desirable to sample
coal after the initial breaker because the
smaller coal volume and coal size will
reduce sampling requirements under
Method 19. If sampling were conducted
before the initial breaker, rock removed
by the coal breaker would not result in
any additional sulfur removal credit
Coal samples are analyzed to determine
potential SO, emissions in ng/J (lb/
million Btu) and any removal of rock or
other similar reject material will not •
change the potential SO* emission rate
(ng/J; Ib/million Btu).
An owner or operator of an affected
facility who elects to use fuel
pretreatment credits is responsible for
insuring that the EPA Method 19
procedures are followed in determining
SOj removal credit for pretreatment
equipment.

Miscellaneous

Establishment of standards of
performance for electric utility steam
generating units was preceded by the
Administrator's determination that these
sources contribute significantly to air
pollution which causes or contributes to
the endangerment of public health or
welfare (36 FR 5931). and by proposal of
regulations on September 19,1978 (43 FR
42154). In addition, a preproposal public
hearing (May 25-26,1977) and a
postpropo&al public hearing (December
12-13,1978) was held after notification
was given in the Federal Register. Under
section 117 of the Act, publication of
these regulations was preceded by
consultation with appropriate advisory
committees, independent experts, and
Federal departments and agencies.
Standards of performance for new
fossil-fuel-fired stationary sources
established under section 111 of the
Clean Air Act reflect:
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Application of the best technological
oyttem of continuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated, [section lll(a)(l)]

Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be selected as the basis of standards of
performance due to costs associated
with its use. Accordingly, standards of
performance should not be viewed as
the ultimate in achievable emission
control. In fact, the Act requires (or has
potential for requiring) the imposition of
a more stringent emission standard in
oeveral situations.
For example, applicable costs do not
play as prominent a role in determining
the "lowest achievable emission rate"
for new or modified sources located in
nonattainment areas, i.e., those areas
where statutorily-mandated health and
welfare standards are being violated. In
this respect, section 173 of the Act
requires that a new or modified source
constructed in an area that exceeds the
National Ambient Air Quality Standard
(NAAQS) must reduce emissions to the
level that reflects the "lowest
achievable emission rate" (LAER), as
defined in section 171(3), for such source
category. The statute defines LAER as
that rate of emission which reflects:
'(A) The most stringent emission
limitation which is contained in the
implementation plan of any State for
ouch class or category of source, unless
the owner or operator of the proposed
source demonstrates that such
limitations are not achievable, or
(B) The most stringent emission
limitation which is achieved in practice
by such class or category of source,
whichever is more stringent.
In no event can the emission rate
exceed any applicable new source
performance standard [section 171(3)].
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (Part C). These provisions
require that certain sources (referred to
in section 169(1)] employ "best available
control technology" [as defined in
section 169(3)] for all pollutants
regulated under the Act. Best available
control technology (BACT) must be
determined on a case-by-case basis,
taking energy, environmental and
economic impacts, and other costs into
account. In no event may the application
of BACT result in emissions of any
pollutants which will exceed the
emissions allowed by any applicable
standard established pursuant to section
111 (or 112) of the Act.
In all events, State implementation
plans (SIP's) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of National Ambient Air
Quality Standards designed to protect
public health and welfare. For this
purpose, SIP's must in some cases
require greater emission reductions than
those required by standards of
performance for new sources.
Finally, States are free under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than EPA's standards of performance
under section 111, and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
• Under EPA's sunset policy for
reporting requirements in regulations,
the reporting requirements in this
regulation will automatically expire five
years from the date of promulgation
unless the Administrator takes
affirmative action to extend them.
Within the five year period, the
Administrator will review these
requirements.
Section 317 of the Clean Air Act
requires the Administrator to prepare an
economic impact assessment for
revisions determined by the
Administrator to be substantial. The
Administrator has determined that these
revisions are substantial and has
prepared an economic impact
assessment and included the required
information in the background
information documents.
Dated: lune 1,1979.
Douglas M. Costle,
Administrator,

PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES

In 40 CFR Part 60, § 60.8 of Subpart A
is revised, the heading and § 60.40 of
Subpart D are revised, a new Subpart
Da is added, and a new reference •
method is added to Appendix A as
follows:
1. Section 60.8(d) and § 60.8(f) are
revised as follows:

( 60.0 Performance tcoto.
(d) The owner or operator of an
affected facility shall provide the
Administrator at least 30 days prior
notice of any performance test, except
as specified under other subparts, to
afford the Administrator the opportunity
to have an observer present.
* * * * *

(f) Unless otherwise specified in the
applicable subpart, each pt.formance
test shall consist of three separate runs
using the applicable test method. Each
run shall be conducted for the time and
under the conditions specified in the
applicable standard. For the purpose of
determining compliance with an
applicable standard, the arithmetic
means of results of the three runs shall
apply. In the event that a sample is
accidentally lost or conditions occur in
which one of the three runs must be
discontinued because of forced
shutdown, failure of an irreplaceable
portion of the sample train, extreme
meteorological conditions, or other
circumstances, beyond the owner or
operator's control, compliance may,
upon the Administrator's approval, be
determined using the arithmetic mean of
the results of the two other runs.
2. The heading for Subpart D is
revised to read as follows:

Subpart D—Standards of Performance
for Fossll-Fuel-Fired Steam Generators
for Which Construction Is Commenced
After August 17,1971

3. Section 60.40 is amended by adding
paragraph (d) as follows:

§60.40 Applicability and designation of
affected facility.
*****

(d) Any facility covered under Subpart
Da is not covered under This Subpart.
(Sec. 111. 301(a) of the Clean Air Act as
amended (42 U.S.C. 7411.760l(a)).)

4. A new Subpart Da is added as
follows:

Subpart Da—Standards of Performance for
Electric Utility Steam Generating Units for
Which Construction Is Commenced After
September 18,1976

Sec.
60.40a Applicability and designation of
affected facility.
60.41a Definitions.
60.42a Standard for participate matter.
60.43a Standard for sulfur dioxide.
60.44a Standard for nitrogen oxides.
60.45a Commercial demonstration permit.
60.46a Compliance provisions.
60.47a Emission monitoring.
60.48a Compliance determination
procedures and methods.
60.49a Reporting requirements.
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Authority: Sec. 111. 901(a) of the Clean Air
Act as amended (42 U.S.C. 7411. 7Wn(a}). and
additional authority «• noted below.

Subpart Da—Standards of
Performance for Electric Utility Steam
Generating Units for Which
Construction Is Commenced After
September W, 1S78

|60.40a AppflcabmtyandderigiMfflonof
effected facility.
(a) The affected facility to which this
subpart applies Is each electric utility
steam generating unit:
(1) That is capable of combusting
more than 73 megawatts (250 million
Btu/hour) heat input of fossil fuel (either
alone or in combination with any other
fuel); and
(2) For which construction or
modification is commenced after
September 18,1978.
[bj This subpart applies to electric
utility combined cycle gas turbines that
are capable of combusting more than 73
megawatts (250 million Btu/hour) beat
input of fossil fuel in the eteam
generator. Only emissions resulting from
combustion of fuels in the steam
generating unit are subject to this
subpart (The gas turbine emissions are
'subject to Subpart CG.)
(c) Any change to an existing fossil-
fuel-fired steam generating unit to
accommodate the use of combustible
materials, other than fossil fuels, shall
not bring that unit under the
applicability of this subpart
(d) Any change to an existing steam
generating unit originally designed to
fire gaseous or liquid fossil fuels, to
accommodate the use of any other fuel
(fossil or nonfossil) shall not bring that
unit under the applicability of this
subpart.

{6O41a Definition*.
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.
"Steam generating unit" means any
furnace, boiler, or other device need for
combusting fuel for the purpose of
producing steam (including fossil-fuel-
fired steam generators associated with
combined cycle gas turbines; nuclear
steam generators are not included).
"Electric utility.steam generating unit"
means any steam electric generating
unit that is constructed for the purpose
of supplying more than one-third of its
potential electric output capacity and •
more than 25 MW electrical output to
any utility power distribution system for
sale. Any steam supplied to a steam
distribution system for the purpose of
providing steam to a steam-electric
generator that would produce electrical
energy for sale is also considered in
determining the electrical energy output
capacity of the affected facility.
"Fossil fuel" means natural gas,
petroleum, coal, and any form of solid,
liquid, or gaseous fuel derived from nch
material for the purpose of creating
useful heat.
"Sabbinuninoas coal" means coal that
is classified as subbitaminoas A, B, or C
according to the American Society of
Testing and Materials' (ASTM)
Standard Specification for Classification
of Coals by Rank D388-68.
"Lignite" means coal that w classified
a« lignite A or B according to the
American Society of Testing and
Material*' (ASTM) Standard
Specification for Classification of Coals
by Rank D38&-08.
"Coal refuse" means waste products
of coal mining, physical coal cleaning,
and coal preparation operations (e.g.
culm, gob, etc.) containing coal, matrix
material, clay, and other organic and
inorganic material.
"Potential combustion concentration''
means the theoretical emissions (ng/J,
Ib/million Btu heat input) that would
result from combustion of a fuel in an
uncleaned state ^without emission
control systems) and:
{a) For particulate matter is:
(1) 3,000 ng/J {70 Ib/million Btu) heat
input for solid fuel; and
(2) 75 ng/J (0.17 Ib/million Btu) heat
input for liquid fuels.
(b) For sulfur dioxide is determined
under § 60.48a(b).
(c) For nitrogen oxides is:
(1) 290 ng/I (0.87 Ib/million Btu) heat
input for gaseous fuels;
(2) 310 ng/| (0.72 Ib/million Bta) heat
input for liquid fuels; and
(3) 990 ng/J (2.30 Ib/million Bta) beat
input for solid fuels.
"Combined cycle gas turbine" means
a stationary turbine combustion system
where heat from the turbine exhaust
gases is recovered fay a steam
generating unit
"Interconnected" means that two or
more electric generating units are
electrically tied together by a network of
power transmission lines, and other
power transmission equipment
"Electric utility company" means the
largest interconnected organization,
business, or governmental entity that
generates electric power for sale {e.g., a
holding company with operating
subsidiary companies).
"Principal company" means the
electric utility company or companies
which own the affected facility.
"Neighboring company" means any
one of those electric utility companies '
with one or more electric power
interconnections to the principal
company and which have
geographically adjoining service areas.
"Net system capacity" sneans the sum
of the net electric generating capability
(not necessarily equal to rated capacity)
of all electric generating equipment
owned by an electric utility company
(including steam generating unite.
internal combustion <*ngineB, gas
turbines, nuclear units, hydroelectric
units, and all other electric generating
equipment) pins firm contractual
purchases that are interconnected to the
affected facility that has the
malfunctioning flue gas desdfurication
system. The electric generating
capability of equipment under multiple
ownership is prorated baaed on
ownership unless the proportional
entitlement to electric output is
otherwise established by contractual
arrangement
"System load" means the entire
electric demand of an electric utility
company's service area interconnected
with the affected facility that has the
malfunctioning flue gas desulfdrization
system phis firm contractual sales to
other electric utility companies. Sales to
other electric utility companies (&£.,
emergency power) not on a firm
contractual basis may also be included
in the system load when no available
system capacity exists in the electric
utility company to which the power is
supplied for sale.
"System emergency reserves" means
an amount of electric generating
capacity equivalent to the rated
capacity of the single largest electric
generating unit in die electric utility
company (including steam generating
units, internal combustion engines, gas
turbines, nuclear units, hydroelectric
units, and all other electric generating
equipment) which is interconnected with
the affected facility that has the
malfunctioning flue gas desulfurization
system. The electric generating
capability of equipment under multiple
ownership is prorated based on
ownership unless the proportional
entitlement to electric output is
otherwise established by contractual
arrangement.
"Available system capacity" means
the capacity determined by subtracting
the system load and the system
emergency reserves from the net system
capacity.
"Spinning reserve" means the sum of
the unutilized net generating capability
of all units of the electric utility
company that are synchronized to the
power distribution system and that are
capable of immediately accepting
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additional load. The electric generating
capability of equipment under multiple
ownership is prorated based on
ownership unless the proportional
entitlement to electric output is
otherwise established by contractual
arrangement.
"Available purchase power" means
the lesser of the following:
(a) The sum of available system
capacity in all neighboring companies.
(b) The sum of the rated capacities of
the power interconnection devices
between the principal company and all
neighboring companies, minus the sum
of the electric power load on these
interconnections.
(c) The rated capacity, of the power
transmission lines between the power
interconnection devices and the electric
generating units (the unit in the principal
company that has the malfunctioning
flue gas desulfurization system and the
unit(s) in the neighboring company
supplying replacement electrical power)
less the electric power load on these
transmission lines.
"Spare flue gas desulfurization system
module" means a separate system of
•ulfur dioxide emission control
equipment capable of treating an /
amount of flue gas equal to the total
amount of flue gas generated by an
affected facility when operated at
maximum capacity divided by the total
number of nonspare flue gas
desulfurization modules in the system.
"Emergency condition" means that
period of time when:
(a) The electric generation output of
an affected facility with a
malfunctioning flue gas desulfurization
system cannot be reduced or electrical
output must be increased because:
(1) All available system capacity in
the principal company interconnected
with the affected facility is being
operated, and
(2) All available purchase power
interconnected with the affected facility
is being obtained, or
(b) The electric generation demand is
being shifted as quickly as possible from
an affected facility with a
malfunctioning flue gas desulfurization
system to one or more electrical
generating units held in reserve by the
principal company or by a neighboring
company, or
(c) An affected facility with a
malfunctioning flue gas desulfurization
system becomes the only available unit
to maintain a part or all of the principal
company's system emergency reserves
and the unit is operated in spinning
reserve at the lowest practical electric
generation load consistent with not
causing significant physical damage to
the unit. If the unit is operated at a
higher load to meet lead demand, an
emergency condition would not exist
unless the conditions under (a) of this
definition apply.
"Electric utility combined cycle gas
turbine" means any combined cycle gas
turbine used for electric generation that
is constructed for the purpose of
supplying more than one-third of its
potential electric output capacity and
more than 25 MW electrical output to
any utility power distribution system for
sale. Any steam distribution system that
is constructed for the purpose of
providing steam to a steam electric
generator that would produce electrical
power for sale is also considered in
determining the electrical energy output
capacity of the affected facility.
"Potential electrical output capacity"
is defined as 33 percent of the maximum
design heat input capacity of the steam
generating unit (e.g., a steam generating
unit with a 100-MW (340 million Btu/hr)
fossil-fuel heat input capacity would
have a 33-MW potential electrical
output capacity). For electric utility
combined cycle gas turbines the
potential electrical output capacity is
determined on the basis of the fossil-fuel
firing capacity of the steam generator
exclusive of the heat input and electrical
power contribution by the gas turbine.
"Anthracite" means coal that is
classified as anthracite according to the
American Society of Testing and
Materials' (ASTM) Standard
Specification for Classification of Coals
by Rank D388-66.
"Solid-derived fuel" means any solid,
liquid, or gaseous fuel derived from solid
fuel for the purpose of creating useful -
heat and includes, but is not limited to,
solvent refined coal, liquified coal, and
gasified coal.
"24-hour period" means the period of
time between 12:01 a.m. and 12:00
midnight.
"Resource recovery unit" means a
facility that combusts more than 75
percent non-fossil fuel on a quarterly
(calendar) heat input basis.
"Noncontinental area" means the
State of Hawaii, the Virgin Islands,
Guam, American Samoa, the
Commonwealth of Puerto Rico, or the
Northern Mariana Islands.
"Boiler operating day" means a 24-
hour period during which fossil fuel is
combusted in a steam generating unit for
the entire 24 hours.

8 60.42a Standard for paniculate matter.
(a) On and after the date on which the
performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility any gases which
contain particulate matter in excess of:
(1) 13 ng/J (0.03 Ib/million Btu) heat
input derived from the combustion of
solid, liquid, or gaseous fuel;
(2) 1 percent of the potential
combustion concentration (99 percent
reduction) when combusting solid fuel;
and
(3) 30 percent of potential combustion
concentration (70 percent reduction)
when combusting liquid fuej.
(b] On and after the date the
particulate matter performance test
required to be conducted under § 60.8 is
completed, no owner or operator subject
to the provisions of this subpart shall
cause to be discharged into the
atmosphere from any affected facility
any gases which exhibit greater than 20
percent opacity (6-minute average),
except for one 6-minute period per hour
of not more than 27 percent opacity.

S60.43a Standard for sulfur dioxide.
(a) On and after the date on which the
initial performance test required to be
conducted under $ 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility which combusts
solid fuel or solid-derived fuel, except as
provided under paragraphs (c), (d), (f) or
(h) of this section, any gases which
contain sulfur dioxide in excess of:
(1) 520 ng/J (1.20 Ib/million Btu) heat
input and 10 percent of the potential
combustion concentration (90 percent
reduction), or
(2) 30 percent of the potential
combustion concentration (70 percent
reduction), when emissions are less than
260 ng/J (0.60 Ib/million Btu) heat input.
(b) On and after the date on which the
initial performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility which combusts
liquid or gaseous fuels (except for liquid
or gaseous fuels derived from solid fuels
and as provided under paragraphs (e) or
(h) of this section), any gases which
contain sulfur dioxide in excess of:
(1) 340 ng/J (0.80 Ib/million Btu) heat
input and 10 percent of the potential
combustion concentration (90 percent
reduction), or
(2) 100 percent of the potential
combustion concentration (zero percent
reduction) when emissions are less than
86 ng/J (0.20 Ib/million Btu) heat input.
(c) On and after the date on which the
initial performance test required to be
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conducted under § 60.8 is complete, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility which combusts
solid solvent refined coal (SRC-I) any
gases which contain sulfur dioxide in
excess of 520 ng/J (1.20 Ib/million Btu)
heat input and 15 percent of the
potential combustion concentration (85
percent reduction] except as provided
under paragraph (f) of this section;
compliance with the emission limitation
is determined on a 30-day rolling
average basis and compliance with the
percent reduction requirement is
determined on a 24-hour basis.
(d) Sulfur dioxide emissions are
limited to 520 ng/J (1.20 Ib/million Btu)
heat input from any affected facility
which:
(1) Combusts 100 percent anthracite,
(2) Is classified as a resource recovery
facility, or
(3) Is located in a noncontinental area
and combusts solid fuel or solid-derived
fuel.
(e) Sulfur dixoide emissions are
limited to 340 ng/J (0.80 Ib/million Btu)
heat input from any affected facility
which is located in a noncontinental
area and combusts liquid or gaseous
fuels (excluding solid-derived fuels).
(f) The emission reduction
requirements under this section do not
apply to any affected facility that is
operated under an SO« commercial
demonstration permit issued by the
Administrator in accordance with the
provisions of § 60.45a.
(g) Compliance with the emission
limitation and percent reduction
requirements under this section are both
determined on a 30-day rolling average
basis except as provided under
paragraph (c) of this section.
(h) When different fuels are
combusted simultaneously, the
applicable standard is determined by
proration using the following formula:
(1) If emissions of sulfur dioxide to the
atmosphere are greater than 280 ng/J
(0.60 Ib/million Btu) heat input
Ego, = [340 x + 520 y]/100 and
PCO, = 10 percent

(2) It emissions of sulfur dioxide to the
atmosphere are equal to or less than 260
ng/J (0.60 Ib/million Btu) heat input:
EM,, = [340 x + 520 y]/100 and
Pso, =[90x + 70y]/100
where:
ESO, is the prorated sulfur dioxide emission
limit (ng/J heat input),
PIO, is the percentage of potential sulfur
dioxide emission allowed (percent
reduction required - lpO-PMl),
x is the percentage of total heat input derived
from the combustion of liquid or gaseous
fuels (excluding solid-derived fuels)
y is the percentage of total heat input derived
from the combustion of solid fuel
(including solid-derived fuels)

J 60.44n Standard for nitrogen oxides.
(a) On and after the date on which the
initial performance test required to be
conducted under 8 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility, except as provided
under paragraph (b) of this section, any
gases which contain nitrogen oxides in
excess of the following emission limits,
based on a 30-day rolling average.
(1) NO, Emission Limits—
Fuel type
Emission »mn
ng/J (Ib/mlllian Btu)
heat Input
Gaseous Fuels:
Coal-derived fuels..
All other fuels
UquW Fuels:
CoaMertvedfueta.
All other fuels
Soid Fuels:
CookJerivod fuels .___«.....»«».
Any fuel containing more than
25%. by weight, coal refuse .
210
66

210
210
130

210
(0.20)

•3-50)
(0.50)
(0.30)

(0.50)
Any fuel containing more than
25%, by weight, lignite H the
Ignite is mined in North
Dakota, South Dakota, or
Montana, and b combusted
In a slag tap furnace _
Lignite not subject to the 340
ng/J heat input emission Hmtt
Subbttuminous coal
Exempt from NO,
standards and NOi
monitoring
requirements
Anthracite coal..
AH other fuels
340

260
210
260
260
260
(0.80)

(0.60)
(0.50)
(0.60)
(0.60)
(0.60)
(2) NOZ reduction requirements—
Fuel type
Porcont reduction
of potential
combustion
coocontrstion
Gaseous fuels....
Liquid fuels
SoUd fuels
25%
30%
65%
(b) The emission limitations under
paragraph (a) of this section do not
apply to any affected facility which is
combusting coal-derived liquid fuel and
is operating under a commercial
demonstration permit issued by the
Administrator in accordance with the
provisions of § 60.45a.
(c) When two or more fuels are
combusted simultaneously, the
applicable standard is determined by
proration using the following formula:
=[88 w+130x+210 y+260 z]/100
where:
ENO, !• the applicable standard for nitrogen
oxides when multiple fuels are
combusted simultaneously (ng/J heat
input);
w is the percentage of total heat input
derived from the combustion of fuels
subject to the 86 ng/J heat input
standard;
x is the percentage of total heat input derived
from the combustion of fuels subject to
the 130 ng/J heat input standard;
y is the percentage of total heat input derived
from the combustion of fuels subject to
the 210 ng/J heat input standard; and
z is the percentage of total heat input derived
from the combustion of fuels subject to
the 260 ng/J heat input standard.

§ 60.4Sa Commercial demonotration
permit
(a) An owner or operator of an
affected facility proposing to
demonstrate an emerging technology
may apply to the Administrator for a
commercial demonstration permit. The
Administrator will issue a commercial
demonstration permit in accordance •
with paragraph (e) of this section.
Commercial demonstration permits may
be issued only by the Administrator,
and this authority will not be delegated.
(b) An owner or operator of an
affected facility that combusts solid
solvent refined coal (SRC-I) and who is
issued a commercial demonstration
permit by the Administrator is not
subject to the SO, emission reduction
requirements under { 60.43a(c) but must,
as a minimum, reduce SOt emissions to
20 percent of the potential combustion
concentration (80 percent reduction) for
each 24-hour period of steam generator
operation and to less than 520 ng/J (1.20
Ib/million Btu) heat input on a 30-day
rolling average basis.
(c) An owner or operator of a fluidized
bed combustion electric utility steam.
generator (atmospheric or pressurized)
who is issued a commercial
demonstration permit by the
Administrator is not subject to the SO,
emission reduction requirements under
§ 60.43a(a] but must, as a minimum,
reduce SO* emissions to 15 percent of
the potential combustion concentration
(85 percent reduction] on a 30-day
rolling average basis and to less than
520 ng/J (1.20 Ib/million Btu] heat input
on a 30-day rolling average basis.
(d) The owner or operator of an
affected facility that combusts coal-
derived liquid fuel and who is issued a
commercial demonstration permit by the
Administrator is not subject to the
applicable NO, emission limitation and
percent reduction under § 60.44a(a) but
must, as a minimum, reduce emissions
to less than 300 ng/J (0.70 Ib/million Btu)
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heat input on a 30-day rolling average
basis.
(e) Commercial demonstration permits
may not exceed the following equivalent
MW electrical generation capacity for
any one technology category, and the
.total equivalent MW electrical
generation capacity for all commercial
demonstration plants may not exceed
15,000 MW.
EiMvatenC
Tactmaloay
PodutwK
opacity
(MW electrical
output)
Son BoKMfit tvflnso covl
(SRC 0——«""—
FUdteedtrtcoflfcustion
(•tmospnanc) ..—»_.>».»».«
FUdizod bod cwntoustion
(pressurized) „_..
Cod NquMcatton

Tott afoMfcto to al
technologiea
SO, 6,000-10,000

SO. 400-3400
so,
NO.
400-1,200
750-10.000
15.000
f (t0.46a Compliance provision*.
(a) Compliance with the particulate
matter emission limitation under
§ 60.42a(a)(l) constitutes compliance
with the percent reduction requirements
for particulate matter under
S 60.42a(a)(2) and (3).
(b) Compliance with the nitrogen
oxides emission limitation under
{ 60.44a(a) constitutes compliance with
tile percent reduction requirements
under 5 60.44a(a)(2).
(c) The particulate matter emission
standards under § 60.42a and the
nitrogen oxides emission standards
under S 60.44a apply at all times except
during periods of startup, shutdown, or
malfunction. The sulfur dioxide emission
standards under { 60.43a apply at all
times except during periods of startup,
shutdown, or when both emergency
conditions exist and the procedures
under paragraph (d) of this section are
implemented.
(d) During emergency conditions in
the principal company, an affected
facility with a malfunctioning flue gas
desulfurization system may be operated
if sulfur dioxide emissions are
minimized by:
(1) Operating all operable flue gas
desulfurization system modules, and
bringing back into operation any
malfunctioned module as soon as
repairs are completed,
(2) Bypassing flue gases around only
those flue gas desulfurization system
modules that have been taken out of
operation because they were incapable
of any sulfur dioxide emission reduction
or which would have suffered significant
physical damage if they had remained in
operation, and
(3) Designing, constructing, and
operating a spare flue gas
desulfurization system module for an
affected facility larger than 365 MW
(1.250 million Btu/hr) heat input
(approximately 125 MW electrical
output capacity). The Administrator
may at his discretion require the owner
or operator within 60 days of
notification to demonstrate spare
module capability. To demonstrate this
capability, the owner or operator must
demonstrate compliance with the
appropriate requirements under
paragraph (a), (b), (d), (e), and (i) under
{ 60.43a for any period of operation
lasting from 24 hours to 30 days when:
(i) Any one flue gas desulfurization
module is not operated,
(ii) The affected facility is operating at
the maximum heat input rate,
(iii) The fuel fired during the 24-hour
to 30-day period is representative of the
type and average sulfur content of fuel
used over a typical 30-day period, and
(iv) The owner or operator has given
the Administrator at least 30 days notice
of the date and period of time over
which the demonstration will be
performed.
(e) After the initial performance test
required under 5 60.8, compliance with
the sulfur dioxide emission limitations
and percentage reduction requirements
under { 60.43a and the nitrogen oxides
emission limitations under { 60.44a is
based on the average emission rate for
30 successive boiler operating days. A
separate performance test is completed
at the end of each boiler operating day
after the initial performance test, and a
new 30 day average emission rate for
both sulfur dioxide and nitrogen oxides
and a new percent reduction for sulfur .
dioxide are calculated to show
compliance with the standards.
(f) For the initial performance test
required under { 60.8, compliance with
the sulfur dioxide emission limitations
and percent reduction requirements
under § 60.43a and the nitrogen oxides
emission limitation under $ 60.44a is
based on the average emission rates for
sulfur dioxide, nitrogen oxides, and
percent reduction for sulfur dioxide for
the first 30 successive boiler operating
days. The Initial performance test is the
only test in which at least 30 days prior
notice is required unless otherwise
specified by the Administrator. The
initial performance test is to be
scheduled so that the first boiler
operating day of the 30 successive boiler
operating days is completed within 60
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.
(g) Compliance is determined by
calculating the arithmetic average of all
hourly emission rates for SOt and NO«
for the 30 successive boiler operating
days, except for data obtained during
startup, shutdown, malfunction (NO,
only), or emergency conditions (SO8
only). Compliance with the percentage
reduction requirement for SO, is
determined based on the average inlet
and average outlet SO, emission rates
for the 30 successive boiler operating
days.
(h) If an owner or operator has not
obtained the minimum quantity of
emission data as required under $ 60.47a
.of this subpart compliance of the
affected facility with the emission
requirements under $ § 60.43a and 60.44a
of this subpart for the day on which the
30-day period ends may be determined
by the Administrator by following the
applicable procedures in sections 6.0
and 7.0 of Reference Method 19
(Appendix A).

{60.47* Emission monitoring.
(a) The owner or operator of an
affected facility shall install, calibrate.
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring the
opacity of emissions discharged to the
atmosphere, except where gaseous fuel
is the only fuel combusted. If opacity
interference due to water droplets exists
in the stack (for example, from the use
of an FGD system), the opacity is
monitored upstream of the interference
(at the inlet to the FGD system). If
opacity interference is experienced at
all locations (both at the inlet and outlet
of the sulfur dioxide control system),
alternate parameters indicative of the
particulate matter control system's
performance are monitored (subject to
the approval of the Administrator).
(b) The owner or operator of an
affected facility shall install, calibrate.
maintain, and operate a continuous
monitoring system, and record the -
output of the system, for measuring
sulfur dioxide emissions, except where
natural gas is the only fuel combusted.
as follows:
(1) Sulfur dioxide emissions are
monitored at both the inlet and outlet of
the sulfur dioxide control device.
(2) For a facility which qualifies under
the provisions of 8 60.43a(d), sulfur
dioxide emissions are only monitored as
discharged to the atmosphere.
(3) An "as fired" fuel monitoring
system (upstream of coal pulverizers)
meeting the requirements of Method 19
(Appendix A) may be used to determine
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potential sulfur dioxide emissions in
place of a continuous sulfur dioxide
emission monitor at the inlet to the
sulfur dioxide control device as required
under paragraph (b)(l) of this section.
(c) The owner or operator of an
affected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring
nitrogen oxides emissions discharged to
the atmosphere.
(d) The owner or operator of an
affected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring the
oxygen or carbon dioxide content of the
flue gases at each location where sulfur
dioxide or nitrogen oxides emissions are
monitored.
(e) The continuous monitoring
systems under paragraphs (b), (c), and
(d) of this section are operated and data
recorded during all periods of operation
of the affected facility including periods
of startup, shutdown, malfunction or
emergency conditions, except for
continuous monitoring system
breakdowns, repairs, calibration checks,
and zero and span adjustments.
(f) When 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 other monitoring
systems as approved by the
Administrator or the reference methods
as described in paragraph (h) of this
section to provide emission data for a
minimum of 18 hours in at least 22 out of
30 successive boiler operating days.
(g) The 1-hour averages required
under paragraph § 60.13(h) are
expressed in ng/J (Ibs/million Btu) heat
input and used to calculate the average
emission rates under { 60.46a. The 1-
hour averages are calculated using the
data points required under § 60.13(b). At
least two data points must be used to
calculate the 1-hour averages.
(h) Reference methods used to
supplement continuous monitoring
system data to meet the minimum data
requirements in paragraph § 60.47a(f)
will be used as specified below or
otherwise approved by the
Administrator.
(1) Reference Methods 3,6, and 7, as
applicable, are used. The sampling
location(s) are the same as those used
for the continuous monitoring system.
(2) For Method 6, the minimum
sampling time is 20 minutes and the
minimum sampling volume is 0.02 dscm
(0.71 dscf] for each sample. Samples are
taken at approximately 60-minute
intervals. Each sample represents a 1-
hour average.
(3) For Method 7, samples are taken at
approximately 30-minute intervals. The
arithmetic average of these two
corrective samples represent a 1-hour
average.
(4) For Method 3, the oxygen or
carbon dioxide sample is to be taken for
each hour when continuous SO» and
NO, data are taken or when Methods 6
and 7 are required. Each sample shall be
taken for a minimum of 30 minutes in
each hour using the integrated bag
method specified in Method 3. Each
sample represents a 1-hour average.
(5) For each 1-hour average, the
emissions expressed in ng/J (Ib/million
Btu) heat input are determined and used
as needed to achieve the minimum data
requirements of paragraph (f) of this
section.
(i) The following procedures are used
to conduct monitoring system
performance evaluations under
§ 60.13{c) and calibration checks under
S 60.13(d).
(1) Reference method 6 or 7, as
applicable, is used for conducting
performance evaluations of sulfur
dioxide and nitrogen oxides continuous
monitoring systems.
(2} Sulfur dioxide or nitrogen oxides,
as applicable, is used for preparing
calibration gas mixtures under
performance specification 2 of appendix
B to this part.
(3] For affected facilities burning only
fossil fuel, the span value for a
continuous monitoring system for
measuring opacity is between 60 and 80
percent and for a continuous monitoring
system measuring nitrogen oxides is
determined as follows:
Foul fuel
Span value for
nitrogen oxides (ppm)
Gas..
SoM
Comb*
500
800
1.000
S00(x+y)+1,000z
where:
x is the fraction of total heat input derived
from gaseous fossil fuel,
y it the fraction of total heat input derived
from liquid fossil fuel, and
E is the fraction of total heat input derived
from solid fossil fuel

560.48a Compliance determination
procedures and methods.
(a) The following procedures and
reference methods are used to determine
compliance with the standards for
particulate matter under § 60.42a.
(1) Method 3 is used for gas analysis
when applying method 5 or method 17.
(2) Method 5 is used for determining
particulate matter emissions and
associated moisture content. Method 17
may be used for stack gas temperatures
less than 160 C (320 F).
(3) For Methods 5 or 17, Method 1 is
used to select the sampling site and the
number of traverse sampling points. The
sampling time for each run is at least 120
minutes and the minimum sampling
volume is 1.7 dscm (60 dscf] except that
smaller sampling times or volumes,
when necessitated by process variables
or other factors, may be approved by the
Administrator.
(4) For Method 5, the probe and filter
holder heating system in the sampling
train is set to provide a gas temperature
no greater than 160°C (32°F).
(5) For determination of particulate
emissions, the oxygen or carbon-dioxide
sample is obtained simultaneously with
each run of Methods 5 or 17 by
traversing the duct at the same sampling
location. Method 1 is used for selection
of the number of traverse points except
that no more than 12 samplej>oints are
required.
(6) For each run using Methods 5 or 17,
the emission rate expressed in ng/J heat
input is determined using the oxygen or
carbon-dioxide measurements and
particulate matter measurements
obtained under this section, the dry
basis Fc-factor and the dry basis
emission rate calculation procedure
contained in Method 19 (Appendix A).
(7) Prior to the Administrator's
issuance of a particulate matter
reference method that does not
experience sulfuric acid mist
interference problems, particulate
matter emissions may be sampled prior
to a wet flue gas desulfurization system.
(b) The following procedures and
methods are used to determine
compliance with the sulfur dioxide
standards under S 60.43a.
(1) Determine the percent of potential
combustion concentration (percent PCC)
emitted to the atmosphere as follows:
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(I) FuelPretreatment (% Rf):
Determine the percent reduction
achieved by any fuel pretreatment using
the procedures in Method 19 (Appendix
A). Calculate the average percent
reduction for fuel pretreatment on a
quarterly basis using fuel analysis data.
The determination of percent R( to
calculate the percent of potential
combustion concentration emitted to the
atmosphere is optional. For purposes of
determining compliance with any
percent reduction requirements under
8 60.43a, any reduction in potential SOs
emissions resulting from the following
processes may be credited:
(A) Fuel pretreatment (physical coal
cleaning, hydrodesulfurization of fuel
oil, etc.).
(B) Coal pulverizers, and
(C) Bottom and flyash interactions.
(ii) Sulfur Dioxide Control System (%
Rf): Determine the percent sulfur
dioxide reduction achieved by any
sulfur dioxide control system using
' emission rates measured before and
after the control system, following the
procedures in Method 19 (Appendix A);
or, a combination of an "as fired" fuel .
monitor and emission rates measured
after the control system, following the
procedures in Method 19 (Appendix A).
When the "as fired" fuel monitor is
used, the percent/reduction is calculated
using the average emission rate from the
sulfur dioxide control device and the
average SO» input rate from the "as
fired" fuel analysis for 30 successive
boiler operating days.
(iii) Overall percent reduction (% R,):
Determine the overall percent reduction
using the results obtained in paragraphs
(b)(l) (i) and (ii) of this section following
the procedures in Method 19 (Appendix
A). Results are calculated for each 30-
day period using the quarterly average
percent sulfur reduction determined for
fuel pretreatment from the previous
quarter and the sulfur dioxide reduction
achieved by a sulfur dioxide control
system for each 30-day period in the
current quarter.
(iv) Percent emitted (% PCC):
Calculate the percent of potential
combustion concentration emitted to the
atmosphere using the following
equation: Percent PCC=100-Percent R,
(2) Determine the sulfur dioxide
emission rates following the procedures
in Method 19 (Appendix A).
(c) The procedures and methods
outlined in Method 19 (Appendix A) are
used in conjunction with the 30-day
nitrogen-oxides emission data collected
under § 60.47a to determine compliance
with the applicable nitrogen oxides
standard under § 60.44.
(d) Electric utility combined cycle gas
turbines are performance tested for
particulate matter, sulfur dioxide, and
nitrogen oxides using the procedures of
Method 19 (Appendix A). The sulfur
dioxide and nitrogen oxides emission
rates from the gas turbine used in
Method 19 (Appendix A) calculations
are determined when the gas turbine is
performance tested under subpart GG.
The potential uncontrolled particulate
matter emission rate from a gas turbine
is defined as 17 ng/J (0.04 Ib/million Btu)
heat input

§ 60.49a Reporting requirement*.
(a) For sulfur dioxide, nitrogen oxides,
and particulate matter emissions, the
performance test data from the initial
performance test and from the
performance evaluation of the
continuous monitors (including the
transmissometer) are submitted to the
Administrator.
(b) For sulfur dioxide and nitrogen
oxides the following informatioiTis
reported to the Administrator for each
24-hour period.
(1) Calendar date.
(2) The average sulfur dioxide and
nitrogen oxide emission rates (ng/J or
Ib/million Btu) for each 30 successive
boiler operating days, ending with the
last 30-day period in the quarter;
reasons for non-compliance with the
emission standards; and, description of
corrective actions taken.
(3) Percent reduction of the potential
combustion concentration of sulfur
dioxide for each 30 successive boiler
operating days, ending with the last 30-
day period in the quarter; reasons for
non-compliance with the standard; and,
description of corrective actions taken.
(4) Identification of the boiler
operating days for which pollutant or
dilutent data have not been obtained by
an approved method for at least 18 ~
hours of operation of the facility;
justification for not obtaining sufficient
data; and description of corrective
actions taken.
(5) Identification of the times when
emissions data have been excluded from
the calculation of average emission
rates because of startup, shutdown,
malfunction (NO, only), emergency
conditions (SOi only), or other reasons,
and justification for excluding data for
reasons other than startup, shutdown,
malfunction, or emergency conditions.
(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.
(B) 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 which
could affect the ability of the continuous
monitoring system to comply with
Performance Specifications 2 or 3.
(c) If the minimum quantity of
emission data as required by § 60.47a is
not obtained for any 30 successive
boiler operating days, the following
information obtained under the
requirements of § 60.46a(h) is reported
to the Administrator for that 30-day
period:
(1) The number of hourly averages
available for outlet emission rates (n,,)
and inlet emission rates (n,) as
applicable.
(2) The standard deviation of hourly
averages for outlet emission rates (s0)
and inlet emission rates (s,) as
applicable.
(3) The lower confidence limit for the
mean outlet emission rate (£„*) and the
upper confidence limit for the mean inlet
emission rate (E,*) as applicable.
(4) The applicable potential
combustion concentration.
(5) The rctio of the upper confidence
limit for the mean outlet emission rate
(Bo*) and the allowable emission rate
(E^) as applicable.
(d) If any standards under § 60.43a are
exceeded during emergency conditions
because of control system malfunction,
the owner or operator of the affected
facility shall submit a signed statement:
(1) Indicating if-emergency conditions
existed and requirements under
§ 60.46a(d) were met during each period,
and
(2) Listing the following information:
(i) Time periods the emergency
condition existed;
(ii) Electrical output and demand on
the owner or operator's electric utility
system and the affected facility;
(iii) Amount of power purchased from
interconnected neighboring utility
companies during the emergency period;
(iv) Percent reduction in emissions
achieved;
(v) Atmospheric emission rate fng/J)
of the pollutant discharged; and
(vi) Actions taken to correct control
system malfunction.
(e) If fuel pretreatment credit toward
the sulfur dioxide emission standard
under § 60.43a is claimed, the owner or
operator of the affected facility shall
submit a signed statement:
(1) Indicating what percentage
cleaning credit was taken for the
calendar quarter, and whether the credit
was determined in accordance with the
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provisions of § 60.48a and Method 19
(Appendix A); and
(2) Listing the quantity, heat content,
and date each pretreated fuel shipment
was received during the previous
quarter; the name and location of the
fuel pretreatment facility; and the total
quantity and total heat content of all
fuels received at the affected facility
during the previous quarter.
(f) For any periods for which opacity,
sulfur dioxide or nitrogen oxides
emissions data are not available, the
owner or operator of the affected facility
shall submit a signed statement
indicating if any changes were made in
operation of the emission control system
during the period of data unavailability.
Operations of the control system and ~
affected facility during periods of data
unavailability are to be compared with
operation of the control system and
affected facility before and following the
period of data unavailability.
(g) The owner or operator of the
affected facility shall submit a signed
statement indicating whether:
(1) The required continuous
monitoring system calibration, span, and
drift checks or other periodic audits
have or have not been performed as
specified.
(2) The data used to show compliance
was or was not obtained in accordance
with approved methods and procedures
of this part and is representative of
plant performance.
(3) The-minimum data requirements
have or have not been met; or, the
minimum data requirements have not
been met for errors that were
unavoidable. x
(4) Compliance with the standards has
or has not been achieved during the
reporting period.
(h) For the purposes of the reports
required under § 60.7, periods of excess
emissions are defined as all 6-minute
periods during which the average
opacity exceeds the applicable opacity
standards under § 60.42a(b). Opacity
levels in excess of the applicable
opacity standard and the date of such
excesses are to be submitted to the
Administrator each calendar quarter.
(i) The owner or operator of an
affected facility shall submit the written
reports required under this section and
subpart A to the Administrator for every
calendar quarter. All quarterly reports
shall be postmarked by the 30th day
following the end-of each calendar
quarter.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414).)
4. Appendix A to part 60 is amended
by adding new reference Method 19 as
follows:
Appendix A—Reference Methods
Method 19. Determination of Sulfur
Dioxide Removal Efficiency and
Particulate, Sulfur Dioxide and Nitrogen
Oxides Emission Rates From Electric
Utility Steam Generators
1. Principle and Applicability
4.1 Principle.
1.1.1 Fuel samples from before and
after fuel pretreatment systems are
collected and analyzed for sulfur and
heat content, and the percent sulfur
dioxide (ng/Joule, Ib/million Btu)
reduction is calculated on a dry basis.
(Optional Procedure.)
1.1.2 Sulfur dioxide and oxygen or
carbon dioxide concentration data
obtained from sampling emissions
upstream and downstream of sulfur
dioxide control devices are used to
calculate sulfur dioxide removal
efficiencies. (Minimum Requirement.) As
an alternative to sulfur dioxide
monitoring upstream of sulfur dioxide
control devices, fuel samples may be
collected in an as-fired condition and
analyzed for sulfur and heat content.
(Optional Procedure.)
1.1.3 An overall sulfur dioxide
emission reduction efficiency is
calculated from the efficiency of fuel
pretreatment systems and the efficiency
of sulfur dioxide control devices.
1.1.4 Particulate, sulfur dioxide,
nitrogen oxides, and oxygen or carbon
dioxide concentration data obtained
from sampling emissions downstream
from sulfur dioxide control devices are
used along with F factors to calculate
particulate, sulfur dioxide, and nitrogen
oxides emission rates. F factors are
values relating combustion gas volume
to the heat content of fuels.
1.2 Applicability. This method is
applicable for determining sulfur
removal efficiencies of fuel pretreatment
and sulfur dioxide control devices and
the overall reduction of potential sulfur
dioxide emissions from electric utility
steam generators. This method is also
applicable for the determination of
particulate, sulfur dioxide, and nitrogen
oxides emission rates.

2. Determination of Sulfur Dioxide
Removal Efficiency of Fuel
Pretreatment Systems
2.1 Solid Fossil Fuel.
2.1.1 Sample Increment Collection.
Use ASTM D 2234', Type I, conditions
A, B, or C, and systematic spacing.
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 D
2234'. Collect one gross sample for each
raw coal lot and one gross sample for
each product coal lot.
2.1.2 ASTM Lot Size. For the purpose
of Section 2.1.1, the product coal lot size
is defined as the weight of product coal
produced from one type of raw coal. The
raw coal lot size is the weight of raw
coal used to produce one product coal
lot. Typically, the lot size is the weight
of coal processsed in a 1-day (24 hours)
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 specific power plant
may be nsed if representative sampling
can be conducted for the raw coal and
product coal.
Note.—Alternate definitions of fuel lot
sizes may be specified subject to prior
approval of the Administrator.
2.1.3 Gross Sample Analysis.
Determine the percent sulfur content
(%S) and gross calorific value (GCV) of
the solid fuel on a dry basis for each
gross sample. Use ASTM 2013 ' for
sample preparation, ASTM D 3177 ' for
sulfur analysis, and ASTM D 3173 ' for
moisture analysis. Use ASTM D 3176 '
for gross calorific value determination.
2.2 Liquid Fossil Fuel.
2.2.1 Sample Collection. Use ASTM
D 270 ' following the practices outlined
• for continuous sampling for each gross
sample representing each fuel lot.
2*23. Lot Size. For the purposes of
Section 2.2.1, the weight of product fuel
from one pretreatment facility and
intended as one shipment (ship load,
barge load, etc.) is defined as one
product fuel lot. The weight of each
crude liquid fuel type used to produce
one product fuel lot is defined as one
inlet fuel lot
Note.— Alternate definitions of fuel lot
sizes may be specified subject to prior
approval of the Administrator.
Note.— For the purposes of this method,
raw or inlet fuel (coal or oil) is defined as the
fuel delivered to the desulfurization
pretreatment facility or to the steam
generating plant. For pretreated oil the input
oiHo the oil desumirizajion process (e.g.
hydrotreatment emitted) is sampled
2.2.3 Sample Analysis. Determine
the percent sulfur content (%S) and
gross calorific value (GCV). Use ASTMD
240 ' for the sample analysis. This value
can be assumed to be on a dry basis.
'Use the moat recent revision or designation of
the ASTM procedure specified.
'Use the most recent revision or designation of
the ASTM procedure specified.
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2.3 Calculation of Sulfur Dioxide
Removal Efficiency Due to Fuel
Pretregtment. Calculate the percent
sulfur dioxide reduction due to fuel
pretreatment using the following
equation:
IR. - 100
SS1/GCV1
Where:
KRi=Sulfur dioxide removal efficiency due
pretreatment; percent.
%S.=Sulfur content of the product fuel lot on
a dry basis; weight percent
%S,=Sulfur content of the inlet fuel lot on a
dry basis; weight percent
GCV,=Gross calorific value for the outlet
fuel lot on a dry basis; kj/kg (Btu/lb).
GCV,=Gross calorific value for the inlet fuel
lot on a dry basis; kj/kg (Btu/lb).
Note.—If more than one fuel type is used to
produce the product fuel, use the following
equation to calculate the sulfur contents per
unit of heat content of the total fuel lot, %S/
GCV: •

K/GCY • £ Vk(ISk/GCVk)

Where:
Yk=The fraction of total mass input derived
from each type, k, of fuel.
*S»=Sulfur content of each fuel type, k/on a
dry basis; weight percent
GCVk=Gross calorific, value for each fuel
type, k, on a dry basis; kj/kg (Btu/lb).
n=The number of different types of fuels.

3. Determination of Sulfur Removal
Efficiency of the Sulfur Dioxide Control
Device

3.1 Sampling. Determine SO,
emission rates at the inlet and outlet of
the sulfur dioxide control system
according to methods specified in the
applicable subpart of the regulations
and the procedures specified in Section
6. The inlet sulfur dioxide emission rate
may be determined through fuel analysis
(Optional, see Section 3.3.)
3.2. Calculation. Calculate the
percent removal efficiency using the
following equation:
.
*(•)
100
(1.0 -
Where:
%R, = Sulfur dioxide removal efficiency of
the sulfur dioxide control system using
inlet and outlet monitoring data; percent.
EBO 0= Sulfur dioxide emission rate from the
outlet of the sulfur dioxide control
system: ng/J (Ib/million Btu).
" E«o i = Sulfur dioxide emission rate to the
outlet of the sulfur dioxide control
system; ng/J (Ib/million Btu).
3.3 As-fired Fuel Analysis {Optional
Procedure). If the owner or operator of
an electric utility steam generator
chooses to determine the sulfur dioxide
imput rate at the inlet to the sulfur
dioxide control device through an as-
fired fuel analysis in lieu of data from a
sulfur dioxide control system inlet gas
monitor, fuel samples must be collected
in accordance with applicable
paragraph in Section 2. The sampling
can be conducted upstream of any fuel
processing, e.g., plant coal pulverization.
For the purposes of this section, a fuel
lot size is defined as the weight of fuel
consumed in 1 day (24 hours) and is
directly related to the exhaust gas
monitoring data at the outlet of the
sulfur dioxide control system.
3.3.1 Fuel Analysis. Fuel samples
must be analyzed for sulfur content and
gross calorific value. The ASTM
procedures for determining sulfur
content are defined in the applicable
paragraphs of Section 2.
3.3.2 Calculation of Sulfur Dioxide
Input Rate. The sulfur dioxide imput rate
determined from fuel analysis is
calculated by:
I
'
2.0(SSf)
T
2.0(JSf)
GCV
x 10 for S. I. units.
x 10 for English units.
Where: ,

I » Sulfur dioxide Input rate from as-fired fuel analysis,

ng/J (1b/mmion Btu).

tS. » Sulfur content of as-fired fuel, on a dry basis; weight

percent.

GCV'« Gross calorific value for as-fired fuel, on a dry basis;

kJ/kg (Btu/lb).

3.3.3 Calculation of Sulfur Dioxide 3.3.2 and the sulfur dioxide emission
Emission Reduction Using As-fired Fuel rate, ESO>. determined in the applicable
Analysis. The sulfur dioxide emission paragraph of Section 5.3. The equation
reduction efficiency is calculated using f°r sulfur dioxide emission reduction
the sulfur imput rate from paragraph ' efficiency is:
JR

Where:

SR
:g(f) '
100 x (1.0 -
! /f» • Sulfur dioxide removal efficiency of the sulfur

dioxide control system using as-fired fuel analysis

data; percent.
Sulfur dioxide emission rate from sulfur dioxide control

system; ng/J (To/million Btu).

Sulfur dioxide Input n

ng/J {Ib/million Btu).
'SO,
I$ • Sulfur dioxide Input rate from as-fired fuel analysis;
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4. Calculation of Overall Reduction in
Potential Sulfur Dioxide Emission
4.1 The overall percent sulfur
dioxide reduction calculation uses the
ettlfur dioxide concentration at the inlet
to the sulfur dioxide control device as

the base value. Any sulfur reduction
realized through fuel cleaning is
introduced into the equation as an
average percent reduction, %Rf.
4.2 Calculate the overall percent
sulfur reduction re

1R0 -

Where:

«0 • Overall sulfur dioxide reduction; percent.

SR« • Sulfur dioxide removal, efficiency of fuel pretreatstent

from Section 2; percent. Refer to applicable subpart

for definition of applicable averaging period.

XR • Sulfur dioxide removal efficiency of sulfur dioxide control

device either 02 or C02 • based calculation or calculated

froa fuel analysts and emission data, fro* Section 3;

percent. Refer to applicable subpart for definition of

applicable averaging period.

6. Calculation of Particulate, Sulfur
Dioxide, and Nitrogen Oxides Emission
Rates
and oxygen concentrations have been
determined in Section 5.1, wet or dry F
factors are used. (Fw) factors and
associated emission calculation
procedures are not applicable and may
not be used after wet scrubbers; (FJ or
(F*) factors and associated emission
calculation procedures are used after
wet scrubbers.) When pollutant and
carbon dioxide concentrations have
been determined in Section 5.1. F,
factors are used.
5.2.1 Average F Factors. Table 1
shows average Fd, F,, and Fe factors
(scm/J, Bcf/miDion Btu) determined for
commonly used fuels. For fuels not
listed in Table 1. the F factors are
calculated according to the procedures
outlined in Section 5.2.2 of mis section.
5.2.2 Calculating an F Factor. If the
fuel burned is not listed in Table 1 or if
the owner or operator chooses to
determine an F factor rather than use
the tabulated data, F factors are
calculated using the equations below.
.The sampling and analysis procedures .
followed in obtaining data for these
calculations are subject to the approval
of the Administrator and the
Administrator should be consulted prior
to data collection.
5.1 Sampling. Use the outlet SOS or
Oi or CO* concentrations data obtained
in Section 3.1. Determine the particulate,
NO., and d or COi concentrations
according to methods specified in an
applicable subpart of the regulations.
5.2 Determination of an F Factor.
Select an average F factor (Section 5.2.1)
or calculate an applicable F factor
(Section 5.2.2.). If combined fuels are
fired, the selected or calculated F factors
are prorated using the procedures in
Section 5.2.3. F factors are ratios of the
gas volume released during combustion
of a fuel divided by the heat content of
the fuel A dry F factor (F«) is the ratio of
the volume of dry flue gases generated
to the calorific value of the fuel
combusted: a wet F factor (Fw) is the
ratio of the volume of wet flue gases
generated to the calorific value of the
fuel combusted; and the carbon F factor
(FJ is the ratio of the volume of carbon
dioxide generated to the calorific value
of the fuel combusted. When pollutant
For SI Units:
227.0(1H) * 95.7(tC) * 35.4(15) * 8.6(tN) - 28.5(10)
347.4(W)49S.7(tt)+35.4(K)+8.6(W)-M.5(tO)+13.0(tH20)«*
GCV
For English Onits:
106C5.57(tH)
1.53(tC) * 0.57(XS)
GCV
O.U(IH) - 0.46(tt)l
106[5.57{XH)+1 .53(XCH>.57(lS)+0.14(»0-0.46(IO)-t0.
CCV_
106ro.3Z1(tC)l
The SHjO tem nay be onitted if SH and SO include the unavailable
hydrogen and oxygen In the for* of M.O.
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Where:
F» F., and F, have the units of scm/J, or scf/
million Btu; %H, XC. XS, XN. XO. and
XHiO are the concentrations by weight
(expressed in percent) of hydrogen,
carbon, sulfur, nitrogen, oxygen, and
. water from an ultimate analysis of the
fuel; and GCV is the gross calorific value
of the fuel in kj/kg or Btu/lb and
consistent with the ultimate analysis.
Follow ASTM D 2015* for solid fuels, D
240* for liquid fuels, and D1826* for
gaseous fuels as applicable in '
determining GCV.

5.2.3 Combined Fuel Firing F Factor.
For affected facilities firing
combinations of fossil fuels or fossil
. fuels and wood residue, the Fd. F,, or Fc
factors determined by Sections 5.2.1 or
5.2.2 of this section shall be prorated in
accordance with applicable formula as
follows:
n
F* • £ XL FJL or
n
t
k-1
xk Fwk or
Fc " E xk Fck
k«1 c
Where:
x»=The fraction of total heat input derived
from each type of fuel, K,
n=The number of fuels being burned in,
combination.

5.3 Calculation of Emission Rate. .
Select from the following paragraphs the
applicable calculation procedure and
calculate the participate, SO«, and NO,
emission rate. The values in the
equations are defined as:
E=Pollutant emission rate, ng/J (Ib/million
Btu).
C«= Pollutant concentration, ng/scm (Ib/sci).
Note.—It is necessary in some cases to
convert measured concentration units to
other units for these calculations.
Use the following table for such
conversions:

Conversion Factor* for Concentration
To-
MuWplybir-
e/icm
me/Km
PpnKSOJ
PpnXNOJ
Ppm/(SOJ
ppm/(NOJ
1.194X10-'
5.3.1 Oxygen-Based F Factor
Procedure.
5.3.1.1 Dry Basis. When both percent
oxygen (SOaj and the pollutant
concentration (Cd) are measured in the
flue gas on a dry basis, the following
equation is applicable:
F r
L
20.9
d L20.9 - XO.j

5.3.1.2 Wet Basis. When both the
percent oxygen (%Ot») and the pollutant
concentration (C,) are measured in the
flue gas on a wet basis, the following
equations are applicable: (Note: Fw
factors are not applicable after wet
scrubbers.)

t.i * - f.e T 20.9 1
*•' • w kZO.SJl - B^j)- *0ft

Where:
Bw,«= Proportion by volume of water vapor in
the ambient air.

In lieu of actual measurement, B..
may be estimated as follows:
Note.—The following estimating factors are
selected to assure that any negative error
Introduced in the term:

, 20jJ »
20.9(1 - B) • XOj

will not be larger than -1.5 percent
However, positive errors, or over-
estimation of emissions, of as much as 5
percent may be introduced depending
upon the geographic location of the
facility and the associated range of
ambient mositure.
(i) Bw»=0.027. This factor may be used
as a constant value at any location.
(ii) Bw.=Highest monthly average of
&«. which occurred within a calendar
year at the nearest Weather Service
Station.
(iii) Bwm=Highest daily average of B..
which occurred within a calendar month
at the nearest Weather Service Station,
calculated from the data for the past 3
years. This factor shall be calculated for
each month and may be used as an
estimating factor for the respective
calendar month.
(b)
fa
20.9
-1
Where:
Bn=Proportion by volume of water vapor in
the stack gas.

5.3.1.3 Dry/Wet Basis. When the
pollutant concentration (Cw) is measured
on a wet basis and the oxygen
concentration (%O*i) or measured on a
dry basis, the following equation is
applicable:
[7
T] t
20.9
20.9 - XO,
-3
'2d

When the pollutant concentration (CJ
is measured on a dry basis and the
oxygen concentration (%OiJ is
measured on a wet basis, the following
equation is applicable:.
CdFd
20.9
20.9 -
SO,
2w
ws'
5.3.2 Carbon Dioxide-Based F Factor
Procedure.
5.3.2.1 Dry Basis. When both the
percent carbon dioxide (%CO*j) and the
pollutant concentration (Cd) are
measured in the flue gas on a dry basis,
the following equation is applicable:
2d

5.3-2.2 Wet Basis. When both the
percent carbon dioxide (%COtw) and the
pollutant concentration (Cw) are
measured on a wet basis, the following
equation is applicable:
5.3.2.3 Dry/Wet Basis. When the
pollutant concentration (Cw) is measured
on a wet basis and the percent carbon
dioxide (%CO»J is measured on a dry
basis, the following equation is
applicable:

C. F ifin
When the pollutant concentration (CJ
is measured on a dry basis and the
precent carbon dioxide (%COt,) is
measured on a wet basis, the following
equation is applicable:
5.4 Calculation of Emission Rate
from Combined Cycle-Gas Turbine
Systems. For gas turbine-steam
generator combined cycle systems, the
emissions from supplemental fuel fired
to the steam generator or the percentage
reduction in potential (SO>) emissions
cannot be determined directly. Using
measurements from the gas turbine
exhaust (performance test, subpart GG)
and the combined exhaust gases from
the steam generator, calculate the
emission rates for these two points
following the appropriate paragraphs in
Section 5.3.
Note. — Fw factors shall not be used to
determine emission rates from gas turbines
because of the injection of steam nor to
calculate emission rates after wet scrubbers;
ft or Fe factor and associated calculation
procedures are used to combine effluent
emissions according to the procedure in
Paragraph 5.2.3.
The emission rate from the steam generator
is calculated as:
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Federal Register / Vol. 44. No. 113 / Monday. June 11. 1979 / Rules and Regulations
4. Calculation of Overall Reduction in
Potential Sulfur Dioxide Emission
4.1 The overall percent sulfur
dioxide reduction calculation uses the
sulfur dioxide concentration at the inlet
to the sulfur dioxide control device as
the base value. Any sulfur redaction
realized through fuel cleaning is
introduced into the equation as an
average percent reduction, J6R,.
4.2 Calculate the overall percent
sulfur reduction CK
ioon.0-
Where:

XR,
Overall sulfur dioxide reduction; percent.

XRf • Sulfur dioxide removal, efficiency of fuel pretreatment

from Section 2; percent. Refer to applicable subpart

for definition of applicable averaging period.

XR • Sulfur dioxide removal efficiency of sulfur dioxide control

device either Og or C02 - based calculation or calculated

fro* fuel analysts and emission data, from Section 3;

percent. Refer to applicable subpart for definition of

applicable averaging period.

5. Calculation of Particulate, Sulfur
Dioxide, and Nitrogen Oxidea Emission
Rates
and oxygen concentrations have been
determined in Section 5.1. wet or dry P
factors are used. (Fw) factors and
associated emission calculation
procedures «re not applicable and may
not be used after wet scrubbers; (FJ or
IFJ factors and associated emission
calculation procedures are used after
wet scrubbers.) When pollutant and
carbon dioxide concentrations have
been determined in Section 5.1, Fe
factors are used.
5.2.1 Average FFactors. Table 1
shows average Fd. F*, and Fc factors
(scm/J, scf/million Btu) determined for
commonly used fuels. For fuels not
listed in Table 1, the F factors are
calculated according to the procedures
outlined in Section 5.2.2 of this section.
5.2.2 Calculating an F Factor. If the
fuel burned is not listed in Table 1 or if
the owner or operator chooses to
determine an F factor rather than use
the tabulated data, F factors are
calculated using the equations below.
.The sampling and analysis procedures .
followed in obtaining data for these
calculations are subject to the approval
of the Administrator and the
Administrator should be consulted prior
to data collection.
5.1 Sampling. Use the outlet SO, or
Oi or COt concentrations data obtained
in Section 3,1. Determine the particulate,
NOi, and O, or CO* concentrations
according to methods specified in an
applicable subpart of the regulations.
5.2 Determination of an F Factor.
Select an average F factor (Section 5.2.1)
or calculate an applicable F factor
(Section 5.2.2.). If combined fuels are
fired, the selected or calculated F factors
are prorated using the procedures in
Section 5.2.3. F factors are ratios of the
gas volume released during combustion
of a fuel divided by the heat content of
the fuel A dry F factor (FJ is the ratio of
the volume of dry flue gases generated
to the calorific value of the fuel
combusted; a wet F factor (Fw) is the
ratio of the volume of wet flue gases
generated to the calorific value of the
fuel combusted; and the carbon F factor
(Fc) is die ratio of the volume of carbon
dioxide generated to the calorific value
of the fuel combusted. When pollutant
For SI Units:
2?7.0(«H) * 9S.7(tCl * 35.4(15) * 8.6(XN) - 28.5(M)
6CV '•

347.4(»)+9S.7(tt)+35.4(SS)+a.6(W)-28.5(W}+13.0(»20)«*
W.OftC
For English units:
106[5.57(tH) * 1.53(»C) + 0.57(XS)
GCV
O.U(XH) - 0.46(10)3
106[5.57(*H)-t-1.53(JC)*0.57(XS)40.14(XN)-0.46(XO)*0.
6CV_
106ro.321(tC)l
fiCV
The XHjO tem may be omitted if XH and SO include the unavailable
hydrogen and oxygen In the for* of M-O.
IV-328
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Federal Register / Vol. 44, No. 113 / Monday. June 11. 1979 / Rules and Regulations
" *
«t
Where:
E.cPollutant emission rate from steam
generator effluent, ng/I (Ib/million Btu).
£.•= Pollutant emission rate in combined
cycle effluent; ng/I (Ib/million Btu).
E^= Pollutant emission rate from gas turbine
effluent; ng/J (Ib/million Btu).
X^ =Fraction of total heat input from
supplemental fuel fired to the steam
generator.
X^= Fraction of total heat input from gas
turbine exhaust gases.
Note. — The total heat input to the steam
generator is the sum of the heat input from
supplemental fuel fired to the steam
generator and the heat input to the steam
generator from the exhaust gases from the
gas turbine.
5.5 Effect of Wet Scrubber Exhaust,
Direct-Fired Reheat Fuel Burning. Some
wet scrubber systems require that the
temperature of the exhaust gas be raised
above the moisture dew-point prior to
the gas entering the stack. One method
used to accomplish this is directfiring of
an auxiliary burner into the exhaust gas.
The heat required for such burners is
from 1 to 2 percent of total heat input of
the steam generating plant. The effect of
this fuel burning on the exhaust gas
components will be less than ±1.0
percent and will have a similar effect on
emission rate calculations. Because of
this small effect, a determination of
effluent gas constituents from direct-
fired reheat burners for correction of
stack gas concentrations is not
necessary.
Tabto 19-1.—f Factors tor Kvfeu* fuels •
F.
e.
Fuellyp*
OK*
10* Btu
10* Btu
•ct
10* Btu
CO*
Bitunwwut •.„.„„„._„
1100% ,...,,
mt
QM:
Mttnl „„ . ............

(MM*-..,,,,.,, ,..,
Wood
WmlBirt ;,

_ 2.71x10"'
2.63x10"'
2.65x10"'
2>7x1Q"'
2.43x10"'
2.34X10"'
2.34 xlO"'
246x10"'
2.56x10"'

(10100)
((760)
(0660)
(9190)
(«710)
(8710)
(8710)
(8240)
(B600) .

163X10"'
Z66X10"'
3-21x10"'
2.77x10"'
235X10"'
^74x10-•
2.79x10"'

(10540)
(10640)
(11950)
(10320)
(10610)
(10200)
(10390)

0.530x10"'
0.484x10"'
0.513x10"'
0.383x10"'
0.267x10"'
0.321 X10"»
.0.337x10"'
0.492x10"'
0.497x10"'
(1970)
(1600)
(1910)
(1420)
(1040)
(1190)
(1250)
(1830)
(1850)
•A»c
ng to ASTM 0 388-66.
• Crude, residual, or (Ssttlate.
•DitarmirxxJ at (tandvd condition*; 20' C (68* F) nd 780 mm Hg (29.92 In. Hg).
6. Calculation of Confidence Limits for
Inlet and Outlet Monitoring Data

6.1 Mean Emission Rates. Calculate
the mean emission rates using hourly
averages in ng/] (Ib/million Btu) for SOt
and NO, outlet data and, if applicable,
SO, inlet data using the following
equations:
t x.
Where:
E.=Mean outlet emission rate; ng/J (lb/
million Btu).
E,=Mean inlet emission rate; ng/] (Ib/million
Btu).
Xc=Hourly average outlet emission rate; ng/]
(Ib/million Btu).
x,=Hourly average in let emission rate; ng/j
(Ib/million Btu).
Ho=Number of outlet hourly averages
available for the reporting period.
HI—Number of Inlet hourly averages
available for reporting period.
6.2 Standard Deviation of Hourly
Emission Rates. Calculate the standard
deviation of the available outlet hourly
average emission rates for SO. and NO,
and, if applicable, the available inlet
hourly average emission rates for SO.
using the following equations:
Where:
•»= Standard deviation of the average outlet
hourly average emission rates for the
reporting period: ng/] (Ib/million Btu).
»,= Standard deviation of the average inlet
hourly average emission rates for the
reporting period: ng/] (Ib/million Btu).
6.3 Confidence Limits. Calculate the
lower confidence limit for the mean
outlet emission rates for SO. and NO,
and, if applicable, the upper confidence
limit for the mean inlet emission rate for
SO. using the following equations:
E,*=E,+U.MB,
Where:
E/«=The lower confidence limit for the mean
outlet emission rates; ng/J (Ib/million
Btu).
E,* =The upper confidence limit for the mean
inlet emission rate; ng/) (Ib/million Btu).
U«= Values shown below for the indicated
number of available data points (n):
n
t
a
4
6
e
7
8
9
10
11
12-16
17-21
22-26
27-31
32-51
52-91
92-1S1
152 armor*
6.31
2.42
2.35
2.13
2.02
1.94
1.89
136
1.63
131
1.77
1.73
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 of hourly average data
points.

7. Calculation to Demonstrate
Compliance When Available
Monitoring Data Are Less Than the
Required Minimum
7.1 Determine Potential Combustion
Concentration (PCC) for SOt.
7.1.1 When the removal efficiency
due to fuel pretreatment (% Rr) is
included in the overall reduction in
potential sulfur dioxide emissions (% RJ
and the "as-fired" fuel analysis is not
used, the potential combustion
concentration (PCC) is determined as
follows:
PCC
PCC
* 2
Ib/million Btu.
Where:
Potential emissions removed by the pretreatment
process, using the fuel parameters defined In
section 2.3; ng/J (Ib/m1ll1on Btu).
IV-329
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Federal Register / Vol. 44. No. 113 / Monday. June 11, ^979 / Rules and Regulations
7.1.2 When the "as-fired" fuel-
analysis is used and the removal
efficiency due to fuel pretreatment (% R()
is not included in the overall reduction
in potential sulfur dioxide emissions [%
R,). the potential combustion
concentration (PCC) is determined as
follows:
PCC«=I.
PCC
PCC
I. * 2
* 2
When:
I. ~ The sulfur dioxide teput rate as defined
in section 3.3
7.1.3 When the •'as-fired" fuel
analysis is used and the removal
efficiency due to fuel pretreatment (% RJ
is included in the overall reduction (%
RO). the potential combustion
concentration (PCC) is determined as
follows:
ng/J
10 ; Ib/«1l11on Btu.
7.1.4 When inlet monitoring data are
used and the removal efficiency due to
fuel pretreatment (% Rf) is not included
in the overall reduction in potential
sulfur dioxide emissions (% RO), the
potential combustion concentration
(PCC) is determined as follows:
Where:
E,* = The upper confidence limit of the mean
inlet emission rate, as determined in
section 6.3.

7.2 Determine Allowable Emission
Rates
7.2.1 NOV Use the allowable
emission rates for NO, as directly
defined by the applicable standard in
terms of ng/J (Ib/million Bra).
7.2.2 SO* Use the potential
combustion concentration (PCC) for SOf
as determined in section 7.1. to
determine the applicable emission
standard. If the applicable standard is
an allowable emission rate hi ng/J (lb/
million Btu), the allowable emission rate
is used as EM*. If the applicable standard
is an allowable percent emission,
calculate the allowable emission rate
(Eftd) using the following equation:
Where:
% PCC = Allowable percent emission as
defined by the applicable standard;
percent.

73 Calculate & * /Eud. To determine
compliance for the reporting period
calculate the ratio:
Where:
Eg* = The lower confidence limit for the
mean outlet emission rates, as defined in
section 6.3; ng/J (Ib/million Btu).
£„,] = Allowable emission rate as defined in
section 7.2; ng/J (Ib/million Btu).
If £„•/£«„ is equal to or less than 1.0, the
facility is in compliance; if £.*/£*« is greater
than 1.0, the facility is not in compliance for
the reporting period.
(FR Doc. 7C-17M7 filed «-»-7» Mi «•)
IV-330
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
GENERAL PROVISIONS
SUBPART A
-------
Federal Register / Vol. 44. No. 106 / Thursday. May 31. 1979 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY

[40 CFH Parts W and 61]

IFRL 1085-1]

Standards of Performance for New
Stationary Sources and National
Emission Standards for Hazardous Air
Pollutants; Definition of "Commenced"

4QENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed Rule.

SUMMARY: This action proposes an
amendment to the definition of
"commenced" as used under 40 CFR
Parts 60 and 61 (standards of
performance for new stationary sources
and national emission standards for
hazardous air pollutants). The
legislative history of the Clean Air Act
Amendments of 1977 indicates that EPA
should revise the definition of
"commenced" to be consistent with the
definition contained in the prevention of
significant deterioration requirements of
the Act. This proposal would effect that
revision.
DATES: Comments must be received on
or before July 30,1979.
ADDRESSES: Comments should be
submitted to Jack R. Farmer, Chief,
Standards Development Branch (MD-
13), Emission Standards and Engineering
Division, Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711. Public comments
received may be inspected and copied
at the Public Information Reference Unit
(EPA Library) Room 2922,401 M Street,
S.W., Washington. D.C.
FOR FURTHER INFORMATION CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711. telephone number 919-
541-5271.
SUPPLEMENTARY INFORMATION: For
many of EPA's regulations, it is
important to determine whether a
facility has commenced construction by
a certain date. For instance, as provided
under section 111 of the Clean Air Act,
facilities for which construction is
commenced on or after the date of
proposal of standards of performance
are covered by the promulgated
standards. The definition of
"commenced" is thus one factor
determining the scope of coverage of the
proposed standards. "Commenced" is
currently defined under 40 CFR Part 60
as meaning:
* * * with respect to the definition of "new
•ouroe" in section lll(a)(2) of the Act that an
owner or operator has undertaken a
continuous program of construction or
modification or that an owner or operator has
entered into a contractual obligation to
undertake and complete, within a reasonable
time, a continuous program of construction or
modification.

A similar definition (minus the
reference to section lll(a)(2)) is used
under 40 CFR Part 61. As provided under
section 112 of the Act facilities which
commence construction after the date of
proposal of a national emission
standard for a hazardous air pollutant
are subject to different compliance
schedule requirements than those
facilities which commence before
proposal.
The Clean Air Act Amendments of
1977 include a definition of
"commenced" under Part C—Prevention
of Significant Deterioration (PSD) of Air
Quality. The PSD definition of
"commenced" requires an owner or
operator to obtain all necessary
preconstruction permits and either (1) to
have begun physical on-site construction
or (2) to have entered into a binding
agreement with significant cancellation
penalties before a project is considered
to have "commenced."
On November 1,1977, Congress
adopted some technical and conforming
amendments to the Clean Air Act
Amendments of 1977. Representative
Paul Rogers presented a Summary and
Statement of Intent which stated:
In no event is there any intent to inhibit or
prevent the Agency from revising its existing
regulations to conform with the requirements
of section 165. In fact, the Agency should do
so as soon as possible. It is also expected
that the Agency will act as soon as possible
to revise its new source performance
standards and the definition of 'commenced
construction' for the purpose of those revised
standards to conform to the definition
contained in part C

In view of this background, EPA has
decided to make the definition of
"commenced" as used under Part 60
consistent with the definitions used
under the PSD requirement of Parts 51
and 52. Even though Congress did not
specify any changes to the definition
under Part 61, it is reasonable to also
change that definition to be consistent
with those under Parts 60,51, and 52.
The manner in which the definition
would be interpreted is expressed in the
preamble to the PSD regulations 43 FR
26395-26396. For complete consistency
with the Clean Air Act and Parts 51 and
52, a new definition of "necessary
preconstruction approvals or permits"
has also been added.
EPA does not intend that sources
would be brought under the standards
by the revised definitions that would not
have been covered by the existing
definitions, The revised definitions
would be effective 30 days after
promulgation of the final definitions.
Facilities which have commenced
construction under the present
definitions before the effective date of
the revised definitions would be
considered to have commenced
construction under the revised
definitions, i.e., the revised definitions
would not be applied retroactively.
Note, however, that under the PSD
regulations, sources could be required to
apply control technology capable of
meeting the most recent standard of
performance even though that standard
is not applicable, because the applicable
standard of performance requirements
are only the minimum criteria for
granting a PSD permit.
During the public comment period,
comments are invited regarding the
impact of the revised definition. In
particular, comments are invited
regarding actual compliance problems
which may occur because of this
revision.
Dated: May 23,1979.

Douglas M. Costle,
Administrator.
It is proposed to amend 40 CFR Parts
60 and 61 by amending § § 60.2(i) and
61.02(d) and by adding §§ 60.2(cc) and
61.02(q) as follows:

PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES

Subpart A—General Provisions

560.2 Definitions.
(i) "Commenced" means, with respect
to the definition of "new source" in
section lll(a)(2) of the Act, either that:
(1) An owner or operator has obtained
all necessary preconstruction approvals
or permits and either has:
(i) Begun, or caused to begin, a
continuous program of physical on-site
construction of the facility to be
completed within a reasonable time; or
(ii) Entered into binding agreements or
contractual obligations, which cannot be
cancelled or modified without
substantial loss to the owner or
operator, to undertake a program of
construction of the facility to be
completed within a reasonable time, or
(2) An owner or operator had
commenced construction before
(effective date of this definition) under
V-A-7
-------
Federal Register / Vol. 44. No. 106 / Thursday. May 31.1979 / Proposed Rules
the definition of "commenced" in effect
before (effective date of this definition).
*****
(cc) "Necessary ^reconstruction
approvals or permits" means those
permits or approvals required under
Federal air quality control laws and
regulations and those air quality control
laws and regulations which are part of
the applicable State implementation
plan.
(Sec. 111. 301(a) of the Clean Air Act as
amended (42 U.S.C. 7411.7601(a))).
V-A-8
-------
ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES

FOSSIL FUEL-FIRED STEAM GENERATORS
SUBPART D
-------
Federal Register / Vol. 44. No. 126 / Thursday. June 28, 1979 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY

[40 CFR Part 60]

[FRL 1094-6]

Standards of Performance for New
Stationary Sources; FossJI-Fuel-Flred
Industrial Steam Generators
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Advance Notice of Proposed
Rulemaking.

SUMMARY: EPA seeks comments on its
plan to develop and implement new
source performance standards for air
pollutants from fossil-fuel-fired
industrial (non-utility) steam generators.
The Clean Air Act, as amended, August
1977, requires the EPA to develop
standards for categories of fossil-fuel-
fired stationary sources. The standards
will require application of the best
systems of emission reduction for
particulates, sulfur dioxide, and nitrogen
oxides to new industrial steam
generators.
DATES: Comments must be received on
or before August 27,1979.
ADDRESS: Comments should be
submitted to the Central Docket Section
(A-130), United States Environmental
Protection Agency, 401 M Street, S.W.
Washington, D.C. 20460, ATTN: Docket
No. A79-02.
FOR FURTHER INFORMATION CONTACT:
Stanley T. Cuffe. Chief, Industrial
Studies Branch (MD-13), Emission
Standards and Engineering Division,
United States Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, (919) 541-5295.
SUPPLEMENTARY INFORMATION: In
December 1971, pursuant to Section 111
of the Clean Air Act, the Administrator
promulgated standards of performance
for particulate, sulfur dioxide, and
oxides of nitrogen from new or modified
fossil fuel fired steam generators with
greater than 250 million BTU/hour heat
input (40 CFR 60.60). Since that time, the
technology for controlling these
emissions has been improved. In August
1977, Congress adopted amendments to
the Clean Air Act which specified that
the Environmental Protection Agency
develop standards of performance for
categories of fossil-fuel-fired stationary
sources. The standards are to establish
allowable emission limitations and
require the achievement of a percentage
reduction in the emissions. EPA is
required to consider a broad range of
issues in promulgating or revising a
standard issued under Section 111 of the
Clean Air Act.
Pursuant to the requirements of the
Act, EPA developed and proposed on
September 19,1978, a revised standard
applicable to fossil-fuel-fired utility
boilers with heat input greater than 250
MM BTU/hour.

Development of Industrial Boiler
Standard

In June 1978, the Agency initiated a
program to develop standards which
would apply to all sizes and categories
of industrial (non-utility) fossil-fuel-fired
steam generators. In this program, the
Agency is studying the technological,
economic, and other information needed
to establish a basis for standards for
particulate. sulfur dioxide and oxides of
nitrogen emissions from fossil-fuel-fired
steam generators. Pertinent information
is being gathered on eight technologies
for reducing boiler emissions: oil
cleaning and existing clean oil, coal
cleaning and existing clean coal;
synthetic fuels; fluidized bed
combustion; particulate control; flue gas
desu'furization; NOx combustion
modifications; and NOx flue gas
tre.it/nent. The studies for each
technology will discuss the
characteristics, emission reduction
methods and potential control costs,
energy and environmental
considerations and emission test data. A
status report on the studies was
presented to the National Air Pollution
Control Techniques Advisory
Committee (NAPCTAC), on January 11.
1979. Future presentations to the
NAPCTAC will be announced in the
Federal Register. The final technological
and economic documentation necessary
to support the standards is scheduled for
completion by June 1980. Interested
persons are invited to participate in
Agency efforts by submitting written
data, opinions, or arguments as they
may desire. The Agency is specifically
interested in information on the
following subjects.
a. Should one standard be proposed
for all industrial applications or should
standards be set for separate industrial
categories?
b. Should a single standard be
proposed for all sizes of industrial
boilers or should several standards be
proposed for various boiler size
categories?
c. Should emerging technologies such
as solvent refined coal, fluidized bed
combustion, and synthetic natural gas
be exempt from industrial boiler
standards, should they have separate
standards, or should they be required to
meet the same standards as
conventional boilers burning natural
fuels?
d. Will enforcement of standards at
cogeneration facilities present special
problems which should be considered?
e. How prevalent is the use of lignite
and anthracite coal in industrial boilers?
f. Are there special problems which
should be considered when controlling
particulate, SO,, or NO. emissions from
combustion of lignite or anthracite.
coals?
Dated: June 13.1979.
Douglas M. Costle,
Administrator.
[FR Doc. 7B-200M Filed «-27-7ft &4i «m|
WLUNQ CODE (MO-01-M
V-D-2
-------
Federal Register / Vol. 44. No. 127 / Friday. )une 29. 1979 / Proposed Rules
[40 CFR Part 60]

[FRL 1207-6; Docket No. EN 79-13]

Standards of Performance for New
Stationary Sources; Adjustment of
Opacity Standard for Fossil Fuel Fired
Steam Generator
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed Rule.

SUMMARY: EPA proposes to adjust the
NSPS opacity standard applicable to
Southwestern Public Service Company's
Harrington Station Unit #1 in Amarillo,
Texas. The proposal is based upon
Southwestern's demonstration of the
conditions that entitle it to such an
adjustment under 40 CFR 60.11(e).
DATES: Comments must be received on
or before July 30,1979.
ADDRESSES: Comments should be
submitted in writing to: Edward E.
Reich, Director, Division of Stationary
Source Enforcement (EN-341),
Environmental Protection Agency, 401 M
Street S.W., Washington, D.C. 20460.
Background information and comments
upon the proposed standard will be
available for public inspection and
copying at the EPA Public Information
Reference Unit, Room 2992 (EPA
Library), 401 M Street S.W.,
Washington, D.C. 20460 Specify Docket
No. EN 79-13.
FOR FURTHER INFOMATION CONTACT:
Richard Biondi, Division of Stationary
Source Enforcement (EN-341),
Environmental Protection Agency, 401 M
Street S.W., Washington, D.C. 20460,
telephone no. 202-755-2564.
SUPPLEMENTARY INFORMATION: The
Standards of performance for fossil fuel-
fired steam generators as promulgated
under Subpart D of Part 60 on December
23,1971 (36 FR 24876) and amended on
December 5,1977 (42 FR 61537) allow
emissions of up to 20 percent opacity,
except that 27 percent opacity is
allowed for one 6-minute period in any
hour. This standard also requires
reporting as excess emissions all hourly
periods during which there are two or
more six-minute periods when the
averages opacity exceeds 20 percent.
On December 15,1977, Southwestern
Public Service Company (SPSC) of
Amarillo, Texas, petitioned the
Administrator under 40 CFR 60.11(e) to
adjust the NSPS 20% opacity standard
applicable to its Harrington Station coal
fired Unit #1 in Amarillo, Texas. The
Administrator proposes to grant the
petition for adjustment, as SPSC has
demonstrated the presence at its
Harrington Station Unit #1 of the
conditions that entitle it to such relief,
as specified in 40 CFR 60.11(e)(3).
On the basis of performance tests
conducted on July 18-20,1977, the
Administrator determined that Unit #1
was in compliance with all applicable
new source performance standards
except opacity. Six minute opacity
average during the test indicated results
as high as 35-38%, while a previously
recorded value showed a maximum of
47.8% on July 16,1977. By letter of
December 5,1977, SPSC was notified of
the Administrator's finding and its right
to petition for adjustment of the opacity
standard, which it did in a timely
manner.
In its petition for adjustment of the
opacity standard, SPSC made the
following showing: (a) the affected
facility and associated air pollution
control equipment were operated and
maintained in a manner to minimize the
opacity of emissions during the
performance tests; (b) the tests were
performed under the conditions
established by the Administrator, and
(c) the affected facility and associated
air pollution control equipment were
incapable of being adjusted or operated
to meet the applicable opacity standard.
As described in the March 8,1974
Federal Register (39 FR 9308), the
Agency utilizes opacity standards as a
means to ensure proper operation and
maintenance of control systems on a
day to day basis. Opacity standards are
regulatory requirements, just like the
concentration/mass standards. They are
separate standards and it is not
necessary to show a violation of the
mass standard to support enforcement
of the opacity standard. Where opacity
and concentration/mass standards are
applicable to the same source, the
opacity standard is not more restrictive
than the concentration/mass standard.
The concentration/mass standard is
established at a level which will result
in the design, installation, and operation
of the best adequately demonstrated
system of emission reduction (taking
costs into account) for each source.
The control method used by SPSC at
Harrington Station Unit #1 is a hybrid
system that uses an electrostatic
precipitator and a marble bed scrubber.
Although the system can be altered to
meet the 20% opacity standard, the cost
of such alteration is excessive in view of
the system's current effectiveness in
. meeting all NSPS emission limitations
except opacity. Twenty percent opacity
could be achieved only by a four-fold
increase in pressure drop on the marble
bed scrubber (from 15 cm HaO to 60 cm
HiO), or by a 30% increase in the
specific collector area of the
electrostatic precipitator. Increasing the
pressure drop to 60 cm HaO would
require an additional $1.5 million
annually for operation and maintenance,
and would require that the scrubber be
redesigned to operate at the increased
pressure drop. Increasing the specific
collector area of the electrostatic
precipitator would cost approximately
an additional $4 million. Since this
facility can meet the mass standard with
the equipment installed, it does not
appear that the extensive redesign and
increased costs are warranted.
In view of the above, EPA proposes
that SPSC's Harrington Station Unit #1
be excused from compliance with the
20% opacity standard of 40 CFR
60.42(a)(2). As an alternative, it is
proposed that SPSC shall not cause to
be discharged into the atmosphere from
Harrington Station Unit #1 any gases
which exhibit greater than 35% opacity,
except that a maximum of 42% opacity
shall be permitted for not more than one
6 minute period in any hour. The
adjustment will not relieve SPSC of its
obligation to comply with any other
federal, state or local opacity
requirements.
Authority: This amendment is proposed
under the authority of Sections 111 and 301(a)
of the Clean Air Act, as amended (42 U.S.C.
7411 and 7601(a)).
• Dated: June 19,1979.
Douglas M Costle,
Administrator.
In consideration of the foregoing, it is
proposed to amend Part 60 of 40 CFR
Chapter I as follows:

Subpart D—Standards of Performance
for Fossil Fuel-Fired Steam Generators

1. Section 60.42 is amended by adding
paragraph (b)(l) as follows:

§ 60.42 Standard for partlculate matter.
(a) * * *
(b)(l) Southwestern Public Service
Company shall not cause to be
discharged into the atmosphere from its'
Harrington Station Unit #1 in Amarillo,
V-D-3
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Federal Register / Vol. 44. No. 127 / Friday, June 29. 1979 / Proposed Rules
Texas, any gases which exhibit greater
than 35% opacity, except that a
maximum of 42% opacity shall be
permitted for not more than 6 minutes in
any hour.
(Sec. Ill, 301(a), Clean Air Act as amended
(42 U.S.C. 7411. 7601.))
2. Section 60.45(g)(l) is amended by
adding paragraph (i) as follows:

160.45 Emission and fuel monitoring.
* • • * •

(«)***
(1) * * '
(i) For sources subject to the opacity
standard of Section 60.42(b)(l),
excession emissions are defined as any
six-minute period during which the
average opacity of emissions exceeds 35
percent opacity, except that one six-
minute average per hour of up to 42
percent opacity need not be reported.
|FR Doc 79-2015* Filed 0-28-79; MS am)
BILLING COM (MO-01-M
V-D-4
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
NITRIC ACID PLANTS
SUBPART G
-------
Federal Register / Vol. 44, No. 119 / Tuesday. June 19. 1979 / Proposed Rules
[40CFRPartW]

[FRL 1095-1]

Review of Standard* et Performance
for New Stationary Sources: Nitric
Add Plants

AOENCY: Environmental Protection
Agency (EPA).
ACTION: Review of standard*.

SUMMARY: EPA has reviewed the
standard of performance for nitric acid
plants. The review is required under the
Clean Air Act, as amended August 1977.
The purpose of this notice is to
announce EPA's intent not to undertake
revision of the standards at this time.
DATES: Comments must be received on
or before August 20,1079.
ADDRESSES: Send comments to the
Central Docket Section (A-130), U.S.
Environmental Protection Agency, 401 M
Street. S.W., Washington, D.C. 20460.
Attention: Docket No. A-79-08. The
document "A Review of Standards of
Performance for New Stationary
Sources—Nitric Acid Plants" (EPA
report number EPA-450/3-79-013) is
available upon request from Mr. Robert
Ajax (MD-13), Emission Standards and
Engineering Division, U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711.

TOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax. (919) 541-5271.
SUPPLEMENTARY INFORMATION:

Background
Prior to the promulgation of the NSPS
in 1971, only. 10 of the existing 194 weak
nitric acid (50 to BO percent acid)
production facilities were specifically
designed to accomplish NO, abatement.
V-G-2
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logisteg / Vol. 44. No. 119 / Tuesday. June 19. 1979 / Proposed Rules
Without control equipment, total NOn
emissions are approximately 3,000 ppm
in the stack gas, equivalent to a release
of 21.5 kg/Mg (43 Ib/ton) of 100 percent
acid produced.
At the time of the NOn New Source
Performance Standard (NSPS)
promulgation there were no State or
local NOa emission abatement
regulations in effect in the U.S. which
applied specifically to nitric acid
production plants. Ventura County,
California, had enacted a limitation of
250 ppm NOg to govern nitric acid plants
as well as steam generators and other
sources.
In August of 1971, the EPA proposed a
regulation under Section 111 of the
Clean Air Act to control nitrogen oxides {
emissions from nitric acid plants. The
regulation, promulgated in December
1971, requires that no owner or operator
of any nitric acid production unit (or
"train") producing "weak nitric acid"
oh a 11 discharge to the atmosphere from
any affected facility any gases which
contain nitrogen oxides, expressed as
NOa, in excess of 1.5 kg per metric ton of
odd produced (3.0 Ib per ton), the
production bsing expreosed as 100
percent nitric acid; and any gases which
exhibit 10 percent opacity or greater.
Ths Clean Air Act Amendmanto of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of
performance for new stationary sources
at least every 4 years [Section
lll(b)(l)(B)]. This notice announces that
EPA has completed a review of the
standard of performance for nitric acid
plants and invites comment on the
results of this review.

Findings
Industry Growth Rate

The average rate of production
increase for nitric acid fell from 9
percent/year in the 1960-1970 period to
0.7 percent from 1971 to 1977. The
decline in.demand for nitric acid
parallels that for nitrogen-based
fertilizers during the same period.
Nitric acid production shows an
increasing trend toward plant/unit
location and growth in the southern tier
of States. In 1971,48 percent of the
national production was in the south.
This figure increased to 54 percent in
51878.
About 50 percent of plant capacity in
1872 consisted of small to moderately
sized units (50 to 300-ton/day capacity).
Because of the economies of scale some
producers are electing to replace their
existing units with new, larger units.
New nitric acid production units have
been built as large as 910 Mg/day (1000
tons/day). The average size of new units
is approximately 430 Mg/day (500 tons/
day).

Control Technology

A mixture of nitrogen oxides (NOJ is
present in the tail gas from the ammonia
oxidation process for the production of
nitric acid. In modern U.S. single
pressure process plants producing 50 to
60 percent acid, uncontrolled NOn
emissions are generated at the rate of
about 21 kg/Mg of 100 percent acid (42
Ib/ton) corresponding to approximately
, '3000 ppm NOB (by volume) in the exit
gas stream. The catalytic reduction
process which was considered the best
demonstrated control technology at the
time the present standard was
established has been largely supplanted
by the extended absorption process as
the preferred control technology for NO0
emissions from new nitric acid plants.
The latter control system appears to
have become the technology of choice
for the nitric acid industry due to She
increasing cost and danger of shortages
of natural gas ussd in the catalytic
reduction process. Since the eaergy
crisis of the mid-1970's, over 50 percent
of the nitric acid plants that had come
on stream through mid-1978 and almost
SO percent of the plants scheduled to
come on stream through 1979 use the
extended absorption process for NOQ
control.

Levels Achievable with Demonstrated
Control Technology

All 14 of the new or modified
operational nitric acid production units
subject to NSPS and tested showed
compliance with the current standard of
1.50 kg/Mg (3 Ib/ton). The average of
seven sets of test data from catalytic
reduction-controlled plants is 0.22 kg/
Mg (0.44 Ib/ton), and the average of six
sets of test data from extended
absorption-controlled plants is 0.91 kg/
Mg (1.82 Ib/ton). All of the plants tested
were in compliance with the opacity
standard. It appears that the extended
absorption process, while it has become
the preferred control technology for NOn
control, cannot control these emissions
as efficiently as the catalytic reduction
process. In fact, over half of the test
results for extended absorption were
within 20 percent of the NOE standard.
The extended absorption process thus
appears to have limitations with respect
to N0n control, and compares
unfavorably with catalytic reduction in
its ability to reduce NOa emissions much
below the present NSPS level.

Economic Considerations Affecting the
NO* NSPS

The anhualized costs of the extended
absorption process and the catalytic
reduction NOn control methods appear
to be quite comparable. Capita] cost for
the extended absorption process is
appreciably higher than that for
catalytic reduction. However, this is
offset by the higher operating cost of the
latter system which requires
increasingly costly natural gas.

Conclusions

Based on the above findings, EPA
concludes that the existing standard of
performance is appropriate at this time.
While lower emission levels are
attainable, the energy penalty and
shortages of natural gas are concluded
to be a basis for retaining the current
otandard of performance under Section
111 of the Clean Air Act. However, tha
racent deregulation will alter the price
and availablity of natural gao, and
provided a basis for optimism about its
future availability for process and
pollution control purposes. The Agency.
therefore, plans to continue to assess the
standard as, the effect of deregulation
materializes. Moreover, it should be
noted that for the purpose of attaining
and maintaining national ambient air
quality standards and prevention of
significant deterioration requirements,
State Implementation Plan new source
reviews may in come cases require
greater emission reductions than those
required by the standards of
performance for new sources.

Public participation

All interested persons are invited to
comment on this review, the
conclusions, and EPA's planned action.
Comments should be submitted to: Mr.
Don Goodwin (MD-13), Emission
Standards and Engineering Division,
U.S. Environmenal Protection Agency,
Research Triangle Park, North Carolina
27711.
Dated: June 11,1079.
Douglas M. Gratia,
Administrator.
|FR Doc. TD-iemc Filed 8-18-79: &45 am]
OIUJKO COKE OKO-01-a •
V-G-3
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES

SUIFUKIC ACID PLANTS
SUBPART H
-------
PROPOSED RULES
NEW STATIONARY SOURCES: SULFURIC AGIO
PLANTS

Review of Performance Standards

AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of Standards.
SUMMARY: EPA has reviewed the
standards of performance for sulfuric
acid plants (40 CFR 60.80). The review
is required under the Clean Air Act, as
amended August 1977. The purpose of
this notice is to announce EPA's deci-
sion to not revise the standards at this
time and to solicit comments on this
decision.
DATES: Comments must be received
by May 14,1979.
ADDRESS: Send comments to: Mr.
Don Goodwin (MD-13), Emission
Standards and Engineering Division,
Environmental Protection Agency, Re-
search Triangle Park, North Carolina
27711.
FOR FURTHER
CONTACT:
INFORMATION
Mr. Robert AJax, telephone: (919)
541-5271. The document "A Review
of Standards of Performance for
New Stationary Sources—Sulfuric
Acid Plants" (EPA report number
EPA-450/3-79-003) is available upon
request from Mr. Robert Ajax (MD-
13), Emission Standards and En-
gineering Division, Environmental
Protection Agency, Research Trian-
gle Park, North Carolina 27711.
SUPPLEMENTARY INFORMATION:

BACKGROUND

Prior to the proposal of the standard
of performance in 1971, almost all ex-
isting contact process sulfuric acid
plants were of the single-absorption
design and had no SO, emission con-
trols. Emissions from these plants
ranged from 1500 to 6000 ppm SO* by
volume, or from 10.8 kg of SOz/Mg of
100 percent acid produced (21.5 lb/
ton) to 42.5 kg of SOa/Mg of 100 per-
cent acid produced (85 Ib/ton). Several
State and local agencies limited SO»
emissions to 500 ppm from new sulfu-
ric acid plants, but few such facilities
had been put into operation (EPA,
1971).
In August of 1971, the Environmen-
tal Protection Agency (EPA) proposed
a regulation under Section 111 of the
Clean Air Act to control SO, and sul-
furic acid mist emissions from sulfuric
acid plants. The regulation, promul-
gated in December 1971, requires that
no owner or operator of any new sul-
furic acid production unit producing
sulfuric acid by the contact process by
burning elemental sulfur, alkylation
acid, hydrogen sulfide, organic sul-
fides, mercaptans, or acid sludge shall
discharge into the atmosphere any
gases which contain sulfur dioxide in
excess of 2 kg/Mg (4 Ib/ton); any gases
which contain acid mist, expressed as
H.SO., in excess of 0.075 kg/Mg of
acid produced (0.15 Ib/ton), expressed
as 100 percent HtSO.; or any gases
which exhibit 10 percent opacity or
greater. Facilities which produce sul-
furic acid as a means of controlling
SO. emissions are not included under
this regulation.
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and. If appropriate,
revise established standards of per-
formance for new stationary sources
at least every 4 years [Section
HKbXlXB)]. This notice announces
that EPA has completed a review of
the standard of performance for sulfu-
ric acid plants and Invites comment on
the results of this review.

FINDINGS
INDUSTRY GROWTH

Since the proposal, 32 contact proc-
ess sulfuric acid units have been con-
structed. Of these, at least 24 units
result from growth In the phosphate
_ fertilizer industry and are dedicated to
the acidulation of phosphate rock.
mainly in the Southern U.S.
In 1976. over 70 percent of the total
national production of new sulfuric
acid was in the South. It is projected
that three of the four units predicted
to be coming on line each year will
most probably be located in the South.

BEST DEMONSTRATED CONTROL
TECHNOLOGY

Sulfur dioxide and acid mist are
present in the tail gas from the con-
tact process sulfuric acid production
unit. In modern four-stage converter
contact process plants burning sulfur
with approximately 8 percent SO, in
the converter feed, and producing 98
percent acid, SO, and acid mist emis-
sions are generated at the rate of 13 to
28 kg/Mg of 100 percent acid (26 to 56
Ib/ton) and 0.2 to 2 kg/Mg of 100 per-
cent acid (0.4 to 4 Ib/ton), respectively.
The dual absorption process is the
best demonstrated control technology
for SO, emissions from sulfuric acid
plants, while the high efficiency acid
mist eliminator is the best demonstrat-
ed control technology for acid mist
emissions. These two emission control
systems have become the systems of
choice for sulfuric acid plants built or
modified since the promulgation of
the NSPS. Twenty-eight of the 32 sul-
furic acid production plants subject to
the standard incorporate the dual ab-
sorption process; all 32 plants use the
high efficiency acid mist eliminator.

COMPLIANCE TEST RESULTS

All 32 sulfuric acid production units
subject to the standard showed com-
pliance with the current SO, standard
of 2 kg/Mg (4 Ib/ton). The 29 compli-
ance test results for dual absorption
plants ranged from a low of 0.16 kg/
Mg (0.32 Ib/ton) to a high of 1.9 kg/
Mg (3.7 Ib/ton) with an average of 0.9
kg/Mg (1.8 Ib/ton). Information re-
ceived on the performance of several
sulfuric acid plants indicates that low
SO, emission results achieved in NSPS
compliance tests apparently do not re-
flect day-to-day SO> emission levels.
These levels appear to rise toward the
standard as the conversion catalyst
ages and its activity drops. Additional-
ly, there may be some question about
the validity of low SO, NSPS values,
i.e.. less than 1 kg/Mg (2 Ib/ton), due
to errors in. the application of the
original EPA Method 8. This method
was revised on August 18, 1977, to In-
clude more detailed procedures to pre-
vent such errors.
All 32 affected sulfuric acid produc-
tion units also showed compliance
with the current acid mist standard of
0.075 kg/Mg of 100 percent acid (0.15
Ib/ton). The compliance test data are
all from plants with acid mist emission
control provided by the high efficien-
FEDERAL REGISTER, VOL 44, NO. 52—THURSDAY, MARCH IS, 1979
V-H-2
-------
cy acid mist eliminator. The data
showed a range with a low of 0.008 kg/
Mg (0.016 Ib/ton) to a high of 0.071
kg/Mg (0.141 Ib/ton), and an overall
average value of 0.04 kg/Mg (0.081 lb/
ton). Acid mist emission (and related
opacity) levels are unaffected by fac-
tors affecting Sd emissions, i.e., con-
version efficiency and catalyst aging.
Rather, acid mist emissions are pri-
marily a function of moisture levels in
the sulfur feedstock and air fed to the
sulfur burner, and the efficiency of
the final absorber operation. The
order-of-magnitude spread observed in
compliance test values is probably a
result of variation in these factors. Ad-
ditionally, the potential for impreci-
sion in the application of the original
EPA Method 8 may have contributed
to this spread.

POSSIBLE REVISION TO STANDARD

The compliance test data indicate
that the available control technology
could possibly meet both lower sulfur
dioxide and sulf uric acid mist emission
standards. However, the available test
data indicate that variability in indi-
cated emission rates occurs—possibly
as a result of process variables, and
test method precision. Therefore, to
meet a tighter standard designers and
operators would need to design for at-
tainment of a lower average emission
rate in order to retain a margin of
safety needed to accommodate emis-
sion variability. The available compli-
ance data do not provide a basis for
concluding that this is possible.
In contrast, the effect of catalyst
aging is controllable by more frequent
replacement. As an outside limit, com-
plete replacement of catalyst in the
first 3 beds of a four-bed converter 3
times as frequently as is normally
practiced could potentially maintain
emissions in the range of 1 to 1.5 kg/
Mg and would result in a net emission
reduction of approximately 0.3 kg/Mg
(0.6 Ib/ton).
Based on an estimated sulfuric acid
plant growth rate of four new produc-
tion lines per year between 1981 and
1984, a 50 percent reduction of the
present SO, NSPS level—from 2 kg/
Mg (4 Ib/ton) to 1 kg/Mg (2 Ib/ton)—
would result in a drop in the estimated
SO, contribution to these new sulfuric
acid plants to the total national SO,
emissions, from 0.04 percent to 0.02
percent (8,000 tons to 4,000 tons).

CONCLUSIONS

Based upon the above findings, EPA
concludes that the current best dem-
onstrated control technology, the duel
absorption process and the acid mist
-eliminator are identical in basic design
'to that used as the rationale for the
'original SO, standard. Therefore, from
'the standpoint of control technology.
and considering costs, and the small
PROPOSED RULES

quantity of emissions in question, it
does not appear necessary or appropri-
ate to revise the present standard of
performance adopted under Section
111 of the Clean Air Act. It should be
noted that for the purpose of attain-
ing national ambient air quality stand-
ards and prevention of significant de-
terioration, State Implementation
Plan new source reviews may in some
cases require greater emission reduc-.
tions than those required by standards
of performance for new sources.

PUBLIC PARTICIPATION

All interested persons are Invited to
comment on this review, the conclu-
sions, and EPA's planned action. Com-
ments should be submitted to: Mr.
Don Goodwin (MD-13), Emission
Standards and Engineering Division,
Environmental Protection Agency, Re-
search Triangle Park, N.C. 27711.
(Section 111(6)(1)(B) of the Clean Air Act,
as amended (42 U.S.C. 7411<6X1)(B».
Dated: March 9,1979.
DOUGLAS M. COSTLE,
Administrator.
[PR Doc. 79-7926 Filed 3-14-79; 8:45 am]
FEDERAL REGISTER, VOL 44, NO. M—THURSDAY, MARCH 15, 1979
V-H-3
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
PETROLEUM REFINERY
SUBPART J
-------
PROPOSED RULES
ENVIRONMENTAL PROTECTION
AGENCY

[40 CFR Port 60)

[FRL 1042-1]

STANDARDS OF PERFORMANCE FOR NEW
STATIONARY SOURCES

Amendment le Petroleum Refinery Clout Sulfur
Recovery Plant*

AGENCY: Environmental Protection
Agency (EPA).-
ACTION: Proposed rule.
SUMMARY: This action proposes to
amend the definition of small "petro-
leum refinery" contained in the stand-
ard of performance promulgated for
petroleum refinery Claus sulfur recov-
ery plants (43 FR 10866, March 15,
1978). The promulgated standard
exempts small Claus sulfur recovery
plants associated with a small petro-
leum refinery. Included in the defini-
tion of a small refinery is the qualifi-
cation that the petroleum refinery
must owned or controlled by a refiner
(or company) whose total crude oil
processing capacity is 137,500 barrels
per stream day (BSD) or less. Two
large oil companies (i.e., with more
than 137,500 BSD processing capacity)
filed a Petition for Review of the pro-
mulgated standard challenging the
standard and the applicability of the
exemption to only small companies.
After considering the arguments pre-
sented in this petition and reconsider-
ing the background information for
the promulgated standard, EPA be-
lieves it is appropriate to apply the ex-
emption to all small petroleum refin-
eries. Consequently, the proposed
amendment extends the exemption for
small Claus sulfur recovery plants lo-
cated in small petroleum refineries to
all companies regardless of their total
crude oil processing capacity.
This amendment will not will result
in any significant change in the envi-
ronmental, energy, or economic im-
pacts resulting from the promulgated
standard.
DATE: Comments must be received on
or before May 21,1979.
ADDRESS: Comments should be sub-
mitted to the Emission Standards and
Engineering Division (MD-13), Envi-
ronmental Protection Agency, Re-
search Triangle Park, North Carolina
27771, Attention: Mr. Jack R. Farmer.
Interested persons who desire an op-
portunity for the oral presentation of
data, views, or arguments should also
contact Mr. Farmer.
Docket: Docket No. OAQPS-79-10
containing all supporting information
used by EPA In developing the pro-
posed rule, as well as comments re-
ceived on this proposal will be availa-
ble for public inspection and copying
at the EPA Central Docket Section
(A-130), Room 2903B, Waterside Mall,
401 M Street, S.W., Washington, D.C.
20460.
FOR FURTHER INFORMATION
CONTACT:
Don R. Goodwin, Emission Stand-
ards and Engineering Division, Envi-
ronmental Protection Agency, Re-
search Triangle Park, North Caroli-
na 27711, telephone number 919-
541-5271.
SUPPLEMENTARY INFORMATION:

PROPOSED AMENDMENT AND BACKGROUND

It is proposed to amend Subpart J—
Standards of Performance for Petro-
leum Refineries to change the applica-
bility of the standard for new, modi-
fied, or reconstructed petroleum refin-
ery Claus sulfur recovery-plants.-The
amendment will exempt from the
standard all Claus sulfur recovery
plants with a capacity of 20 long tons
per day (LTD) or less associated with a
petroleum refinery having a process-
ing capacity of 50,000 BSD or less.
On October 4, 1976 (41 FR 43866),
EPA proposed standards of perform-
ance limiting SO, emissions from new,
modified, or reconstructed petroleum
refinery Claus sulfur recovery plants.
These standards applied to all petro-
leum refinery Claus sulfur recovery
plants, regardless of the size of the
dulfur recovery plant or the size of the
refinery involved. During the com-
ment period following proposal, sever-
al commenters presented information
showing that the economic impact of
the standards would be much more
severe on a small petroleum refinery
than on a large petroleum refinery. As
a result, EPA reexamined this point
and concluded that an exemption
from the standard was appropriate for
small sulfur recovery plants located in
small petroleum refineries. In defining
the "small petroleum refinery", EPA
adopted the definition included in sec-
tion 211(g) of the Clean Air Act as
amended August 1977 which defines a
small petroleum refinery as one of
50,000 BSD or less which is owned or
controlled by a company with no more
than 137,500 BSD of total crude oil
processing capacity.
On May 12. 1978, a Petition for
Review of the standard was filed in
the U.S. Court of Appeals for the Dis-
trict of Columbia Circuit on behalf of
Phillips Petroleum Company and Ash-
land Oil, Inc. Among other things, the
Petitioners argued that the exemption
from the standard for small sulfur re-
covery plants associated with small pe-
troleum refineries should apply in all
cases, regardless of the size (i.e., total
refining capacity) of the company
owning or controlling the refinery.
After a consideration of the points
covered in the Petition for Review and
the background information for the
promulgated standard, EPA agrees
with the Petitioners and is proposing
this amendment to the standard. The
Petitioners have agreed to dismiss
their entire Petition for Review if the
final regulation does not differ sub-
stantlvely from the proposal discussed
herein.

RATIONALE

As concluded in the preamble to the
promulgated regulation (43 FR 10866,
March 15, 1978) EPA's analysis of the
impact of the proposed standard on
the profitability of a small petroleum
refinery indicated this impact would
have been more severe than the corre-
sponding impact on a large petroleum
refinery. The attempt of the Agency
in allowing the exemption from the
standard was to:
(1) Lessen the adverse economic"
impact of the standard on the small
refinery compared to the large refin-
ery; and
(2) Have minimum impact on efforts
by States to encourage installation of
sulfur plants at small refineries where
none previously existed.
In considering the appropriateness
of an exemption from standard for
certain refineries, EPA first looked at
the cost per unit of sulfur recovered
(i.e., cost effectiveness) relative to the
size of the refinery Claus sulfur recov-
ery plant having to comply with the
standard. This analysis revealed a sig-
nificant deterioration hi cost effective-
ness for Claus sulfur recovery plant
capacities of 20 LTD or less. As a
result, EPA concluded that refinery
Claus sulfur recovery plants with a ca-
pacity of 20 LTD or less should be
exempted from the standard. Since
the economic impact of the standard
was also known to be dependent upon
the size of the refinery in which the
Claus sulfur recovery plant was locat-
ed, EPA reviewed its analysis of the
impact of the standard on different
size refineries. On the basis of this
analysis, EPA concluded that for re-
fineries of 50,000 BSD or less the re-
duction in profitability required by
the standard was unreasonable. Thus,
initial drafts of the standards provided
an exemption for Claus sulfur recov-
ery plants with a capacity of 20 LTD
or less associated with a petroleum re-
finery having a processing capacity of
50,000 BSD or less.
During internal EPA review of the
standard prior to promulgation, a rec-
ommendation was made that "small
petroleum refinery" be defined to be
consistent with section 211(g) of the
Clean Air Act. This provision defines a
small refinery as one with a total
crude oil processing capacity of 50,000
FfDERAL IEOISTII. VOL 44, NO. 55—TUESDAY, MARCH M, 1979
V-J-2
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PROPOSED RULES
BSD or less owned or controlled by a
—company with—a—total crude oil proc-
essing capacity of 137,500 BSD. This
suggestion was incorporated into the
standard. Thus, the promulgated
standard exempted and Claus sulfur
recovery plant with a capacity of 20
LTD or less associated with a petro-
leum refinery having processing capac-
ity of 50,000 BSD or less owned or con-
trolled by a company with a total
processing capacity of 137,500 BSD or
less.
In light of the evolution of this
standard, it is apparent that EPA did
not in this case conduct the analysis
required to support the requirement in
the standard that a small refinery be
owned or controlled by a company win
a total crude oil processing capacity of
137,500 BSD. Thus, the proposed
amendment will exempt from stand-
ards of performance all new, modified,
or reconstructed Claus sulfur recovery
plants with a capacity of 20 LTD or
—fess-associated with a-petroleum refin-
ery having a crude oil processing ca-
pacity of 50,000 BSD or less.

ENVIRONMENTAL, ECONOMIC AND
ENERGY IMPACTS

This amendment will result in a neg-
ligible increase in SO2 emissions com-
pared to the promulgated regulation.
Based on past trends in petroleum re-
finery and sulfur recovery plant con-
struction, very few large companies
are likely to build small petroleum re-
fineries with small sulfur recovery
plants. In addition, the few petroleum
refinery Claus sulfur recovery plants.
involved would be regulated by State
regulations at a control level only
somewhat less than that of the pro-
mulgated standard.
For the same reasons, this amend-
ment will result in a negligible de-
crease in costs and energy consump-
tion compared to the promulgated
standard.

MISCELLANEOUS

The docket is an organized and com-
plete file of all the information sub-
mitted to or otherwise considered by
EPA in the development of this rule-
making. The principal purposes of the
docket are: (1) To allow members of
the public and industries involved to
identify and participate in the rule-
making process, and (2) to serve as the
record for judicial review. The docket
is required under section 307(d) of the
Clean Air Act, as amended, and is
available for public inspection and
copying at the address above.
It should be noted that standards of
performance for new sources under
section 111 of the Clean Air Act re-
flect:
• • • application of the best technological
system of continuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impart and energy requirements) the Ad-
ministrator determines has been adequately
demonstrated. [Section llliaxl).]
Although there may be emission
control technology available that can •
reduce emissions below those levels re-
quired to comply with standards of
performance, this technology might
not be selected as the basis of stand-
ards of performance due to costs asso-
ciated with its use. Accordingly, stand-
ards of performance should not be
viewed as the ultimate in achievable
emission control. In fact, the Act re-
quires (or has the potential for requir-
ing) the imposition of a more stringent
emission standard in—several situa-_
tions.
For example, applicable costs do not
necessarily play as prominent a role in
determining the "lowest achievable
emission rate" for new or modified
sources locating in nonattainment
areas, i.e., those areas where statutori-
ly-mandated health and welfare stand-
ards are being violated. In this respect,
section 173 of the Act requires that a
new or modified source constructed in
an area which exceeds the NAAQS
must reduce emissions to the level
which reflects the "lowest achievable
emission rate" (LAER), as defined in
section 171(3), for such category of
source. The statute defines LAER as
that rate of emissions which reflects:
(A) the most stringent emission limitation
which is contained in the implementation
plan of any State for such class or category
of source, unless the owner or operator of
the proposed source demonstrates that such
limitations are not achievable, or
(B) the most stringent emission limitation
which is achieved in practice by such class
or category of source, whichever is more
stringent.
In no event can the emission rate
exceed any applicable new source per-
formance standard [section 171(3)].
A similar situation may arise under
the prevention of significant deteriora-
tion of air quality provisions of the
Act (Part C). These provisions require
that certain sources [referred to in
section 169(1)] employ "best available
control technology" [as defined in sec-
tion 163(3)] for all pollutants regulat-
ed under the Act. Best available con-
trol technology (BACT) must be deter-
mined on a case-by-case basis, taking
energy, environmental—and economic
impacts and other costs into account.
In no event may the application of
BACT result in emissions of any pol-
lutants which will exceed the emis-
sions allowed by any applicable stand-
ard established pursuant to section
111 (or 112) of the Act.
In all events, State Implementation
Plans (SIP's) approved or promulgated
under section 110 of the Act must pro-
vide for the attainment and mainte-
nance of national ambient air quality-
standards (NAAQS) designed to pro-
tect public health and welfare.- For
this purpose, SIP's must in some cases
require greater emission reductions
than those required by standards of
performance for new sources.
Finally. States are free under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under-seetioiv-UQv-According-
ly, new sources may in some cases be
subject to limitations more stringent
than EPA's standards of performance
under section 111, and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
Section 317 of the Clean Air Act re-
quires the Administrator to prepare an
economic impact assessment for revi-
sions determined by the Administrator
to be substantial. The Administrator
has determined that the economic
impact of the proposed amendment is
not substantial and an economic
impact assessment is not required.
Dated: March 9, 1979.
BARBARA BLUM,
Acting Administrator.
It Is proposed to amend Part 60 of
Chapter I, Title 40 of the Code of Fed-
eral Regulations as follows:
Subpart J—Standards of Performance for
Petroleum Refineries

Section 60.101 is amended as follows:

§60.101 Definitions.
(m) "Small petroleum refinery"
means a petroleum refinery w hich has
a crude oil processing capacity of
50,000 barrels per stream day (BSD) or
less.

[PR Doc. 79-8258 Filed 3-19-79: 8:45 ami
FEDERAL REGISTER, VOL 44, NO. 55—TUESDAY, MARCH 20, 1979
V-J-3
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES

SECONDARY BRASS OB BftON.lt: INGOT PRODUCTION PLANTS
S«SFART M
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Federal Register / Vol. 44. No. 119 / Tuesday, June 19.1979 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY

[40 CFR Part 60]

[FRL-1231-1]

Review of Standards of Performance
for New Stationary Sources:
Secondary Brass and Bronze Ingot
Production

AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of Standards.

SUMMARY: EPA has reviewed the
standard of performance for secondary
brass and bronze ingot production
plants (40 CFR 60.130, Subpart M). The
review is required under the Clean Air
Act, as amended August 1977. The
purpose of this notice is to announce
EPA's intent not to undertake revision of
the standards at this time.
DATES: Comments must be received on
or before August 20,1979.
ADDRESSES: Comments should be sent
to the Central Docket Section (A-130).
U.S. Environmental Protection Agency,
401 M Street, SW., Washington, D.C.
20460, Attention: Docket No. A-79-10.
The Document "A Review of Standards
of Performance for New Stationary
Sources—Secondary Brass and Bronze
Plat Plants" (EPA-450/3-79-011) is
available upon request from Mr. Robert
Ajax (MD-13), Emission Standards and
Engineering Division, U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711.
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, telephone: (919) 541-
5271.
SUPPLEMENTARY INFORMATION:

Background
In June of 1973, the EPA proposed a
standard under Section 111 of the Clean
Air Act to control participate matter
emissions from secondary brass and
bronze ingot production plants (40 CFR
60.230, Subpart M). The standard,
promulgated in March 1974, limits the
discharge of any gases into the
atmosphere from a reverberatory
furnace which;
1. Contain particulate matter in excess
of 50 mg/dscm (0.022 gr/dscf). '
2. Exhibit 20 percent opacity or
greater.
In addition, any blast (cupola) or
electric furnace may not emit any gases
which exhibit 10 percent opacity or
greater.
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of
performance for new stationary sources
at least every 4 years [Section
lll(b)(l)(B)]. This notice announces that
EPA has completed a review of the
standard of performance for secondary
brass and bronze ingot production
plants and invites comment on the
results of this review.

Findings

Industry Statistics

In 1969, there were approximately 60
brass and bronze ingot production
facilities in the United States. Currently,
only 35 facilities are operational, and
only one facility has become operational
since the promulgation of the NSPS in
1974. No new facilities or modifications
are know to be currently planned or
under construction.
Ingot production has shown a steady
decline from the 1966 peak year
production of 315,000 Mg (347,000 tons)
to a low of 160,000 Mg (186.000 tons) in
1975, the last year for which nationwide
statistics were published. The decline
has been caused by a decline in the
demand for products made with brass or
bronze and large scale substitution of
other materials or technologies for the
previously used broae or bronze. No
information has been reported which
would indicate a reversal of the decline
in brass and bronze ingot production or
in the number of operating plants.

Emissions and Control Technology

The current best demonstrated control
technology, the fabric filter, is the same
as when the standards were originally
promulgated. No major improvements in
this technology have occurred during the
intervening period.
High-pressure drop venturi scrubbers
are used, to some extent, in the brass
and bronze industry, but their overall
control efficiency is lower than that of
fabric filters. Electrostatic precipitators
have not been used in the industry due
to both the low gas flow rates and high
resistivity of metallic fumes.
Only one facility has become subject
to the standard since its original
promulgation. This facility was tested in
February 1978. The average test result of
16.9 milligrams/dry standard cubic
meters (mg/dscm), or 0.0074 grains/dry
standard cubic feet (gr/dscf), is lower
than most of the test data used for
justification of the current standard of
50 mg/dscm (0.022 gr/dscf), but this
single test is not considered sufficient to
draw any overall conclusion about
improved control technology.
Fugitive emissions continue to be a
problem in the brass and bronze
industry. In most cases, these emissions
are very difficult to capture and equally
difficult to measure during testing. It
was primarily for the former reason that
the current particulate standard does
not apply during pouring of the ingots.
This overall situation has not changed in
that only complete enclosure of the
furnace can result in full control of
fugitive emissions. However,
information is available indicating that
there may be additives capable of
reducing fugitive emissions during
pouring. Also, improved control of
fugitive emissions may be possible
through improved hood design.
Conclusions
Based on the above findings, EPA
concludes that the existing standard of
performance is appropriate and no
revision is needed. While extension of
the standard to include fugitive
emissions would be possible, the lack of
anticipated growth in the industry does
not justify such action.
PUBLIC PARTICIPATION: All interested
persons are invited to comment on this
review and the conclusions.
Dated: June 12,1979.
Douglas M. Costle,
Administrator.
(FR Doc. 79-19003 Filed 6-16-79; &45 am)
BHJJNO CODE 6560-01-M
V-M-2
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ENVIRONMENTAL
PROTECTION
AGENCY
BASIC OXYGEN PROCESS
FURNACES

Standards of Performance For New
Stationary Sources
SUBPART N
-------
PROPOSED RULES
ENVIRONMENTAL PROTECTION
AGENCY

[40 CFR Port 60]

IPRL 1012-1]

STANDARDS OF PERFORMANCE FOR NEW
STATIONARY SOURCES: IRON AND STEEL
PLANTS, BASIC OXYGEN FURNACES

Review of Standard!

AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of standards.
SUMMARY: EPA has reviewed the
standards of performance for basic
oxygen process furnaces (BOPFs) used
at iron and steel plants. The review is
required under the Clean Air Act, as
_amended in August 1977. The purpose
of this notice is to announce EPA's
intent to propose amendments to the
standards at a later date.
DATES: Comments must be received
by May 21. 1979.
ADDRESS: Send comments to: Mr.
Don Goodwin (MD-13), Emission
Standards and Engineering Division,
U.S. Environmental Protection
Agency, Research Triangle Park, N.C.
27711.
FOR FURTHER INFORMATION
CONTACT:
Mr. Robert Ajax, telephone: (919)
541-5271.
The document "A Review of Stand-
ards of Performance of New Station-
ary Sources—Iron and Steel Plants/
Bassic Oxygen Furnaces" (report
number EPA-450/3-78-116) is availa-
ble upon request from Mr. Robert
Ajax (MD-13), Emission Standards
and Engineering Division, U.S. Envi-
ronmental Protection Agency. Re-
search Triangle Park, N.C. 27711.
SUPPLEMENTARY INFORMATION:

BACKGROUND

Paniculate matter emissions from
BOPFs fall in two categories, primary
and secondary. Emissions associated
with the oxygen blow portion of the
BOPF are termed "primary" emis-
sions. These emissions ore generated
at the rate of 25 to 28 kg/Mg (50 to 55
Ib/ton) of raw steel. Emissions gener-
ated during ancillary operations, such
as charging and tapping, are termed
"secondary" or fugitive emissions.
These emissions are generated at a
lower rate in the range of 0.5 to 1 kg/
Mg (1 to 2 Ib/ton) of raw steel.
In June of 1973, EPA proposed a reg-
ulation under Section 111 of the Clean
Air Act to control primary particulate
emissions from basic oxygen process
furnaces at iron and steel plants. The
regulation, promulgated in March
1974. requires that no owner or opera-
' tor of any furnace producing steel by
charging scrap steel, hot metal, and
flux materials into a vessel and intro-
ducing a high volume of an oxygen-
rich gas shall discharge into the at-
mosphere any gases which contain
particulate matter in excess of 50 mg/
dscm (0.022 gr/dscf).
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of per-
formance for new stationary sourcs at
least every 4 years (Section
HKbXlXB)). This notice announces
that EPA has completed a review of
the standard of performance for basic
oxygen process furnaces at iron and
steel plants and invites comment on
the results of this review.

FINDINGS .

INDUSTRY GROWTH RATE

The present economic conditions in
the United States and worldwide steel
industry have created a significant
excess U.S. BOPF capacity and a
tightening of the availablitly of capital
for future expansion. Since the pro-
mulgation of the BOPF standard, new
BOPF construction has declined sig-
nificantly. For example, three of the
four units scheduled for startup in
1978 were originally scheduled to
begin production in 1974. This coupled
with the lack of any additional indus-
try announcements of new U.S. BOPF
contruction, indicates that construc-
tion of new BOPFs which would be
subject to a revised new source per-
formance standard (NSPS) is not
likely to commence before 1980, if
then. Construction of new plants
beyond 1980 will be dictated by domes-
tic economic conditions and interna-
tional competition, and is, therefore,
uncertain.

PRIMARY EMISSION CONTROL

Review of the literature and per-
formance test data indicates that the
use of a closed hood in conjunction
with a scrubber or an open hood in
conjunction with either a scrubber or
electrostatic precipitator currently
represents the best demonstrated con-
trol technologies for controlling BOPF
primary emissions. All BOPFs that
have been installed since 1973 incorpo-
rate closed hood systems for particu-
late emission control. The closed hood
control system in combination with a
venturi scrubber - has become the
system of choice of the U.S. steel in-
dustry because this system saves
energy and has generally lower main-
tenance requirements compared with
the older open-hood electrostatic pre-
cipitator system. Use of the closed
hood system requires that approxi-
mately 80 percent less air be cleaned
than with the open hood system. The
potential* also exists with the closed
hood system for using the carbon
monoxide off-gas as a fuel source.
As of early 1978, no NSPS compli-
ance tests had been carried out since
the promulgation of the standard. Per-
tinent data are available, however,
from emission tests on a limited
number of new BOPFs. These tests,
carried out using EPA Method 5, indi-
cate that primary particulate emission
levels of between 32 and 50 mg/dscf
(0.014 and 0.022 gr/dscf) are being
achieved using the same control tech-
nology as that existing at the time the
standard for primary emissions was es-
tablished for BOPFs. The rationale
for the current NSPS level of 50 mg/
dscm (0.022 gr/dscf) for primary stack
emissions, as described in 1973, is
therefore, still considered to be valid. •

. SECONDARY EMISSION CONTROL
TECHNOLOGY

Secondary or fugitive emissions not
captured by the BOPF primary emis-
sions control system during various
BOPF ancillary operations currently
amount to more than 100 tons annual-
ly. One of the principal sources of
these emissions, the hot metal charg-
ing cycle, can generate amounts of fu-
gitive emissions on the order of 0.25
kg/Mg (0.5 Ib/ton) of charge. These
emissions are presently uncontrolled
in most of the older BOPFs and only
partially controlled in most BOPFs
that have come on stream during the
past 5 years.
Control of secondary emissions in-
volves a developing technology that
requires in-depth study to determine
the most effective methods of fume
capture. Although potentially expen-
sive to construct, the complete furnace
enclosure equipped with several auxil-
iary hoods is currently the only dem-
onstrated technology exhibiting the
potential for effectively minimizing fu-
gitive emissions from a new BOPF.
Seven new BOPFs installed in the
U.S. in the past 7 years have incorpo-
rated partial or full furnace enclosures
as part of the original particulate
emission control system. Since these
designs had deficiencies, these systems
are operating with varying degrees of
success. Six new furnace enclosure in-
stallations due to commence oper-
ations in 1978, including four on new
BOPFs and two retrofit installations.
will incorporate a secondary hood
inside the furnace enclosure with suf-
ficient volume for fugitive emission
control.

CLARIFICATION OF WORDING OF NSPS
STANDARD

Review of the existing standard re-
vealed possible ambiguity in the word-
ing of the NSPS with regard to the
FEDERAL REGISTER, VOL. 44, NO. 56—WEDNESDAY, MARCH 21, 1979
V-N-2
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PROPOSED RULES
definitions of a BOPP. Also, the defi-
nition of the operating cycle during
which sampling is performed requires
clarification. Specifically, the stack
emissions averaged over the oxygen
blow part of the cycle could be signifi-
cantly different from the emissions av-
eraged over a period or periods that
Includes scrap preheating and turn-
down for vessel sampling. The current
standard is unclear as to which averag-
ing time should be used. Since no tests
to date have come under the NSPS,
averaging time has not been an issue:
however, interpreting the standard
will be a problem until this matter is
resolved.
CONCLUSIONS

Based upon the above findings, the
following conclusions have been
reached by EPA:
(1) The best demonstrated systems
of emissions control at the time the
standard for primary emissions was es-
tablished for BOPP have not changed
In the past 5 years. (See APTD-1352c
(EPA/2-74-003), Background Informa-
tion for New Source Performance
Standards, Volume 3, Promulgated
Standards.) These technologies con-
trol emissions to a level consistent
with the current standard; therefore.
revision to the existing standard is not
required, if only primary emissions are
•to be controlled.
(2) Secondary or fugitive emissions
from BOPPs represent a major air pol-
lution emission source. EPA. there-
fore, intends to Initiate a project to
revise the existing standard of per-
formance to include fugitive emissions.
This development project is planned
to begin during 1979 and lead to a pro-
posal 20 months after initiation. In ad-
dition, an assessment of foreign tech-
nology, which ahs been initiated by
the Agency, will be included in the
basis for the revised standard. The as-
sessment may lead to further conclu-
sions about the allowable emissions
from the primary gas cleaning stack
due to the interdependence of primary
and secondary control technologies.
(3) The ambiguities in the present
standard concerning definition of a
BOPF and the operating cycle to be
measured should be clarified, and a
project to do so has been initiated.

PUBLIC PARTICIPATION
»
All interested persons "are invited to
comment on this review, the conclu-
sions, and EPA's planned action. Com-
ments should be submitted to: Mr.
Don Goodwin (MD-13), Emission
Standards and Engineering Division,
U.S. Environmental Protection
Agency, Research Triangle Park, N.C.
27711.
Dated: March 9,1979.
BARBARA BLUM,
Acting Administrator.
[FR Doc. 79-8360* Filed 3-20-79; 8:45 am]
FEDERAL REGISTER, VOL 44, NO. 56-WEDNESDAY, MARCH M, 1979
V-N-3
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES

GLASS MANUFACTURING PLANTS
SUBPART OC
-------
Federal Register / Vol. 44. No. 117 / Friday, June 15,1979 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY

[40 CFR Part 60]

[FRL 1203-7]

Standards of Performance for New
Stationary Sources; Glass
Manufacturing Plants
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule and notice of
public hearing.

SUMMARY: The proposed standards
would limit emissions of particulate
matter from new, modified, and
reconstructed glass manufacturing
plants. The standards implement the
Clean Air Act and are based on the
Administrator's determination that glass
manufacturing plants contribute
significantly to air pollution. The
intended effect is to require new,
modified, and reconstructed glass
manufacturing plants to use the best
demonstrated system of continuous
emission reduction, considering costs,
nonair quality health and environmental
impact, and energy impacts.
A public hearing will be held to
provide interested persons an opportuity
for oral presentation of data, views, or
arguments concerning the proposed
standards.
DATES: Comments. Comments must be
received on or before August 14,1979.
Public Hearing. The public hearing
will be held on July 9,1979 beginning at
9:30 a.m. and ending at 4:30 p.m.
Request to Speak at Hearing. Persons
wishing to present oral testimony at the
hearing should contact EPA by June 29,
1979.
ADDRESSES: Comments. Comments
should be submitted to Central Docket
Section (A-130), United States
Environmental Protection Agency, 401M
Street, S.W., Washington, D.C. 20460,
Attention: Docket No. OAQPS 79-2.
Public Hearing. The public will be
held at Office of Administration
Auditorium, Research Triangle
Park, North Carolina 27771. Persons
wishing to present oral testimony should
notify Mary Jane Clark, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Rsearch Triangle Park, North
Carolina 27711, telephone (919) 541-
5271.
Standards Support Document. The
support document for the proposes
standards may be chained from the U.S.
EPA Library (MD-35), Research Triangle
Park, North Carolina 27711, telephone
number (919) 541-2777. Please refer to
"Glass Manufacturing Plants,
Background Information: Proposed
Standards of Performance." EPA-450/3-
79-005a.
Docket. A docket, number OAQPS 79-
2, containing information used by EPA
in development of the proposed
standard, is available for public
inspection between 8:00 a.m. and 4:00
p.m. Monday through Friday, at EPA's
Central Docket Section (A-130), Room
2903 B, Waterside Mall, 401 M Street.
S.W., Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
• Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION:
Proposed Standards
The standards would apply to glass
melting furnaces with glass
manufacturing plants with two
exceptions: day pot furnaces (which
melt two tons or less of glass per day)
and all-electric melting furnaces. No
existing plants would be covered unless
they were to undergo modification or
reconstruction. Change of fuel from gas
to fuel oil would be exempt from
consideration as a modification and
rebricking of furnaces would be exempt
from consideration as reconstruction.
Specifically, the proposed standards
would limit exhaust emissions from gas-
fired glass melting furnaces to 0.15
grams of particulate matter per kilogram
of glass produced for flat glass
production; 0.1 g/kg (0.2 Ib/ton) for
container glass production; 0.2 g/kg (0.4
Ib/ton) for wool fiberglass production;
0.1 g/kg (0.2 Ib/ton) for pressed and
blown glass production of soda-lime
formulation; and 0.25 g/kg (0.5 Ib/ton)
for pressed and blown glass production
of borosilicate, opal, and other
formulations. A15 percent allowance
above the emission limits for gas-fired
furnaces is proposed for fuel oil-fired
glass melting furnaces and an additional
proportionate allowance is proposed for
furnaces simultaneously firing gas and
fuel oil.

Summary of Environmental and
Economic Impacts

Environmental Impacts

The proposed standards would reduce
projected 1983 emissions from new
uncontrolled glass melting furnaces from
about 5,200 megagrams (Mg)/year (5,732
ton/year) to about 400 Mg/year (441
ton/year). This is a reduction of about
92 percent of uncontrolled emissions.
Meeting a typical State Implementation
Plan (SIP), however, would reduce
emissions from new uncontrolled
furnaces by about 3,700 Mg/year (4.079
ton/year), or by about 70 percent. The
proposed standard would exceed the
reduction achieved under a typical SIP
by about 1,100 Mg/year (1,213 ton-year).
This reduction in emissions would result
in a reduction of ambient air
concentrations of particulate matter in
the vicinity of new glass manufacturing
plants.
The proposed standards are based on
the use of electrostatic precipitetors
(ESP's) and fabric filters, which are dry
control techniques; therefore, no water
discharge would be generated and there
would be no adverse water pollution
impact.
The solid waste impact of the
proposed standards would be minimal.
Less than 2 Mg (2.2 ton) of particulate
would be collected for every 1,000 Mg
(1,102 ton) of glass produced. These
dusts can generally be recycled, or they
can be landfilled if recycling proves to
be unattractive. The current solid waste
disposal practice among most controlled
plants surveyed is landfilling. Since
landfill operations are subject to State
regulation, this disposal method would
not be expected to have an adverse
environmental impact. The additional
solid material collected under the
proposed standard would not differ
chemically from the material collected
under a typical SIP regulation; therefore,
adverse impact from landfilling should
be minimal. Also, recycling of the solids
has no adverse environmental impact.
For typical plants in the glass
manufacturing industry, the increased
"energy consumption that would result
from the proposed standards ranges
from about 0.1 to 2 percent of the energy
consumed to produce glass. The energy
required in excess of that required by a
typical SIP regulation to control all new
glass melting furnaces constructed by
1983 to the level of the proposed
standards would be about 2.500
kilowatt-hours per day in the fifth year
and is considered negligible. Thus, the
proposed standards would have a
minimal impact on national energy
consumption.

Economic Impacts

The economic impact of the proposed
standards is reasonable. Compliance
with the standards would result in
annualized costs in the glass
manufacturing industry of about $8.5
million by 1983. For typical plants
constructed between 1978-1983 capital
costs associated with the proposed
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Kogisto / Vol. 44. No. 117 / Friday. June 15. 1979 / Proposed Rules
standards would range from about
$235,000 for a small furnace in the
pressed and blown glass sector which
melts formulations other than soda-lime
to about $770,000 for a large pressed and
blown glass furnace which melts soda-
lime formulations. Annualized costs
associated with the proposed standards
would range from about $70,000/year to
about $235,000/year for the furnaces
mentioned above. Cumulative capital
costs of complying with the proposed
standards for the glass manufacturing
industry as a whole would amount to
about $28 million between 1978-1983.
The percent price increase necessary to
offset costs of compliance with the
proposed standards would range from
about 0.3 percent in the wool fiberglass
sector to about 1.8 percent in the
container glass sector. Industry-wide,
the price increase would amount to
about 0.7 percent.
The economic impact of the proposed
standards may vary depending on the
size of the glass melting furnace being
considered. EPA is requesting comments
specifically on the economic impact of
the proposed standards with regard to a
possible lower cut-off size for glass
melting furnaces.
Selection of Source and Pollutants

The proposed Priority List, 40 CFR
80.16, identifies various sources of
emissions on a nationwide basis in
terms of the quantities of emissions from
source categories, the mobility and
competitive nature of each source
category, and the extent to which each
pollutant endangers health or welfare.
The sources on this proposed list are
ranked in decreasing order. Glass
manufacturing ranks 38th on the
proposed list, and is therefore of
considerable importance nationwide.
The production of glass is projected to
increase at compounded annual growth
rates of up to 7 percent through the year
1983. In 1975, over 17 million megagrams
(18.8 million ton) of glass were
produced; by 1983 this production rate is
expected to increase by nearly 2.9
million Mg/year (3.2 million ton/year).
Geographically, the glass manufacturing
industry is relatively concentrated with
plants currently located in 17 states.
Total particulate emissions in the United
States in 1975 were estimated to be
about 12.4 million Mg/year (13.7 million
ton/year); by the year 1983 new glass
manufacturing plants would cause
annual nationwide particulate matter
emissions to increase by about 1,500
Mg/year (1.820 ton/year) with emissions
controlled to the level of a typical SIP
regulation.
On March 18,1977, the Governor of
New Jersey petitioned EPA to establish
standards of performance for glass
manufacturing plants. The petition was
primarily motivated by the Governor's
concern that the glass manufacturing
industry might locate plants in other
States rather than comply with New
Jersey's air pollution regulations limiting
emissions of particulate matter. The
glass manufacturing industry is not
geographically tied to either markets or
resources. Only a few States have
specialized air pollution standards for
glass manufacturing plants in their SIP's,
and these standards vary in the level of
control required. Therefore, new glass
manufacturing operations could be
located in States which do not have
stringent SIP regulations.
Glass manufacturing plants are
significant contributors to nationwide
emissions of particulate matter,
especially when viewed as contributors
to emissions in the limited number of
States in which they are located. They
rank high with regard to potential
reduction of emissions. Since they are
free to relocate in terms of both markets
and required resources, the possibility
exists that operations could be moved or
relocated to avoid stringent SIP
regulations, thereby generating
economic dislocations. For these
reasons, emissions of particulate matter
from new glass manufacturing plants
have been selected for control by NSPS.
Glass manufacturing plants also emit
other criteria pollutants: sulfur oxides
(SOa), nitrogen oxides (NOJ, carbon
monoxide, and hydrocarbons. Carbon
monoxide and hydrocarbon emissions
from efficiently operated glass
manufacturing plants, however, are
negligible.
Nationwide, the largest aggregate
emissions from glass manufacturing
plants are NOn. The techniques
generally applicable to control NOB
produced by combustion are staged
combustion, off-stoichiometric
combustion, or reduced-temperature
combustion. To date none of these
techniques has been applied to the
control of NOa emissions from glass
melting furnaces. Accordingly, there is
no way of determining how effective
they might be in such applications.
Consequently. NOB was not selected for
control by standards of performance.
SOB emissions result from combustion
of sulfur-containing fuels and from
chemical reactions of raw materials, to
general there are two alternatives for
control of SOa emissions: (1) scrubbing
of exhaust gases containing SOB, and (2)
reducing the sulfur content of fuel and
raw materials. SO2 emissions from glass
melting furnaces are in most cases
already less than the emission limits of
applicable SIP's for fuel burning sources.
Flue-gas scrubbing for control of SOa
emissions from glass melting furnaces is
not considered economically
reasonable.
There are difficulties as well with the
use of low-sulfur fuels or reduction of
oulfur content of raw materials. Using •
low-sulfur fuel would not adequately
address the problem of SOS control for
two reasons. Natural gas is the preferred
fuel for glass melting furnaces. The only
alternative fuel currently in use or
projected for future use by the glass
manufacturing industry is distillate fuel
oil, which normally contains more sulfur
than natural gas. The elimination of
sulfur-containing fuel oil is not
considered reasonable. Alternatively,
standards of performance based solely
on combustion of low-sulfur fuels could
distort existing fuel distribution
patterns, since low-sulfur fuels could be
diverted to new facilities to meet NSPS
in areas that have no difficulty attaining
or maintaining the National Ambient Air
Quality Standards (NAAQS) for SO8.
This would reduce the supply of low-
sulfur fuels for existing facilities in areas
that have great difficulty attaining or
maintaining the NAAQS for SO,.
Consequently, standards of performance
for SOa emissions based on use of low-
sulfur fuels do not seem reasonable.
Use of reduced-sulfur raw materials
has not been demonstrated as a means
of reducing SOa emissions from glass
melting furnaces. There is a wide variety
of formulations, most of which are
considered by the industry to be trade
secrets. The present state of glass
making is such that formula alterations
of the type envisioned here would lead
to glass of unpredictable quality. For
these reesons, standards of performance
for SOS emissions from glass melting
furnaces based on reduced-sulfur raw
materials, or any other approach, do not
seem reasonable and have not been
proposed. .

Selection of Affected Facility

Ninety-eight percent of the particulate
matter emitted from glass manufacturing
plants is emitted in gaseous exhaust
streams from glass melting furnaces.
Only two percent of the particulate
matter emitted from glass manufacturing
plants is emitted from raw material
handling and glass forming and
finishing. Therefore, the glass melting
furnace has been selected as the
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Federal Register / Vol. 44, No. 117 / Friday, June 15, 1979 / Proposed Rules
The proposed standards would apply
to all glass melting furnaces within glass
manufacturing plants with two
exceptions: day pot furnaces and all-
electric melters. A day pot furnace is a
glass melting furnace which is capable
of producing no more than two tons of
glass per day. These small glass melting
furnaces constitute an extremely small
percentage of total glass production and
their control is not considered
economically reasonable. Therefore, the
regulation exempts day pot furnaces
from the proposed standards.
Well operated and maintained all-
electric furnaces have particulate
emissions only slightly higher than
fossil-fuel fired furnaces controlled to
meet the proposed standards. Most of
these furnaces are open to the
atmosphere and do not have stacks.
Thus, control and measurement of
emissions from all-electric furnaces does
not appear to be economically
reasonable. Therefore, all-electric
melting furnaces are not regulated by
the proposed standards.
Selection of Format
Two alternative formats were
considered for the proposed standards:
mass standards, which limit emissions
per unit of feed to the glass furnace or
per unit of glass produced by the glass
furnace; and concentration standards,
which limit emissions per unit volume of
exhaust gases discharged to the
atmosphere.
Enforcement of concentration
standards requires a minimum of data
and information, decreasing the costs of
enforcement and reducing chances of
error. Furthermore, vendors of emission
control equipment usually guarantee
equipment performance in terms of the
pollutant concentration in the discharge
gas stream.
There is a potential for circumventing
concentration standards by diluting the
exhaust gases discharged to the
atmosphere with excess air, thus
lowering the concentration of pollutants
emitted but not the total mass emitted.
This problem can be overcome,
however, by correcting the
concentration measured in the gas
stream to a reference condition such as
a specified oxygen percentage in the gas
stream.
Concentration standards would
penalize energy-efficient furnaces, since
a decrease in the amount of fuel
required to melt glass decreases the
volume of gases released but not the
quantity of particulate matter emitted
As a result, the concentration of
particulate matter in the exhaust gas
stream would be increased even though
the total mass emitted remained the
same. Even if a concentration standard
were corrected to a specified oxygen
content in the gas stream, this penalizing
effect of the concentration would not be
overcome.
Primary disadvantages of mass
standards, as compared to concentration
standards, are that their enforcement is
more costly and that the more numerous
calculations required increase the
opportunities for error. Determining mass
emissions requires the development of a
material balance on process data
concerning the operation of the plant, .
whether it be input flow rates or
production flow rates. Development of
this balance depends on the availability
and reliability of production figures
supplied by the plant. Gathering of these
data increases the testing or monitoring
necessary, the time involved, and,
consequently, the costs. Manipulation of
these data increases the number of
calculations necessary; e.g., the
conversion of volumetric flow rates to
mass flow rates, thus compounding error
inherent in the data and increasing the
chance for error.
Although concentration standards
involve lower resource requirements
than mass standards, mass standards
are more suitable for regulation of
particulate emissions from glass melting
furnaces because of their flexibility to
accommodate process improvements
and their direct relationship to quantity
of particulate emitted to the atmosphere.
These advantages outweigh the
drawbacks associated with creating and
manipulated a data base. Consequently,
mass standards are selected as the
format for expressing standards of
performance for glass melting furnaces.
The proposed standards express
allowable particulate emissions in
grams of particulates per kilogram of
glass pulled. While emissions data
referring to raw material input as well
as data referring to glass pulled were
used in the development of the
standards, an examination of the
several sectors of the glass
manufacturing industry indicated that
an emission rate based on quantity of
glass pulled would be more
representative of industry practice.
Further, emissions are more dependent
on pull rate than on rate of raw material
input. Accordingly, the mass of glass
pulled is used as the denominator in the
proposed standards. Raw material input
data could be employed to estimate
glass pulled from a furnace if a
quantitative relationship between raw
material input and glass pulled were
developed following good engineering
methods.
Selection of the Best System of Emission
Reduction and Emission Limits

Introduction

Particulate emissions from glass
melting furnaces can be reduced
significantly by the use of the following
emission control techniques:
electrostatic precipitators, fabric filters,
and venturi scrubbers. Since these
emission control techniques do not
achieve the same level of control for
glass melting furnace emissions within
all sectors of the glass manufacturing
industry, they are discussed separately
for each sector.
Process modifications such as batch
formulation alteration and electric
boosting also may be capable of
reducing particulate emissions from
glass melting furnaces. The test data
available for furnaces where process
modifications are used as emissions
reduction techniques indicate that
emission reduction by process
modification is indifmite with respect to
the effectiveness of the techniques.
Accordingly, the selection of the best
system of emission reduction is based
on the use of add-on emission reduction
techniques of known effectiveness.
However, (here is nothing in this
proposal nor is it the intent of this
proposal to preclude the use of process
modifications to comply with the
proposed standards.
The glass manufacturing industry is
divided into four principal sectors
designated by Standard Industrial
Classifications (SIC's). The container
glass sector (SIC 3221) manufactures
containers for commercial packing and
bottling and for home canning by
pressing (stamping) and/or blowing (air-
forming) molten glass usually of soda-
lime recipe. The pressed and blown
glass, not elsewhere classified, sector
(SIC 3229) includes such diverse
products as: table, kitchen, art and
novelty glassware; lighting and
electronic glassware; scientific,
technical, and other glassware; and
textile glass fibers. Based on the
differing rates of particulate matter
emissions, it is necessary to subdivide
the pressed and blown glass sector into
plants producing glass from soda-lime
formulations and plants producing glass
from other formulation (primarily
borosilicate, opal and lead). Glass
manufacturing plants in the wool
fiberglass sector are classified under
mineral wool (SIC 3296); fiberglass
insulation is a major product. The flat
glass sector (SIC 3211) uses continuous
glass forming processes, and materials
almost exclusively of soda lime
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/ VoL 44. No. 117 / Friday, June 15, 1970 / Proposed KuSes
formulation, to manufacture sheet, plate,
float, rolled, and wire glass.
Each of the glass manufacturing
sectors is unique both from a technical
and an economic standpoint Thus,
uncontrolled paniculate emission rate,
furnace size, and the applicability of
emission control techniques vary from
one sector to another. Since the products
manufactured by the different sectors of
the glass manufacturing industry serve
different markets, each sector is working
in a different economic environment.'For
these reasons it was apparent that no
single model furnace could adequately
characterize the glass manufacturing
industry. Accordingly, several model
furnaces were specified in terms of the
following parameters: production rate,
stack height, stack diameter, exhaust
gas exit velocity, exhaust gas flow rate,
and exhaust gas temperature. The
evaluation.of these parameters may be
found in the Background Information
document The model furnace
production rate specified for the
container glass sector was 225 Mg/day
(250 ton/day). For pressed and blown
glass furnaces melting soda-lime and
other formulations two model furnace
production rates were specified: 45 Mg/
day (50 ton/day) and SO Mg/day (100
ton/day). Model furnace production
rates for the wool fiberglass and flat
glass sector were 180 Mg/day (200 ton/
day) and 635 Mg/day (700 ton/day),
respectively.
Review of the performance of the
emission control techniques led to the
identification of two regulatory options
for each sector. These options specify
numerical emission limits for glass
melting furnaces in each sector of the
glass manufacturing industry. The
environmental impacts, energy impacts,
and cost and economic impacts of each
regulatory option were compared with
those associated with a typical £>IP
regulation and those associated with no
control.

Container Class
Uncontrolled participate emissions
from container glass furnaces are
generally about 1.25 g/kg (2.5 Ib/ton) of
glass pulled. Emission tests (using EPA
Method 5) on three container glass
furnaces equipped with ESP's indicate
an average particulate emission of 0.08
g/kg (0.12 Ib/ton) of glass pulled.
Emission test data for container glass
furnaces equipped with fabric filters are
not available. However, emission test
results for a pressed and blown glass
furnace melting a soda-lime formulation
essentially identical to that used for
container glass indicate that emissions
can be reduced to 0.12 g/kg (0.24 Ib/ton)
of glass pulled with & fabric filter. This
fabric filter installation was tested with
the Los Angeles Air Pollution Control
District particulate matter test method
(LAAPCD Method), which considers the
combined weight of the particulate
matter collected in water-filled
impmgers and of that collected on a
filter. EPA Method 5 also uses iraipmgers
and a filter, but considers) only the
weight of the particulate matter
collected on the filter. Hie LAAPCD
Method collects a larger amount of
particulate matter than doss EPA
Method 5, and, consequently, greater
mass emissions would be reported for
comparable tests. An emission level of
0.1 g/kg (0.2 Ib/ton) as determined by
EPA Method 5, could be achieved by a
container glass furnace equipped with e
property designed and operated fabric
filter. (
EPA Method 5 tests of four furnaces
equipped with venturi scrubbers
indicated an average particulate
emission of 0.21 g/kg (0.42 Ib/ton] of
glass pulled.
Based on the data cited above, an
emission level of 0.1 g/kg (0.2 Ib/ton) of
glass pulled from container glass
furnaces can be achieved with ESFs or
fabric filters. An emission level of 0.2 g/
kg (0.4 Ib/ton) of glass pulled can
reasonably be achieved with a venturi
scrubber when operated at a pressure
drop somewhat higher than the average
of those scrubbers tested. ESP's and
fabric filters could also be designed to
achieve an emission level of 0.2 g/kg (0.4
Ib/ton) of glass pulled.
On the basis of these conclusions, two
regulatory options for reducing
particulate emissions from container
glass furnaces were formulated. Option I
would set an emission limit of 0.1 g/kg
(0.2 Ib/ton), requiring a particulate
emissioa reduction of somewhat over SO
percent as compared with an
uncontrolled furnace. Option II would
set an emission limit of 0.2 g/kg (0.4 lb/
ton), requiring a particulate emission
reduction of about 85 percent.
By 1983 approximately 1SOO gigagrams
(Ggj/year (2.1 million ton/year) of
additional production is anticipated in
the container glass sector. About 25 new
container glass furnaces of about 225
Mg/day (250 ton/day) production
capacity (the size of the model furnace)
would be built in order to provide this
additional production. If uncontrolled,
these new container glass furnaces
would add about 2,400 Mg/year (2,846
ton/year) to national particulate
emissions by 1983. Compliance with a
typical SIP regulation would reduce this
impact to about 1,000 Mg/year (1,102
ton/year). Under Option I, emissions
would be reduced to about 1® psrosnt of
those emitted under a typical SIP
regulation. Under Option H. emissions
would be reduced to about 33 percent of
those emitted trade? a typical SUP
regulation.
Ambient dispersion modeling
indicates that under worst case
conditions the annual maximum ground-
level particulete concentration near an
uncontrolled container glass furnace
producing 225 Mg/day of giass would be
less than 1 (ig/m°. The annual maximum
ground-level concentration resulting
from compliance with a typical SIP
regulation. Option L or Option II would
also be less than 1 f&g/ms. The
calculated maximum 24-hour ground-
level particulate concentration near an
uncontrolled container glass furnace
producing 225 Mg/day of glass would be
approximately 10 fig/m8. The
corresponding concentration for
complying with a typical SIP regulation
would be 5 {ig/m8. Under Option I, with
an ESP or a fabric filter being employed
for control, the maximum 24-hour
ground-level concentration would be
reduced to 1 jig/m8. Under Option H,
with the same techniques being
employed, the concentration would be
reduced to 2 fig/ms. Use of a venturi
scrubber to meet the Option II emissions
limit would only reduce the
concentration to 8 ftg/msdue to the
decreased stack height of a scrubber-
controlled plant and the resulting
increased building wake effects.
With one exception, standards of
performance for container glass
furnaces would Have no water pollution
impact The exception would be the use
of a venturi scrubber to comply with a
standard based on Option II. Such a
system, applied to a furnace producing
225 Mg/day of glass, would discharge
about 0.5 ms/hr of waste water
containing about 5 percent solids. The
.waste water would probably be
discharged directly to an available
waste water treatment system. To date,
however, only a few container glass
furnaces have been controlled with
venturi scrubbers; dry collection
techniques have been preferred.
Consequently, few container glass
manufacturers would be expected to
install venturi scrubbers on their
furnaces to comply with a standard
based on Option II. The overall water
pollution impact would then be
negligible.
The potential solid waste impacts of
the regulatory options would result from
collected particulate matter. Solid waste
from container glass furnaces, other
than collected particulate matter, is
minimal since cullet is normally
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Federal Register / Vol. 44. No. 117 / Friday. June 15. 1979 / Proposed Rules
recycled back into the glass melting
process. Under a typical SIP regulation,
about 1.400 Mg/year (1,543 ton/year) of
participate matter would be collected
rrom the 25 new 225 Mg/day container
glass furnaces projected to come on-
stream during the 1978-1983 period.
Compliance with standards based on
Option I and Option II would add about .
800 Mg/year (882 ton/year) and about
600 Mg/year (661 ton/year),
respectively, to the solid waste collected
under a typical SIP regulation. Option I
would increase the mass of solids for
disposal by about 60 percent over that
resulting from compliance with a typical
SIP regulation, and Option II would
increase it by about 45 percent. The
additional solid material collected under
Option I or Option II would not differ
chemically from the material collected
under a typical SIP regulation. Collected
solids either are recycled back into the
glass melting process or are disposed of
in a landfill. Recycling of the solids has
no adverse environmental impact, and,
since landfill operations are subject to
State regulation, this disposal method
also would not be expected to have an
adverse environmental impact.
The potential energy impacts of the
regulatory options would be due to the
energy used to drive the fans in
emission control systems and the energy
used to charge the electrodes in ESP's.
Since ESP's have been the predominant
control system used in the industry, the
energy requirements estimated for a
typical SIP regulation, Option I, and
Option II were based on the use of
ESP's. The energy required to control
particulate emissions from the 25 new
container glass furnaces would be about
40 million kWh (22 thousand barrels of
oil/year) for a typical SIP regulation for
the new furnaces equipped with ESP's.
This required energy would be about 0.2
percent of the total energy use in the
container glass sector. There would be
no energy impact .associated with either
Option I or Option II because the energy
required to operate an ESP for Option I
or Option II is essentially the same as
the energy required to operate an ESP
for a typical SIP regulation.
Incremental installed cost (cost in
excess of a typical SIP regulation cost)
in January 1978 dollars associated with
Option I for controlling particulate
emissions from a 225 Mg/day container
glass furnace would be about $700
thousand for an ESP and about $1.2
million for a fabric filter. Incremental
installed cost associated with Option II
would be about $450 thousand for an
ESP. and about $1 million for a fabric
filter. The incremental installed cost of
control equipment associated with
Option I level of control would be about
1.6 times the incremental installed cost
associated with Option n if ESP's were
selected. If fabric filters were selected,
the incremental installed cost associated
with the Option I level of control would
be about 1.2 times the incremental
installed cost associated with Option n.
Incremental annualized costs
associated with Option I for a 225 Mg/
day furnace would be about $200
thousand/year and about $350
thousand/year for an ESP and a fabric
filter, respectively. Incremental
annualized costs associated with Option
II would be about $130 thousand/year
for an ESP, and about $300 thousand/
year for a fabric filter. The incremental
annualized cost associated with Option
I would be about 1.5 times the
incremental annualized cost associated
with Option II if ESP's were used. If
fabric filters were used the incremental
annualized cost associated with Option
I would be about 1.2 times the
incremental annualized cost associated
with Option II.
Based on the use of control equipment
with the highest annualized cost (worst
case conditions), a price increase of
about 1.8 percent would be necessary to
offset the cost of installing control
equipment on a 225 Mg/day container
glass furnace to meet the emissions limit
of Option I. A price increase of about 1.5
percent would be necessary to comply
with the emission limit of Option II.
Incremental cumulative capital costs
for the 25 new 225 Mg/day container
glass furnaces during the 1978-1983
period associated with Option I would
be about $17 million if ESP's were used.
Use of ESP's to comply with a standard
based on Option II would require
incremental cumulative capital costs of
about $11 million for the same period.
Fifth-year annualized costs for
controlling container glass melting
furnaces to comply with Option I would
be about $5 million/year. To comply
with Option II, fifth-year annualized
costs would be about $3 million/year.
A summary of incremental impacts (in
excess of impacts of a typical SIP
regulation) associated with Option I and
Option II is shown in Table 1. Air
impacts, expressed in Mg/year of
particulate matter emissions reduced,
would approximate the quantity of
particulate matter collected and
disposed of as solid waste.
Tabte I.—Summary of Incremental Impacts
Associated With Regulatory Options

Impacts

Air1 Witer Energy' Economic1

Regulatory
option:
I 600 None Negligible... -1.8
II eOO Negligible ....Negligible.... -1.5

'Mg/Yr. reduced.
' Barrels of oil/day.
• Percent price Increase.

Consideration of the beneficial impact
on national particulate emissions, the
degree of water pollution impact, the
small potential for adverse solid waste
impact, the lack of energy impact, the
reasonableness of cost impact, and the
general availability of demonstrated
emission control technology leads to the
selection of Option I as the basis for
standards for glass melting furnaces in
the container glass sector.

Pressed and Blown Glass—Soda-Lime
Formulation

Because the glass production rates,
the furnace configurations, and the glass
formulations melted in furnaces in this
sector are very similar to those in
container glass sector, the quantity and
chemical composition of particulate
emissions approximate those of
container glass furnaces. On the basis of
this similarity of process and emissions,
the emission reduction techniques which
have been shown to be effective for
container glass furnaces would also be
effective in reducing particulate
emissions from furnaces in this sector.
Uncontrolled particulate emissions
from pressed and blown glass furnaces
melting soda-lime formulations are
generally about 1.25 g/kg (2.5 Ib/ton) of
glass pulled from the furnace. Test data
for a pressed and blown glass furnace
melting a soda-lime formulation and
equipped with a fabric filter indicate
particulate emissions of 0.12 g/kg (0.24
Ib/ton) of glass pulled using the
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tor / Vol.
I Friday. Jane 15, 1979 / Proposed Rules
LAAPCD Msfthad. No emissions data for
pressed and blown glass furnaces
equipped with ESP'e are available.
However, emission test& using EPA
Method 5 oa three container-glass
fhmiBces equipped with ESP's indicate
an average participate emiosion rate of
0.0$ g/kg (0.12 Ib/ton) of glass pulled.
EJscaues of (the similarities between fihds
sector and the container glass sector,
both ESP'o and fabric filters would bs
expected to be capable of reducing
emissions to about 0.1 g/kg (0.2 Jb/ton)
of glass pulled.
Eased am tthe similarity of pressed and
blown glass production methods in thas
sector to those of the coataktar glass
cscJoff, oo twsl!l no on test data eveilable
on container glass furnace emissions,
too regulatory options were formulated.
Tfes regulatory optic&s are identical to
these formula tad fw container gkss
fernaces. Option 8 would set on
emission limit of 0.1 g/kg (0.2 Ib/ton) of
glass pulled, which would require a
participate amiseioa reduction of about
60 percent. Option 0 would set an
emission limit of 0.2 g/kg (0.4 Ib/ton) of
glass pulled, which would require about
B§ percent particulate emission
reduction.
BSy 1B33 approximately 310 Mg/yea?'
([342 ton/year) of additional production
Jo anticipated in this glass
manufacturing sector. About four new 45
Mg/day (50 ton/day) (small) and six
aew 69 Mg/day (ICO ton/day) (large)
furnaces would be built in order to
provide this production. Emissions from
the large furnaces would have to be
reduced in order to comply with a
typical SIP regulation, while small
furnaces would meet a typical SIP
regulation without reducing emissions. If
uncontrolled, the four new small
furnaces would add about 80 Mg/year
lj88 ton/year) to national participate
emissions by 1983, while the six new
large furnaces would add about 230 Mgf
year (254 ton/year). Compliance with a
typical SIP regulation would reduce the
impact of the new large furnaces to
about 70 Mg/year (77 ton/year). Under
Option I, these furnace emissions would
be reduced to about 26 percent of those
emitted under a typical SIP regulation.
Under Option II, large furnace emissions
would be reduced to about 53 percent of
those emitted under a typical SIP
regulation.
The small furnaces would be in
compliance with a typical SIP regulation
without control. Under Option L
emissions would be reduced 'to about 8
percent of uncontrolled emissions.
Under Option H, emissions would be
seduced to about 16 percent of
The efffect of a tvpical SSP regulation
Mg/day (50 toa/day) furnaces would be
& reduction of about 48 percent of
uncontrolled emissions. Under Option I,
emissions would be reduced to about 18
percent of those emitted under a typical
SIP regulation. Under Option H,
emissions would be reduced to about 33
percent of those emitted under a typical
SIP regulation.
Ambient dispersion modeling
indicates that under worst case
conditions the annual maximum ground-
level particuJate concentration near an
famace producing 05 Mg/day of glass
would be less than 3 fig/HI 3, as would
the concentrations sfesulting from
©BnapSiance with Opton I or Optical II.
Corresponding annual EjasdmuHi
ground-Bevel oonoantrs&iimiis near an
mcontrolled pressed end blown glass
s?odd also be lew than 1 fig/m3.
EmiEsicsffis fruKffl mnccoitrolled furnaces of
either size in this esctor would result in
level casicsntratioaQ of 3 ^g/m3. Under
Option I this concentration would be
reduced to below 1 f&g/m3. Under Option
II it would be reduced to about i j&g/ms.
Since fabric filters and electrostatic
precipitatosfl are likely to be the control
systems installed on furnaces in this
sector to comply with standards, there
would be no water pollution impact
associated with standards based on
either Option I or Option IL
Under a typical SIP regulation, no
participate matter would be collected
from the four new 45 Mg/day pressed
and blown glass furnaces projected to
come on-stream during the 1078-1983
period. The six new 90 Mg/day furnaces
would collect about 160 Mg/year (178
ton/year) under a typical SIP regulation.
For the six £0 Mg/day furnaces the
amounts collected in addition to those
collected through compliance with a
typical SIP regulation would be about 50
Mg/year (55 ton/year) for Option I and
about 33 Mg/year (38 ton/year) for
Option ID. Compliance with standards
based on Option I and Option E would
result in the collection of about 72 Mg/ •
year (78 ton/year) and about 63 Mg/year
(75 ton/year), respectively, of solid
waste from the four 45 Mg/day furnaces.
Option I would increase the mass of
colids for disposal by 100 percent and by
about 31 percent over that required by a
typical SIP regulation for 45 Mg/day and
SO Mg/day furnaces, respectively.
Option II would increase the mass of
solids for disposal by 100 percent and 21
percent over that required by Q typical
SIP regulation for 45 Mg/day and BO Mg/
day furnaces, respectively. The total
ssasses of solids for disposal collected
from all new furnaces would be about
122 Mg/year (135 ton/year) and 101 Mg/
year (111 ton/year) for Option I and
Option II, respectively.
The additional solid material
collected under Option I and Option £1
would not differ chemically from the
material collected under a typical SIP
regulation. Collected solids either are
recycled back into the glass melting
process or are disposed of in a landfill.
Recycling of the soJids has no adverse
environmental .impact, and, since
landfill operations are subject to State
regulation, this dispose! method also
would not be expected to have an
adverse environmental impact.
Since the four new 45 Mg/day
furnaces would be in compliance with a
typical SIP. regulation without add-on
controls, there would be no associated
energy requirement. The estimated
energy required to control particulates
emissions from the four new 45 Mg/day
fornacss projected to come on-stream in
required by both OptionS and Option II
would bs about 2.5 million ikWh (SCO
barrels of oil/year). The energy required
to control particulate emissions from the
oix new SO Mg/day fum&oas would be
<1.4 million kWh (2,503 barrelo of oil/
year) for a typical SIP regulation. Option
H, or Option D if ESFs were installed.
The energy required to comply with
the emission limits of the regulatory
options would be about 0.5 percent of
the total energy use in this glass
manufacturing sector. The energy
fenpacts of both Option I and Option i
or® negligible (~3 barrels of oil/day) for
would be no energy impact associated
with either Option I or Option H for the
raew SO Mg/day furasoss bsyond the
impact associated trith Sfes requirements
to meet a typical SIP regulation.
Bjicrsmentat snstaOed cooto in January
W8 dollars associated with Option 1 (For
controlling particular emiooioras from a
45 Mg/day pressed and bSovsm glass
ftsmace melting ocda-Jime foKmulatiomo
would be about 8740 thouoand for an
ESP and about §710 thousand for a
fabric filter. Incremental installed ouato
associated with Option II would bs
about SJ845 thousand ftw an ESP, and
The incremental installed cocto of
srcntrol equipmsat associated wiflh 4k2
Opticra I level of control would tte ateat
1.1 times the incs-emsnitai inotatled ccoto
associated with Option 1 if ISsP'o wera
selected. If fabric Sltero
associated with the Optiea B fevs! eS
V-CC-7
-------
/ Vol. «4, No. 117 / Friday. June 15. 1S79 / Proposed Rules
control would be about 1.1 times the
Incremental installed costs associated
with Option II.
Incremental annualized costs for a 45
Ms/day furnace associated with Option
1 would be about $230 thousand/year for
both ESP's and fabric filters.
incremental annualized costs associated
with Option II would be about $205
thousand/year for an ESP, and about
8215 thousand/year for a fabric filter.
The incremental annualized costs
aooociated with Option I would be about
l.i times the incremental annualized
coots associated with Option Q if ESP's
were used. If fabric filters were used,
the incremental annualized costs
associated with Option I would be about
1.1 times the incremental annualized
costs associated with Option II.
Based on the use of control equipment
with the highest annualized costs (worse
case conditions), a price increase of
about 0.6 percent would be necessary to
offset the costs of installing control
equipment on a 45 Mg/day pressed and
blown glass furnace melting soda-lime
formulations to meet the emission limits
of Option I. A price increase of about 0.5
percent would be necessary to comply
with the emission limits of Option II.
Incremental cumulative capital costs
for the 1978-1883 period associated with
Option! for the four new 45 Mg/day
furnaces would be about $2.8 million if a
fabric filter were used. Use of an ESP to
comply with Option II would require
incremental cumulative capital costs of
about $2.6 million for the same period.
Fifth-year annualized costs for
controlling the furnace to comply with
Option I would be about $910 thousand.
To comply with Option II, fifth-year
annualized costs would be about $815
thousand.
Incremental installed costs in January
1878 dollars associated with Option I for
controlling particulate emissions from a
SO Mg/day pressed and blown glass
furnace melting soda-lime formulations
would be about $615 thousand for an
ESP and about $770 thousand for a
fabric filter. Incremental installed costs
associated with Option 0 would be
about $450 thousand for an ESP, and
about $880 thousand for e fabric filter.
The incremental installed costs of
control equipment associated with the
Option I level of control would be about
1.4 times the incremental installed costs
oooociated with Option II, if ESP's were
selected. If fabric filters were selected
the incremental installed costs
associated with the Option i level of
control would be about l.J times the
incremental installed coots associated
with Optaa E.
Incremental annualized costs for a 80
Mg/day furnace associated with Option
I would be about $175 thousand/year
and about $235 thousand/ year for an
ESP and a fabric filter, respectively.
Incremental annualized costs associated
with Option II would be about $130
thousand/year for an ESP, and about .
$205 thousand/year for a fabric filter.
The incremental annualized costs
associated with Option I would be about
1.3 times the incremental annualized
costs associated with Option E if ESP's
were used. If fabric filters were used the
incremental annualized costs associated
with Option I would be about 1.1 times
the incremental annualized costs
associated with Option H
Based on the use of control equipment
with the highest annualized cost, a price
increase of about 0.6 percent would be
necessary to offset the costs of installing
control equipment on the large pressed
and blown glass furnace melting soda-
lime formulations to meet the emission
limits of Option L A price increase of
about 0.5 percent would be necessary to
comply with the emission limits of
Option II.
Incremental cumulative capital costs
for the 1878-1983 period associated with
Option I for the six new SO Mg/day
furnaces would be about $3.7 million if
ESP's were used. Use of ESP's to comply
with Option II would require
incremental cumulative capital costs of
about $2.7 million for the same period.
Fifth-year annualized costs for
controlling these glass melting furnaces
to comply with Option I would be about
$1.1 million. To comply with Option II,
fifth-year annualized costs would be
about $780 thousand.
A summary of incremental impacts (in
excess of impacts of the typical SIP
regulation) associated with Option I and
Option II is shown in Table II for both
small and large furnaces. Air impacts,
expressed in Mg/year of particulate
matter emissions reduced, would
approximate the quantity of particulate
matter collected and disposed of as
solid waste.

Vc&So lt.-~SummeryoflncramanlBllmf>£cts
A!?1
Water
Econonte »
122 K«mo_
101 Kono...
-3.0
-ao
-O.Q
~o.s
"BaiTOlo of all/day.
oporoait prlco laacaca.
Consideration of the beneficial impact
on national particulate emissions, the
lack of water pollution impact, the small
potential for adverse solid waste impact,
the reasonableness of energy and costs
impacts, and the general availability of
demonstrated emission control
technology leads to the selection of
Option I as the basis for standards for
pressed and blown glass furnaces
melting soda-lime formulations.

Pressed and Blown Glass—Other Than
Soda-Lime Formulations

Uncontrolled particulate emissions
from furnaces in this sector are about 5
g/kg (10 Ib/ton) of glass pulled.
Emission tests using EPA Method 5 on
four furnaces melting borosilicate
formulations and equipped with ESP's
yielded a representative emission rate of
about 0.50 g/kg (1.0 Ib/ton) of glass
pulled. A single emission test using EPA
Method 5 on an ESP-controlled furnace
melting fluoride/opal formulations
yielded an emission rate of 0.17 g/kg
(0.34 Ib/ton) of glass pulled. EPA
Method 5 tests of six ESP-controlled
furnaces melting lead glass yielded a
representative emission rate of 0.12 g/kg
(0.24 Ib/ton) of glass pulled. A single
EPA method 5 emission test of an ESP-
controlled furnace melting potash-soda-
lead glass yielded an emission rate of
0.03 g/kg (0.08 Ib/ton) of glass pulled.
An EPA method 5 emission test on a
furnace equipped with a fabric filter and
melting soda-lead-borosilicate glass
produced an emission rate of 0.17 g/kg
(0.34 Ib/ton) of glass pulled.
Upon consideration of the data cited
above, an emission limit of 0.25 g/kg (0.5
Ib/ton) of glass pulled was identified as
a reasonable limit for control for
pressed and blown glass furnaces
melting other than soda-lime
formulations. This limit was selected for
Option I; it provides for about 95 percent
particulate removal. Option II would set
an emission limit of 0.5 g/kg (1.0 Ib/ton)
of glass pulled, which provides for a
particulate removal of about SO percent.
Fabric filters and ESP's could be
designed to achieve the levels of
emission reduction required by either
regulatory option.
By 1883 approximately 70 Gg/year
(77.2CO ton/year) of additional
production is anticipated in this sector.
One 45 Mg/day (50 ton/day) (small)
furnace and two SO Mg/day (100 ton/
day) (large) furnaces would be built in
order to provide this production. If
uncontrolled, emissions from the one
Eiew small pressed and blown glass
furnace melting formulations other than
code-lime would add about SO Mg/year
(ICO ton/year) to national paniculate
V-CC-8
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Fate®! Eogisteir / Vol. M, No. 117 / Friday. June IS. i®78i / Proposed
emissions by 1983, while the emissions
from the two new large furnaces would
odd about 260 Mg/year (287 ton/year)
during the same period.
Compliance with a typical SIP
regulation would reduce the impact from
the small furnace to about 27 Mg/year .
(30 ton/year), Control to the Option E
emissions limit would reduce the
emissions to about 17 percent of those
emitted under a typical SIP regulation.
With Option II emissions would be
reduced to about 33 percent of those
emitted under a typical SIP regulation.
Compliance with a typical SIP
regulation would reduce the impact of
the large furnances to about 47 Mg/year
(52 ton/year). Under Option !, these
emissions would be reduced to about 28
percent of those emitted under a typical
SIP regulation. Under Option II, the large
furnace emissions would be reduced to
about 56 percent of those emitted under
si typical SIP regulation.
The effect of a typical SE> regulation
for both large and small furnaces would
be a reduction of about 79 percent.
Under Option 1, emissions would be
reduced to about 25 percent of those
emitted under a typical SIP regulation.
Under Option Q, emissions would be
reduced to about 50 percent of those
emitted under a typical SIP regulation.
Ambient dispersion modeling
indicates that under worst case
conditions the annual maximum ground-
level particulate concentration near an
uncontrolled 45 Mg/day pressed and
blown glass furnace melting
formulations other than soda-lime would
be less than 1 fig/ms, as would be the
concentrations resulting from
compliance with a typical SIP
regulation, Option I, or Option 1.
Corresponding annual maximum
ground-level concentrations near a CO*
Mg/day furnace also would be less than
1 fig/m*
The calculated maximum 24-hour
ground-level concentration near an
uncontrolled 45 Mg/day furnace in this
sector would be 11 fig/m8. This
concentration would be reduced to 8 fig/
ms with a typical SIP regulation. With
Options I and II, the concentrations
would be reduced to 1 fig/m8 or less.
The calculated maximum 24-hour
ground-level concentration near an
uncontrolled 80 Mg/day furnance would
be 14 ftg/m8. This concentration would
foe reduced to 3 fig/m s with a typical SIP
regulation end to below 1 f4g/ms with
Option I; with Option E it would reach I
pollution impact associated with
standards based on either Option i or
Option XL
Under a typical SIP regulation, about
®4 Mg/year (71 ton/year) of particulate
matter would be collected from the one
Eiew 45 Mg/day furnace projected to
come on-stream in the 1978-1983 period.
Compliance with standards based on
Option I and Option II would add about
23 Mg/year (25 ton/year) and 18 Mg/
year (20 ton/year), respectively, to the
solid waste collected under a typical SIP
regulation. Option 1 would increase the
mass of solids by about 38 percent over
that resulting from compliance with a
typical SIP regulation, and Option 0
would increase it by about 28 percent.
Under a typical SIP regulation, about
210 Mg/year (232 ton/year) of
particulate matter would be collected
from the two new 80 Mg/day furnaces
projected to come on-stream in the 1978-
1983 period. Compliance with standards
based on Option I and Option Q would
add about 34 Mg/year (38 ton/year) end
21 Mg/year (23 ton/year), respectively,
to the solid waste collected under a
typical SIP regulation. Option I would
{increase the mass of solids by about 10
percent over that resulting from
compliance with a typical SIP \
regulation, and Option H would increase
it by about 10 percent. The total mass of
solids for disposal collected from all
three new furnaces in this sector,
associated with Option I and Option B,
would be about 57 Mg/year (83 ton/
year) and about 39 Mg/year (43 ton/
year), respectively.
The additional solid material
collected under Option I or Option E
would not differ chemically from the
material collected under the typical SIP
regulation. Collected solids either ere
recycled back into the glass melting
process or are disposed of in a landfill.
Recycling of the solids has no adverse
environmental impact, and, since
landfill operations are subject to State
regulation, this disposal method also is
mot expected to have an adverse
environmental impact.
Since ESP's have been the
predominant control system used in the
industry and are anticipated as the
predominant system to be used for new
plants coming on-stream between 1978=
1883 regardless of which regulatory
option is selected, energy requirements
estimated for the typical SIP regulation.
(typical SIP regulation would be about
2.7 million kWh (1,500 barrels of oil/
year). The energy required to comply
with the Option 1 and Option E
omissions limits would be essentially
the same as that required for meeting a
Since fabric filters and ESP's era
iikely to be the control systems installed
on furnaces in this sector to comply with
otandardo, there would be no mites*
use of ESP's.
The energy required to control
particulate emissions from the new
-------
Federal Register / Vol 44. No. 117 / Friday. June 15. 1979 / Proposed Rules
with Option I would be about 1.2 times
the incremental annnalized costs
associated with Option IL
Based on the use of control equipment
with the highest annualized costs (worse
case conditions), a price increase of
about 0.4 percent would be necessary to
offset the costs of installing control
equipment on a 45 Mg/day pressed and
blown glass furnace melting other than
soda-lime formulations to meet the
emission limits of Option I. A price
increase of about 0.3 percent would be
necessary to comply with the emission
limits of Option n.
Incremental cumulative capital costs
for the 1976-1963 period associated with
Option I for the 45 Mg/day furnace
would be about $235 thousand if an ESP
were used. Use of an ESP to comply
with Option n would require
incremental cumulative capital costs of
about $190 thousand for the same
period. Fifth-year annualized costs for
controlling mis furnace in this sector to
comply with Option I would be about
$70 thousand.'To comply with Option n,
fifth-year annnalized costs would be
about $60 thousand.
Incremental installed costs in January
1978 dollars associated with Option I for
controlling participate emissions from a
90 Mg/day pressed and blown glass
furnace melting other than soda-lime
formulations would be about $800
thousand for an ESP and about $260
thousand for a fabric filter. Incremental
installed costs associated with Option II
would be about $140 thousand for an
ESP, and about $180 thousand for a
fabric filter. The incremental installed
costs of control equipment associated
with the Option I level of control would
be about 5.7 times the incremental
installed costs associated with Option n
if ESP1 s were selected. If fabric filters
were selected the incremental installed
costs associated with the Option I level
of control would be about 1.4 times the
incremental installed costs associated
with Option D.
Incremental annualized costs for a 90
Mg/day furnace associated with Option
I would be about $245 thousand per year
and about $85 thousand per year for an
ESP and a fabric filter, respectively.
Incremental annualized costs associated
with Option n would be about $45
thousand per year for an ESP, and about
$55 thousand per year for a fabric filter.
The incremental annualized costs
associated with Option I would be about-
5.4 times the incremental annualized
costs associated with Option H if ESFs
were used. If fabric niters were used the
incremental annualized costs associated
with Option I would be about L5 time*
the incremental annualized costs
associated with Option II.
Based on the use of control equipment
with the highest annualized costs, a
price increase of about dfl percent
would be necessary to offset the costs of
installing control equipment on the 90
Mg/day pressed and blown glass
furnace melting formulations other than
soda-lime to meet the emission limits of
Option I. A price increase of about 0.5
percent would be necessary to comply
with the emission limits of Option II.
• Incremental cumulative capital costs
for the 1978-1983 period associated with
Option I for the two new 90 Mg/day
furnaces would be about $500 thousand
if fabric filters were used. Use of ESP's
to comply with Option II would require
incremental cumulative capital costs of
about $300 thousand for the same
period. Fifth-year-annualized costs for
controlling these glass melting furnaces
to comply with Option I would be about
$160 thousand. To comply with Option
fl, fifth-year annualized costs would be
about $85 thousand.
A summary of incremental impacts (in
- excess of impacts of the typical SIP
regulation) associated with Option I and
Option II is shown in Table III for both
small and large furnaces. Air impacts,
expressed in Mg/year of particulate
matter emissions reduced, would
approximate the quantity of participate
matter collected and disposed of as
soild waste.
HI.—Sunmaiy of Increme
Atsooatol watt RfgulaKxy Options
Mr1
Water Enngy' Economic1
options
I
fl
67Nar»__Negl0ble_
M Nan*
-O7
-0.4
'Mg/Yr.
'PsYOtrri price sTsCTWM.
Consideration of the beneficial impact
on national participate emissions, lack
of water pollution impact, the small
potential for adverse solid waste impact.
the lack of energy impact, (he
reasonableness of cost impacts, and the
general availability of demonstrated
emission control technology leads to die
selection of Option I as the baste for
standards for pressed and blown glass'
furnaces melting formulations other than
soda-lime.

Wool Fiberglass
Uncontrolled particulate emissions
from wool fiberglass furnaces are
generally about « g/kg (10 Ib/tonJ of
glass pulled. The average emission from
three furnaces in the wool fiberglass
sector equipped with ESP's was 0.18 g/
kg (0.36 Ib/ton) of glass pulled. EPA
Method 5 tests of three furnaces
equipped with fabric filters indicated
emissions of 0.2 g/kg (0.4 Ib/ton), 0.26 g/
kg (0.52 Ib/ton). and 0.55 g/kg (1.1 lb/
ton) of glass pulled. The test data cited
indicate that an emission limit of 0.2 g/
kg (0.4 Ib/ton) of glass pulled could be
met through the use of an ESP and that a
limit of 0.4 g/kg (0.8 Ib/ton) of glass
pulled could be met through the use of
either an ESP or a fabric filter.
On the basis of these conclusions, two
regulatory options for reducing
particulate emissions from wool
fiberglass furnaces were formulated.
Option I would set an emission limit of
02 g/kg (0.4 Ib/ton) of glass pulled,
which would provide for about 95
percent particulate removal Option II
would set an emission limit of 0.4 g/kg
(0.8 Ib/ton) of glass pulled, which would
provide for about 90 percent removal of
participates.
By 1983 approximately 360 Gg/year
(397,000 ton/year) of additional
production is anticipated in the wool
fiberglass sector. About six new wool
fiberglass furnaces of about 180 Mg/day
(200 ton/day production capacity (the
size of the model furnace) would be
built in order to provide this additional
production. If uncontrolled, these new
wool fiberglass furnaces would add
about 1,800 Mg/year (1.984 ton/year) to
national particulate emissions by 1983.
Compliance with a typical SIP
regulation would reduce this impact to
about 210 Mg/year (232 ton/year).
Under Option I, emissions would be
reduced to about 33 percent of those
emitted under a typical SIP regulation.
Under Option II, emissions would be
reduced to about 66 percent of those
emitted under a typical SIP regulation.
Ambient dispersion modeling
indicates that under worst case
conditions the annual maximum ground-
level particulate concentration near an
uncontrolled wool fiberglass furnace
producing 180 Mg/day of glass would be
about 2 pg/m3. The annual maximum
ground-level concentrations resulting
from compliance with a typical SIP
regulation. Option I, or Option II would
be less than 1 pg/m'. The calculated
maximum 24-hour ground-level
particulate concentration near an
uncontrolled wool fiberglass furnace
producing 180 Mg/day of glass would be
about 29 /ig/m*. The corresponding
concentration for complying with a
typical SIP regulation would be about 3
Mg/m» Under Option I. with an ESP
employed for control, the •'•^"••'•i 24-
V-CC-10
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Federal Register / Vol. 44. No. 117 / Friday, June 15, 1979 / Proposed Rules
hour ground-level concentration would
be reduced to 2 fig/m9. Under Option D
it would be reduce.d to 3 and 4 jig/m'
with the fabric filter and ESP,
respectively.
Since fabric filters and ESP'8 are
likely to be the control systems installed
on wool fiberglass furnaces to comply
with standards, there would be no water
pollution impact associated with
standards based on either Option I or
Option II.
Under a typical SIP regulation, about
1600 Mg/year (1.764 ton/year) of
particulate matter would be collected
from the six new 180 Mg/day wool
fiberglass furnaces projected to come
on-stream during the 1978-1983 period.
Compliance with standards based on
Option I and Option II would add about
140 Mg/year (154 ton/year) and about 70
Mg/year-(77-ton/year), respectively, to
the solid waste collected under a typical
SIP regulation. Option I would increase
the mass of solids for disposal by about
B percent over that resulting from
compliance with a typical SIP
regulation, and Option II would increase
it by about 4 percent. The additional
solid material collected under Option I
or Option D would not differ chemically
from the material collected under a
typical SIP regulation. Collected solids
either are recycled back into the glass
melting process or are disposed of in a
landfill. Recycling of the solids has no
adverse environmental impact, and,
since landfill operations are subject to
State regulation, this disposal method
also is not expected to have an adverse
environmental impact.
The estimated energy required to
control particulate emissions from the
six new wool fiberglass furnaces
expected to come on-stream in the 1978-
83 period to comply with a typical SIP
regulation would be about 6.8 million
kWh (3,850 barrels of oil/year) if
electrostatic precipitators were used.
Complying with the emission limits of
Option I and Option Q with electrostatic
precipitators would require about 6.9
million kWh (3,900 barrels of oil/year).
The energy required would be about 0.3
percent of the total energy use in the
wool fiberglass sector. The energy
impacts of either Option I or Option D
would be negligible—only about 50
barrels of oil/year.
Incremental installed costs in January
1978 dollars associated with Option I for
controlling particulate emissions from a
180 Mg/day wool fiberglass furnace
would be about $500 thousand for an
ESP and about $70 thousand for a fabric
filter. Incremental installed costs
associated with Option D would be
about $110 thousand and about $30
thousand for an ESP and a fabric filter,
respectively. The incremental installed
costs of control equipment associated
with the Option I level of control would
be nearly 5 times the incremental
installed costs associated with Option D
if ESP's were selected. If fabric filters
were selected, the incremental installed
costs associated with the Option I level
of control would be aobut twice the
incremental installed costs associated
with Option H.
Incremental annualized costs
associated with Option I for a 180 Mg/
day wool fiberglass furnace would be
about $155 thousand/year and about $20
thousand/year for an ESP and a fabric
filter, respectively. Incremental
"annualized costs associated with Option
II would be about $35 thousand/year for
an ESP and about $10 thousand/year for
a fabric filter. The incremental
annualized costs associated with Option
I would be about five times the
incremental annualized costs associated
with Option D if ESP's were used. If
fabric filters were used, the incremental
annualized costs associated with Option
I would be about two times the
incremental annualized costs associated
with Option H.
Based on the use of control equipment
with the highest annualized costs (worst
case conditions), a price increase of
about 0.3 percent would be necessary to
offset the costs of installing control
equipment on a 180 Mg/day wool
fiberglass furnace to meet the emission
limits of Option I. A price increase of
about 0.1 percent would be necessary to
complying with the emission limits of
Option n.
Incremental cumulative capital costs
for the six new 180 Mg/day wool
fiberglass furnaces during the 1978-1983
period associated with Option I would
be about $3 million if ESP's were used.
Use of fabric filters to comply with
Option n would require incremental
cumulative capital costs of about $185
thousand for the same period. Fifth-year
annualized costs for controlling wool
fiberglass furnaces complying with
Option I would be about $930 thousand.
To comply with Option n, fifth-year
annualized costs would be about $60
thousand.
A summary of incremental impacts
associated with Option I and Option n
is shown in Table IV. Air impacts,
expressed in Mg/year of particulate
matter emissions reduced, would
approximate the quantity of particulate
matter collected and disposed of as
solid waste.
Tabto IV.^Summary of Increment*! Impacts
• Ataooated With Regulatory Options
Mr1
Water Energy • Economic •
Regrittonr
opttoft
i
140 None.
70 None.
-.Negligible....
OJ
0.1
'Mg/Yr. reduced
^Benetsofol/aey.
Pwoonl pnot Incf

Consideration of the beneficial impact
on national particulate emissions, the
lack of water pollution impact, the small
potential for adverse solid waste impact,
the reasonableness of energy and cost
impacts, and the general availability of
demonstrated emission control
technology leads to the selection of
Option I as the basis for standards for
glass melting furnaces in the wool
fiberglass sector.
Flat Glass

Uncontrolled particulate emissions
from flat glass furnaces are about 1.5 g/
kg (3.0 Ib/ton) of glass pulled. There are
no emissions test data for fiat glass
furnaces equipped with control devices
available for evaluation. However, the
soda-lime formulations melted in these
furnaces are quite similar to those
melted hi container glass furnaces, as
are the chemical composition and
physical characteristics of the
particulate emissions. The primary
difference between container glass and
flat glass furnaces is that the
uncontrolled emission rates of flat glass
furnaces are greater. Given the
similarity of processes, glass
formulations, and emissions it is
expected that the percentage reduction
in particulate emissions achieved by
control of container glass furnaces also
could be achieved with flat glass
furnaces. This conclusion is supported
by the performance guarantee
underwritten by an ESP manufacturer
for a flat glass facility which indicates at
least 90 percent control efficiency. Thus,
uncontrolled emissions from flat glass
furnaces can be reduced with an ESP by
at least 90 percent or to about 0.15 g/kg
(0.3 Ib/ton) of glass pulled.
The similarity of container glass and
flat glass furnace formulations and
emissions and the vendor guarantee
noted above provide the basis for
Option L Option I would set an emission
limit of 0.15 g/kg (0.3 Ib/ton) of glass
pulled, which would provide about 90
percent control. The Option II emission
limit for furnaces in the other glass
manufacturing sectors has been found to
be twice the Option I limit For
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consistency, therefore. Option II would
set an emission limit of 0.3 g/kg (0.6 lb/
ton) of glass pulled, which would
provide about 80 percent control.
By 1963 approximately 240 Gg/year
(284,555 ton/year) of additional
production is expected in the flat glass
sector. One new flat glass furnace of
about 635 Mg/day (700 ton/day)
capacity (the size of the model" furnace)
would be built in order to provide this
additional production.
If uncontrolled, this new flat glass
furnace would add about 360 Mg/year
(397 ton/year) to national particulate
emissions by 1983. Compliance with a
typical SIP regulation would reduce this
impact to about 90 Mg/year (100 ton/
year). Under Option I, emissions would
be reduced to about 40 percent of those
emitted under a typical SIP regulation.
Under Option EL emissions would be
reduced to about 80 percent of those
emitted under a typical SIP regulation.
Ambient dispersion modeling
indicates that under worst case
conditions the annual maximum ground-
level particulate concentration near an
uncontrolled flat glass furnace
producing 635 Mg/day of glass would be
about 1 ug/m*. The annual mazimnm
ground-level concentrations resulting
from compliance with a typical SIP
regulation, Option I. or Option n. would
be less than 1 jtg/m'. The calculated
maximum 24-hour ground-level
particulate concentration near an
uncontrolled flat glass furnace
producing 635 Mg/day of glass would be
about 21 pg/m1. The corresponding
concentration for complying with a
typical SIP regulation would be about 5
f*g/m*. Under Option I, this
concentration would be reduced to
about 2 >ig/ras. Under Option II it would
be reduced to about 5 >ig/m'.
Since the ESP is likely to be the
emission control system installed on flat
glass furnaces to comply with standards,
there would be no water pollution
impact associated with standards based
on either Option I or Option IL
Under a typical SIP regulation, about
270 Mg/year (298 ton/year) of
particulate matter would be collected
from the one new 635 Mg/day flat glass
furnace projected to come on-stream in
the 1978-1983 period. Compliance with
standards based on Option I and II
would add about 50 Mg/year (55 ton/
year) and about 20 Mg/year (22 ton/
year), respectively, to the solid waste
collected under a typical SIP regulation.
Option I would increase the mass of
solids for disposal by about 20 percent
over that resulting from compliance with
a typical SIP regulation, and Option n
would increase it by about 7 percent.
The additional solid material collected
under Option I or Option n would not
differ chemically from the material
collected under a typical SIP regulation.
Collected solids either are recycled back
into the glass melting process or are
disposed of in a landfill. Recyling of the
solids has no adverse environmental
impact, and, since landfill operations are
subject to State regulations, this
disposal method also is not expected to
have en advene environmental impact.
Since the energy requirements for an
electrostatic precipitator do not vary
significantly over the range of emission
reductions considered here, the estimate
of energy required to control particulate
emissions from die one new flat glass
furnace would be about the same for
compliance with a typical SIP
regulation, Option I, or Option n—about
7A million kWh (4.300 barrels of oil/
year). The energy required to comply
with the emission limits of the
regulatory options would be about 0.2
percent of the total energy use in the flat
glass sector. There would be no
incremental energy impact associated
with either Option I or Option n as
compared with a typical SIP regulation.
The incremental installed cost in
January 1978 dollars associated with
Option I for controlling particulate
emissions from a 635 Mg/day flat glass
furnace would be about $605 thousand.
Incremental installed cost associated
with Option D would be about $140
thousand. The incremental installed cost
of control equipment associated with the
Option I level of control would be
somewhat more than four times the
incremental installed cost associated
with the Option II level of control
Incremental annualized cost
associated with Option I for a 635 Mg/
day flat glass furnace would be about
$190 thousand/year; the corresponding
incremental annualized cost for Option
n would be about $45 thousand/year.
The incremental annualized cost
associated with Option I would be more
than four times the incremental
annualized cost associated with Option
n.
A price increase of about 0.4 percent
would be necessary to offset the cost of
installing as ESP on a 635 Mg/day flat
glass furnace to meet the emission limit
of Option I. A price increase of about 0.1
percent would be necessary to comply
with the emission limit of Option n.
Incremental cumulative capital cost
for the one new 635 Mg/day flat glass
furnace during the 1978-1983 period
associated with Option I would be about
$605 thousand. Compliance with Option
II would require an incremental
cumulative capital cost of about $145
thousand for the same period. Fifth-year
annualized costs for controlling the one
new flat glass furnace to comply with
Option I would be about $190 thousand.
To meet the Option II emissions limit,
fifth-year annualized costs would be
about $45 thousand.
A summary of incremental impacts
associated with Option I and Option II
is shown in Table V. Air impacts.
expressed in Mg/year of particulate
matter emissions reduced, would
approximate the quantity of particulate
matter collected and disposed of as
solid waste.
Tabto V.—Summtrr of tncftmanlfl triplet*
Associated With Regutttory Options
Enwgy* Economic*
FtagUatory
. option:
•20 Nan*
280 Nora
-0.4
-0.1
•Mg/Yr.raducBd
•Barrel, of oU/Aiy.
.Consideration of the beneficial impact
on national particulate emissions, the
lack of water pollution impact, the small
potential for adverse solid waste impact.
the lack of energy impact, the
reasonableness of cost impacts, and the
general availability of demonstrated
emission control technology leads to the
selection of the Option I as the basis for
standards for glass melting furnaces in
the flat glass sector.
Summary

If uncontrolled, total particulate
emissions from the 45 new glass melting
furnaces projected to come on-stream
between 1978 and 1983 would be about
5,200 Mg/year (5,732 ton/year).
Compared to a typical SIP regulation,
Option I would reduce particulate
emissions by an additional 1.100 Mg/
year (1,213 ton/year).
Ambient dispersion modeling
indicates that the annual maximum
ground-level particulate concentrations
near uncontrolled glass melting furnaces.
would be 2 jig/m* or less. Both a typical
SIP regulation and the Option I emission
limits would reduce the annual
maximum ground-level particulate
concentrations to under 1 pg/m.The 24-
maximuun ground-level particulate
concentrations near uncontrolled glass
melting furnaces would be less than 30
Hg/ms, with a median concentration of
about 11 fig/m'. Under a typical SIP
regulation these concentrations would
be reduced to 5 pg/m*or less. Control to
the Option I emission limits would
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reduce the 24-hour maximum ground-
level concentrations near glass melting
furnaces to about 2 pg/m* or less.
The glass manufacturing process has
minimal water pollution potential.
Complying with a standard based on
Option I would have a negligible water
pollution impact, because control
systems installed to meet Option I
would not discharge waste water
streams.
The amounts of solid waste generated
in the control of particulates from glass
melting furnaces would approximate the
amount of paniculate removed from
exhaust gases. Compliance with a
typical SIP regulation would produce
3,700 Mg (4,080 tons) of solid waste per
year. Meeting the Option I emission
limits would generate an additional
1,100 Mg/year (1,213 ton/year). Either
recycling or landfilling would present
minimal adverse environmental impact.
Totally recycling the collected solids
would have no adverse impact.
Landfilling operations must meet State
regulations, and therefore this disposal
method would have limited potential for
adverse environmental impact.
Implementing Option I would require
about 1.6 million kWh of electricity to
power the emission control equipment
installed above the requirements for
implementing a typical SIP regulation.
To meet this power requirement electric
utilities would require about 950 barrels
of oil/year, or about 3 barrels/day. The
energy that would be required to
operate emission reduction sytems to
meet a standard based on the Option I
limits would be 2 percent or less of the
total energy used in glass production.
Incremental cumulative capital costs
• to the glass manufacturing industry for
controlling emissions from new glass
melting furnaces projected to come on-
stream during the 1978-1983 period to
comply with a standard based on the
Option I emission limits would be about
$27.9 million. The fifth-year annuaJized
costs to the glass manufacturing
industry associated with compliance
with the Option I emission limits would
be about $8.4 million. An industry-wide
price increase of about 0.7 percent
would be necessary to offset the costs of
installing control equipment to meet the
emission limits of Option L

Modification, Reconstruction, and Other
Considerations

An exemption from provisions of the
modification section (40 CFR § 80.14) is
proposed for those plants' which convert
to fuel-oil firing, even though particulate
emissions would more than likely be
increased. The primary objective of the
proposed standards is to control
emissions of particulates from glass
melting furnaces. The data and
information supporting the standards
consider essentially only those
emissions arising from the basic melting
process, not those arising from fuel
combustion. It is not the prime purpose
of these standards, therefore, to control
emissions from fuel combustion per se.
Consequently, since emissions from fuel
combustion are small in comparison
with those from the basic melting
process, and a conversion of glass
melting furnaces to firing oil rather than
natural gas will aid in efforts to
conserve natural gas resources, the
standards proposed herein include a
provision exempting fuel switching in
glass melting furnaces from
consideration as a modification. The
• proposed increment in emissions
allowed fuel oil-fired glass melting
furnaces is 15 percent, a small
allowance; however, without this
exemption there would be a large
economic impact on the industry.
An exemption from reconstruction
provisions (40 CFR $ 80.15) is proposed
for the cold refining (rebricking) of the
melter of an existing furnace. Under 40
CFR $ 60.15 the Administrator must be
notified of intent to conduct such a
procedure 60 days in advance of
commencement, and will determine
whether or not the rebricking constitutes
a reconstruction. This rebricking
procedure has been a routine operation
in the glass manufacturing industry and
would not generally be considered an
opportunity to evade the provisions of
the standard by unduly extending the
useful life of an existing glass melting
furnace. Therefore, the exemption of
rebricking from reconstruction provision
has been proposed.
Class melting furnaces fired with
number 2 fuel oil would be expected to
exhibit a 10 percent increase in
particulate emissions over those
produced in gas-fired furnaces since
particulates are formed by the
combustion of oil. Similarly, furnaces
fired with numer 4, 5. or 6 fuel oil would
show a 15 percent increase in
particulate emissions over those
produced in gas-fired furnaces. This
effect of fuel oil on furnace emissions
being recognized, it is proposed that the
emission limits for furnaces fired with
fuel oil be the limits for gas-fired
furnaces multiplied by 1.15. It is
additionally proposed that
simultaneously liquid and gas-fired
furnaces have emission limits based on
an equation, taking into consideraton
the relative proportions of the fuels
being fired.
Selection of Performance Teat Methods

The use of EPA Reference Method 5—
"Determination of Particulate Emissions
from Stationary Sources" (Appendix A,
40 CFR $ 60, Federal Register, December
23,1971) is required to determine
compliance with the mass standards for
particular matter emissions. Emission
test data used in the development of the
proposed standard were obtained either
by the LAAPCD sampling method or by
EPA Method 5. However, results of
performance tests using Method 5
conducted by EPA on existing glass
melting furnaces comprise a major
portion of the data base used in the
development of the proposed standard.
EPA Reference Method 5 has been
shown to provide a respresentative
measurement of particulate matter
emissions. Therefore, it has been
included for determining compliance
with the proposed standards.
Calculations applicable under Method
5 necessitate the use of data obtained
from three other EPA test methods
conducted previous to the performance
of Method 5. Method 1—"Sample and
Velocity Traverse for Stationary
Sources" must be conducted in order to
obtain representative measurements of
pollutant emissions. The average gas
velocity in the exhaust stack is
measured by conducting Method 2—
"Determination of Stack Gas Velocity
and Volumetric Flow Rate (Type S Pilot
Tube)." The analysis of gas composition
is measured by conducting Method 3—
"Gas Analysis for Carbon Dioxide.
Oxygen, Excess Air and Dry Molecular
Weight." These three tests provide data
necessary in Method 5 for.converting
volumetric flow rate to mass flow rate.
In addition, Method 4—"Determination
of Moisture Conent in Stack Gases" is
suggested as an accurate mode of
predetermination of moisture content.
Since the proposed standards are
expressed as mass of emissions per unit
mass of glass pulled, it will be
neccessary to quantify glass pulled in
addition to measuring particulate
emissions. Glass production in Mg shall
be determined by direct measurement or
computed from materials balance data
using good engineering practices. The
materials balance computation may
consist of a process relationship
between feed material input rate and the
glass pull rate. In all materials balance
computations, glass pulled from the
furnace shall include product, cullet, and
any waste glass. The hourly glass pull
rate for a furnace shall be determined
by averaging the glass pull rate over the
time of the performance test
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Selection of Monitoring Requirements
«
To provide a convenient means for
enforcement personnel to ensure that
installed emission control systems
comply with standards of performance
through proper operation and
maintenance, monitoring requirements
are generally included in standards of
performance. For glass melting furnaces
the most straightforward means of
ensuring proper operation and
maintenance is to monitor emissions
released to the atmosphere. EPA has
established opacity monitoring
performance specifications in Appendix
B of 40 CFR § 60 for industrial sources
with well-developed velocity and
temperature profiles.
The best indirect method of
monitoring proper operation and
maintenance of compliance control
equipment is the determination of
exhaust gas opacity limits. Determining
an acceptable exhaust gas opacity limit
is not presently possible because the
relationship between participate
emissions and corresponding opacity
levels was not evaluated for glass
melting furnaces. The data base for the
particulate standards does not include
information on opacity. Also, currently
there are no continuous particulate
monitors operating on glass melting
furnaces; consquently, the data base
necessary for developing an opacity-
emission rate relationship is not
available. Resolution of the sampling
problems, development of performance
standards for continuous particulate
monitors, and obtaining a data base for
developing an opacity-emission rate
relationship would entail a major
development program. For these
reasons, continuous monitoring of
particulate emissions from glass melting
furnaces would not be required by the
proposed standards.

Public Hearing

A public hearing will be held to
discuss these proposed standards in
accordance with Section 307(d)(5) of the
Clean Air Act. Persons wishing to make
oral presentations should contact EPA
at the address given in the ADDRESSES
section of this preamble. Oral
presentations will be limited to IS
minutes each. Any member of the public
may file a written statement with EPA
before, during, or within 30 days after
the hearing. Written statements should
be addressed to the Docket address
given in the ADDRESSES section of this
preamble.
A verbatim transcript of the hearing
and written statements will be available
for public inspection and copying during
normal working hours at EPA's Central
Docket Section in Washington, D.C. (See
ADDRESSES section of this preamble).

Miscellaneous
The docket is an organized and
complete file of all the information
considered by EPA in the development
of this rulemaking. The principal
purposes of the docket are: (1) to allow
interested persons to identify and locate
documents so that they can intelligently
and effectively participate in the
rulemaking process, and (2) to serve as
the record for judicial review. The
docket requirement is discussed in
Section 307(d) of the Clean Air Act.
As prescribed by Section 111 of the
Act, this proposal of standards has been
preceded by the Administrator's
determination that emissions from glass
manufacturing plants contribute to the
endangerment of public health or
welfare, and by publication of this
determination in this issue of the
Federal Register. In accordance with
Section 117 of the Act, publication of
these proposed standards was preceded
by consultation with appropriate
advisory committees, independent
experts, and Federal departments and
agencies. The Administrator will
welcome comments on all aspects of the
proposed regulation, including the
designation.of glass manufacturing
plants as a significant contributor to air
pollution which causes or contributes to
the endangerment of public health or
welfare, economic an'd technological
issues, and on the proposed test method.
It should be noted that 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 emission reduction, any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated." [Section lll(a)(l)]
Although there may be emission
Control technology available that is
capable of reducing emissions below
those levels required to comply with the
standards of performance, this
technology might not be selected as the
basis of standards of performance
because of costs associated with its use.
Accordingly, these standards of
performance should not be viewed as
the ultimate in achievable emissions
control. In fact, the Act requires (or has
the potential for requiring) the
imposition of a more stringent emission
standard in several situations. For
example, applicable costs do not
necessarily play as prominent a role in
determining the "lowest achievable
emission rate" for new or modified
sources locating in nonattainment areas;
i.e.. those areas where statutorily-
mandated health and welfare standards
are being violated. In this respect,
Section 173 of the Act requires that new
or modified sources constructed in an
area which is in violation of the NAAQS
must reduce emissions to the level
which reflects the "lowest achievable
emission rate" (LAER), as defined in
Section 171(3), for such category of
source. The statute defines LAER as that
rate of emissions which reflects:
"(A) the most stringent emission limitation
which is contained in the implementation
plan of any State for such class or category of
source, unless the owner or operator of the
proposed source demonstrates that such
limitations are not achievable; or (B)Jhe most
stringent emission limitation which is
achieved in practice by such class or
category of source, whichever is more
stringent."

In no event can the emission rate exceed
any applicable new source perfomance
standard [Section 171(3)].
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (Part C). These provisions
require that certain sources (referred to
in Section 169(1)) employ "best
available control technology" (as
defined in Section 169(3]) for all
pollutants regulated under the Act. Best
available control technology (BACT)
must be determined on a case-by-case
basis, taking energy, environmental, and
economic impacts and othe^ costs into
account. In no event may the application
of BACT result in emissions of any
pollutants which will exceed the
emissions allowed by an applicable
standard established pursuant to
Section 111 (or 112} of the Act.
In all events, State Implementation
Plans approved or promulgated under
Section 110 of the Act must provide for
the attainment and maintenance of
national ambient air quality standards
(NAAQS) designed to protect public
health and welfare. For this purpose,
SIP's must in some cases require greater
emission reductions than those required
by standards of performance for new
sources.
Finally, States are free under Section
116 of the Act to establish even more
stringent limits than those established
under Section 111 of those necessary to
attain or maintain the NAAQS under
Section 110. Accordingly, new sources
may in some cases be subject to
limitations more stringent than EPA's
standards of performance under Section
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111, and prospective owners and
operators of new sources should be
aware of this possibility in planning for
such facilities.
EPA will review this regulation four
years from the date of promulgation.
This review will include an assessment
of such factors as the need for
integration with other programs, the
existence of alternative methods,
enforceability, and improvements in
emission control technology.
An economic impact assignment has
been prepared as required under Section
317 of the Act and is included in the
Background Information Document.
Dated: May 22,1979.
Douglas M. Costle,
Administrator.

It is proposed to amend Part 60 of
Chapter I, Title 40 of the Code of Federal
Regulations as follows:

Suto(part CC—Standards off
Performance tor
Sec.
80.280 Applicability and designation of
affected faoih'ty.
60.291 Definitions.
60.292 Standards (or partioulate matter.
60.293 Test methods and procedures.
Authority: Sections 111 and 301(a) of the
Clean Air Act. as amended [42 U.S.C. 7411,
7601(a)], and additional authority as noted
below.

§ 80.280 Applicability and designation off
affected facility.
The affected facility to which the
provisions of this subpart apply is each
glass melting furnace within a glass
manufacturing plant.

§$0.281 Boflnltlons.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart A.
(a) "Glass manufacturing plant"
means any plant which produces glass
or glass products.
(b) "Glass melting furnace" means a
unit comprising a refractory vessel in
which raw materials are charged,
melted at high temperature, refined, and
conditioned to produce molten glass.
The unit includes foundations,
superstructure and retaining walls, raw
material charger systems, heat
exchangers, melter cooling system,
exhaust system, refractory brick'work,
fuel supply and electrical boosting
equipment, integral control systems and
instrumentation, and appendages for
conditioning and distributing molten
glass to forcing apparatuses.
(c) "Day pot" means any glass melting
furnace designed to produce less than
1800 kilograms of glass per day.
(d) "All-electric melter" means a glass
melting furnace in which all the heat
required for melting is provided by
electric current from electrodes
submerged in the molten glass, although
some fossil fuel may be charged to the
furnace as raw material.
(e) "Glass" means flat glass; container
glass; pressed and blown glass; and
wool fiberglass.
(f) "Flat glass" means glass made of
soda-lime recipe and produced into
continuous flat sheets and other
products listed in Standard Industrial
Classification 3211 (SIC 3211).
(g) "Container glass" means glass
made of soda-lime recipe, clear or
colored, which is pressed and/or blown
into bottles, jars, ampoules, and other
products listed in SIC 3211.
(h) "Pressed and blown glass" means
glass which is pressed and/or blown,
including textile fiberglass,
noncontinuous process flat glass,
noncontainer glass, and other products
listed in SIC 3229. It is separated into:
(1) Glass of soda-lime recipe; and
(2) Glass of borosilicate, opal, lead
and other recipes.
(i) "Wool fiberglass" means fibrous
glass of random texture, including
fiberglass insulation, and other products
listed in SIC 3288.
(j) "Recipe" means formulation of raw
materials.
(k) "Glass production" means the
weight of glass pilled from a glass
melting furnace.
(1) "Rebricking" means cold
replacement of damaged or worn
refractory parts of the glass melting
furnace. Rebricking includes
replacement of the refractories
comprising the bottom, sidewalls, or
roof of the melting vefssel; replacement
of refractory work in the heat
exchanger; replacement of refractory
portions of the glass conditioning and
distribution system.
(m) "Soda-lime recipe" means raw
material formulation of the following
approximate proportions: 72 percent
silica; 15 percent soda; 10 percent lime
and magnesia; 2 percent alumina; and 1
percent miscellaneous materials.

§ 30.393 Standards to? partlculato maWor.
(a) On or after the date on which the
performance test required to be
conducted by § 60.8 is completed, no
owner or operator of a glass melting
furnace subject to the provisions of this
subpart shall cause to be discharged
into the atmosphere, except as provided
in paragraph (d) of this section:
(1) From any glass melting foraacz,
fired with a gaseous fuel, particulate
matter at emission rates exceeding those
specified in Table CC-1.
(2) From any glass melting furnace.
fired with a liquid fuel, particulate
matter at emission rates exceeding 1.15
times those specified in Table CC-1.
(3) From any glass melting furnace.
simultaneously fired with gaseous and
liquid fuel, particulate matter at
emission rates exceeding those specified
by the following equation:
STD = X[1.15 (Y) + (Z))
where:
STD = Particulate matter emission limit
X = Emission rate specified in Table CC-1
Y = Decimal percent of liquid fuel heating
value to total (gaseous and liquid) fuel
"heating value
tdlojoules
ttilojoules
Z = (1 - Y)
(b) Conversion of a glass melting
furnace to use of liquid fuel shall not be
considered a modification for purposes
of 40 CFR 60.14.
(c) Rebricking and the cost of
msbricking shall not ba considered
reconstruction for the purposes of 40
CFR 60.15.
(d) This subpart shall not apply to day
pots and all-electric metiers.
Tc&to CC-1—emission Kates
GUm category
go)
ot glass
produced
(1) Flat Glass. _ o.ts
(2) Contains Glass „ 10
(3) Pressed and Btocm Glass:
(a) Othsr than coda-Cma rcctpao (i.e..
bofooiScote, opal. bed. and otftsi rcctpas,
mciwSng tsxtfe Bborgtooo) 25
(b) Soda-nmo redpsa ~ .10
(4) Wool FGtsrglQSa „ „ .20
§ 30.393 Tool! esjQtfKttto sntf procedures.
(a) Reference methods in Appendix A
of this part, except as provided under
% SO.e(b), shall be used to determine
compliance with § 60.292 as follows:
(1) Method 5 shall be used to
determine the concentration of
particulate matter and the associated
moisture content.
(2) Method 1 shall be used for sample
and velocity traverses, and
(3) Method 2 shall be used to
determine velocity and volumetric flow
rate.
(4) Method 3 shall be used for gas
analysis.
(b) For Method 5, the sample probe
and filter holder shall be heated to 121 °C
(250°F). The sampling time for each run
V-CC-15
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Federal Register / Vol. 44. No. 117 / Friday. June 15. 1979 / Proposed Rules
shall be at least 60 minutes and the
volume shall be at least 4.25 dscm.
(c) The particulate emission rate, E.
shall be computed as follows:
E = VxC
where:
(1) E is the particulate emission rate
(g/hr).
(2) V is the average volumetric flow
rate (dscm/hr) as found from Method 2:
and
(3) C is the average concentration (g/
dscm) of particulate matter as found
from Method 5.
(d) the rate of glass production. P (kg/
hr) shall be determined by dividing the
weight of glass pulled in kilograms (kg)
from the affected facility during the
performance test by the number of hours
(hr) taken to perform the performance
test. The glass pulled in kilograms shall
be determined by direct measurement or
computed from materials balance by
good engineering practice.
. (e) The furnace emission rate shall be
computed as follows:
R = E/P
where:
(1) R is the furnace emission rate (g/
kg);
(2) E is the particulate emission rate
(g/hr) from (c) above; and
(3) P is the-rate of glass production
(kg/hr) from (d) above.
(Sec. 114 of Clean Air Act as amended (42
U.S.C. 7414).)
|FD Doc. 78-18602 Piled 6-14-79: 8:45 am|
BILLING CODE U60-01-M
V-CC-16
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16560-01 ]

[40CFRPart60]
|FRL 82&-S]

STATIONARY GAS TURBINES
Standards of Performance for New Sta-
tionary Sources Extension of Comment
Period
AGENCY: Environmental Protection
Agency (EPA).

ACTION: Proposed rule.

SUMMARY: The deadline for submittal
of comments on the proposed standards
of performance for stationary gas tur-
bines, which were proposed on October 3,
1977 (42 PR 53782), is being extended
from December 2, 1977. to January 31,
1978.

DATE: Comments must be received on
or before January 31. 1978.
ADDRESSES: Comments should be sub-
mitted (preferably in triplicate) to the
Emission Standards . and Engineering
Division (MD-13), Environmental Pro-
tection Agency, Research Triangle Park,
N.C., attention: Mr. Don R. Goodwin.
All public comments received may be
inspected and copied at the Public In-
formation Reference Unit (EPA Li-
brary) , Room 2922, 401 M Street SW.,
Washington, D.C.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13) Environmental Protection
Agency, Research Triangle Park, N.C.
27711, 819-541-5271.
SUPPLEMENTARY INFORMATION:
On October 3, 1977 (42 FR 53782), the
Environmental Protection Agency pro-
posed standards of performance for the
control of emissions from stationary gas
turbines. The notice of proposal re-
quested public comments on the stand-
ards by December 2, 1977. Due to a delay
in the printing and shipping of the
Standards Support and Environmental
Impact Statement, sufficient copies of the
document have not been available to all
Interested parties in time to allow their
meaningful review and comment by De-
cember 2, 1977. EPA has received a re-
quest from the Industry to extend the
comment period by 60 days through
January 31, 1978. An extension of this
length is Justified since the printing and
shipping delay has resulted in approxi-
mately a seven week delay in processing
requests for the document.
Dated: December 2, 1977.
EDWARD F. TUERX,
Assistant Administrator
for Air and Waste Management.
[PR Doc.77-35293 Piled 12-«-T7;8:45 am]
FEDERAL REGISTER, VOL 42, NO. M7—FRIDAY, DECEMBER f, 1977
V-GG-17
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA 340/1-79-001 a
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Standards of Performance for New Stationary Sources -
As of July 1, 1979 (second Supplemental Information
acket for Updflfci^November 1977 NSPS Regulations
5. REPORT DATE
July 1979
6. PERFORMING ORGANIZATION CODE
cet for
)-Nation.
P/N 3370-3-DD
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS

PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.

68-01-4147, Task 73
12. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agency
Division of Stationary Source Enforcement
Washington, D.C. 20460
13. TYPE OF REPORT AND PERIOD COVERED
Supplement, Jan 79 to July 79
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
DSSE Project Officer: Kirk Foster
16. ABSTRACT
This document contains those pages necessary to update Standards of Performance
for New Stationary Sources - A Compilation, published by the U.S. Environmental
Protection Agency, Division of Stationary Source Enforcement in November 1977
(EPA 340/1-77-015) and the first update published in January 1979 (EPA 340/1-79-
001). It is only an update and should be used in conjunction with the
original compilation.

Included in the update, with complete instructions for filing, are: a new cover,
title page, and table of contents; a new summary table; all revised and new
Standards of Performance; the full text of all revisions and standards
promulgated since January 1979; and all proposed standards or revisions.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Federal Emission Standards
Regulations
Enforcement
New Source Performance
Standards
13B

14D
18. DISTRIBUTION STATEMENT
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
20. SECURITY CLASS (This page)

Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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